0001628280-19-001941.txt : 20190226 0001628280-19-001941.hdr.sgml : 20190226 20190226150630 ACCESSION NUMBER: 0001628280-19-001941 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 95 CONFORMED PERIOD OF REPORT: 20181231 FILED AS OF DATE: 20190226 DATE AS OF CHANGE: 20190226 FILER: COMPANY DATA: COMPANY CONFORMED NAME: Black Stone Minerals, L.P. CENTRAL INDEX KEY: 0001621434 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 471846692 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-37362 FILM NUMBER: 19633043 BUSINESS ADDRESS: STREET 1: 1001 FANNIN STREET, SUITE 2020 CITY: HOUSTON STATE: TX ZIP: 77022 BUSINESS PHONE: (713)658-0647 MAIL ADDRESS: STREET 1: 1001 FANNIN STREET, SUITE 2020 CITY: HOUSTON STATE: TX ZIP: 77022 10-K 1 bsm10-kdocx12312018.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, 2018
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 every Interactive Data File required to be submitted 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 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.
 
Large Accelerated Filer
x
 
 
Accelerated Filer
¨
 
 
Non-Accelerated Filer
¨
 
 
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 $1,501,371,840 on June 29, 2018, the last business day of the registrant’s most recently completed second fiscal quarter, based on a closing price of $18.49 per unit as reported by the New York Stock Exchange on such date. As of February 19, 2019, 108,851,353 common units, 96,328,836 subordinated 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 to obtain access to proved reserves and provide facilities for extracting, treating, gathering, and storing oil and natural gas.
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 horizontally 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 and preparing the hydrocarbons for delivery off the lease, 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. A measurement 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, develop, 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 exists in a gaseous state at atmospheric temperature and pressure. 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. 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.
Production Costs. The production or operational costs incurred while extracting and producing, storing, and transporting oil and/or natural gas. Typically, these costs include wages for workers, facilities lease costs, equipment maintenance, well repairs, 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. Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Proved developed producing reserves. Proved 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 development or operating costs.
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. Standardized measure does not give effect to derivative transactions.
Tight formation. A formation with low permeability that produces oil and/or 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 (WI). 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 the terms on those leases to encourage and accelerate drilling activity, and selectively participating alongside our lessees on a working interest basis. 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% 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 over 60,000 producing wells. Our mineral and royalty interests are located in 41 states in the continental United States, including all of the major onshore producing basins. 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, and the Eagle Ford shale in South Texas. 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 being required to invest 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. 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

PART I




Our Assets
As of December 31, 2018, our total estimated proved oil and natural gas reserves were 69,904 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, 2018, approximately 91.5% were proved developed reserves (approximately 85.7% proved developed producing and 5.8% proved developed non-producing) and approximately 8.5% were proved undeveloped reserves. At December 31, 2018, our estimated proved reserves were 25% oil and 75% natural gas.
The locations of our oil and natural gas properties are presented on the following map. Additional information related to these properties is provided below under "Our Properties" based on major geographical region and by material resource play as denoted on the map below.
bsmmapa01.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, develop, 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 over which we have the most influence. 

3


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.
We may own more than one type of mineral and royalty interest in the same tract of land. For example, where we own an ORRI in a lease on the same tract of land in which we own a mineral interest, our ORRI in that tract will relate to the same gross acres as our mineral interest in that tract. As of December 31, 2018, approximately 28% of our mineral and royalty interests are leased, calculated on a cumulative gross acreage basis for all three types of mineral and royalty interests. We have relied on representations made in the relevant purchase agreements to determine leasing status of recently acquired acreage.
The majority of our producing mineral and royalty interest acreage is pooled with third party acreage to form pooled units. Pooling proportionately reduces our royalty interest in wells drilled in a pooled unit, and it proportionately increases the number of wells in which we have such reduced royalty interest.
Non-Operated Working Interests
We own non-operated working interests related to our mineral interests in various plays across our asset base. The majority of our working interest exposure is in the Haynesville/Bossier play in East Texas where we own non-operated working interests alongside XTO Energy Inc., a subsidiary of Exxon Mobil Corporation, and our other major operator in the area. In 2017, we entered into farmout arrangements (discussed below) for our entire working interest position in that area. We also hold working interests 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.
Beginning in 2017, we have significantly reduced the number of wells in which we participate with a working interest. We generally farmout or sell these participation rights to third parties and often retain some form of non-cost-bearing interest in those wells, such as an overriding royalty interest.
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 31% of our total production volumes during the year ended December 31, 2018. As of December 31, 2018, we owned non-operated working interests in 9,919 gross (354 net) wells.
Our 2019 capital expenditure budget associated with our non-operated working interests is expected to be approximately$10.0 million. The majority of this capital will be spent for workovers on existing wells in which we own a working interest, or for acquiring new leasehold acreage for subsequent farmout (discussed below) in the Haynesville/Bossier play.

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 were drilled over an initial phase, beginning with wells spud after January 1, 2017. Canaan has elected to participate in an additional phase for the lesser of 2 years or until 20 wells have been drilled. After the completion of the second phase, Canaan will have the option to elect for a similar third phase. During the first three phases of the agreement, Canaan commits on a phase-by-phase basis and funds 80% of our drilling and completion costs and is assigned 80% of our working interests in such wells (40% working interest on an 8/8ths basis) as the wells are drilled. 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

4


payout on all wells drilled under the agreement. From the inception of the agreement through December 31, 2018, we have received $80.7 million from Canaan under the agreement and assigned to Canaan working interests in certain wells that have been drilled and completed.
On November 21, 2017, we entered into a farmout agreement with Pivotal Petroleum Partners ("Pivotal"), a portfolio company of Tailwater Capital, LLC. The farmout agreement 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) until November 2025. In wells operated by XTO Energy Inc. in San Augustine County, Texas, Pivotal will earn our remaining working interest not covered by the Canaan Farmout (10% working interest on an 8/8ths basis), 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 San Augustine and Angelina counties, Texas. Initially, Pivotal is obligated to fund the development of up to 80 wells across several development areas and then has options to continue funding our working interest across those areas for the duration of the farmout agreement. Pivotal will fund designated groups of wells. Once Pivotal achieves a specified payout for a designated well group, we will obtain a majority of the original working interest in such well group. From the inception of the agreement through December 31, 2018, we have received $63.0 million from Pivotal under the agreement and assigned to Pivotal working interests in certain wells drilled and completed.
As a result of the farmout agreements with Canaan and Pivotal, we expect net capital requirements associated with non-operated working interests to be minimal in 2019.
PepperJack Prospect
We have cumulatively spent approximately $13.1 million to drill two wells within our PepperJack prospect in Hardin and Liberty counties, Texas. The PepperJack A#1 well targeting the Lower Wilcox formation was drilled during the fourth quarter of 2017 and the first quarter of 2018. The PepperJack B#1 well, also targeting the Lower Wilcox formation, was drilled during the second quarter of 2018 to further delineate the prospect.
Based on the log results, we believe the PepperJack A#1 well is highly prospective and will be completed as a commercially productive well. The PepperJack B#1 well, which was a significant step-out from the PepperJack A#1 well, is not likely to be completed in the near term. Accordingly, we have recorded $6.8 million of costs for the PepperJack B#1 well to the Exploration expense line item of the consolidated statements of operations for the year ended December 31, 2018.
On September 21, 2018, we entered into an exploration agreement with a consortium of private exploration and production companies (the “Development Partners”) to further delineate and develop the PepperJack prospect. As part of the agreement, we assigned 75% of our working interest in the PepperJack A#1 well and acreage in the associated unit to the Development Partners and transferred our status as the operator of record. We received proceeds of $6.4 million for the assignment, which represented a reimbursement for 100% of the drilling costs and associated acreage, proceeds of $1.0 million for an option covering our mineral interests and leases in the PepperJack prospect area, and an overriding royalty interest in the PepperJack prospect area. The Development Partners began completion operations on the PepperJack A#1 well in the fourth quarter of 2018, and we are participating as a 25% non-operated working interest owner.

5



Our Properties
BSM Land Regions
We divide the contiguous United States into major geographical regions that we refer to as "BSM Land Regions". The following is an overview of these regions.
Gulf Coast. The Gulf Coast region consists of the land area along the Gulf of Mexico from South Texas through Florida. This region includes the Western Gulf (onshore), East Texas Basin, Louisiana-Mississippi Salt Basin, and South Florida Basin.
Southwestern US. The Southwestern US region consists of the land area north of the US-Mexico border from north-central Texas westward through Arizona. This region includes the Permian Basin, Fort Worth Basin, Bend Arch, Palo Duro Basin, Dalhart Basin, and Marfa Basin.
Rocky Mountains. The Rocky Mountains region consists of the land area along the Rocky Mountains from Northern New Mexico through Montana and North Dakota. This region includes the Williston Basin, Montana Thrust Belt, Bighorn Basin, Powder River Basin, Greater Green River Basin, Denver-Julesburg Basin, Uinta-Piceance Basin, Park Basin, Paradox Basin, San Juan Basin, and Raton Basin.
Eastern US. The Eastern US region consists of the land area east of the Mississippi River and north of the Gulf Coast region. This region includes the the Michigan Basin, Illinois Basin, Appalachian Basin, and Black Warrior Basin.
Mid-Continent. The Mid-Continent region extends from Oklahoma north through Minnesota. This region includes the Anadarko Basin, Arkoma Basin, Forest City Basin, Cherokee Platform, Marietta Basin, and Ardmore Basin.
Western US. The Western US region consists of the land area west of the Rocky Mountains and Southwestern US regions. This region includes the San Joaquin Basin, Santa Maria Basin, Ventura Basin, Los Angeles Basin, Sacramento Basin, and Eastern Great Basin.
The following tables present information about our mineral and royalty interests and working interests by BSM Land Region:
 
 
 
Acreage as of December 31, 20181
 
 
 
Mineral and Royalty Interests
 
 
 
Working Interests2
BSM Land Region
 
Mineral Interests
 
NPRIs
 
ORRIs
 
 
 
 
 
 
Gross Acres
 
Net %3
 
Gross Acres
 
Net %4
 
Gross Acres
 
Net %4
 
Gross Acres
 
Net Acres
Gulf Coast
 
7,870,800

 
52.3
%
 
615,430

 
3.6
%
 
406,073

 
3.8
%
 
432,483

 
96,033

Southwestern US
 
2,856,033

 
24.9
%
 
1,006,317

 
2.4
%
 
213,637

 
1.8
%
 
60,879

 
17,630

Rocky Mountains
 
2,144,803

 
15.3
%
 
244,839

 
3.4
%
 
1,026,455

 
2.6
%
 
97,932

 
16,720

Eastern US
 
1,657,834

 
47.4
%
 
1,727

 
4.0
%
 
74,892

 
1.4
%
 
13,487

 
1,346

Mid-Continent
 
1,292,995

 
34.2
%
 
39,483

 
3.9
%
 
349,046

 
3.3
%
 
40,622

 
23,860

Western US
 
1,025,167

 
89.1
%
 
333

 
1.8
%
 
30,810

 
3.1
%
 

 

Total
 
16,847,632

 
43.3
%
 
1,908,129

 
3.0
%
 
2,100,913

 
2.8
%
 
645,403

 
155,589

1 
We may own more than one type of interest in the same tract of land. For example, where we have acquired non-operated working interests related to our mineral interests 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 may also be included in the acreage shown for another type of interest. Because of our non-operated working interests, 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.

6


2 
Excludes acreage for which we have incomplete seller records.
3 
Reflects our average ownership interest. Ownership interest is the percentage that our undivided ownership interest in a tract bears to the entire tract. The average ownership interests shown reflect the weighted averages of our ownership interests in all tracts in the BSM Land 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 interests.
4 
Reflects our average royalty interest. 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 BSM Land 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.

 
 
 
 
 
 
 
 
Mineral and Royalty Interests
 
Working Interests
 
 
 
Gross Well Count as of December 31, 20181
 
Average Daily Production (Boe/d) for the Year Ended December 31,
 
Average Daily Production (Boe/d) for the Year Ended December 31,
BSM Land Region
 
MRI Wells2
 
WI Wells
 
2018
 
2017
 
2016
 
2018
 
2017
 
2016
Gulf Coast
 
11,702

 
2,307

 
16,425

 
13,016

 
11,235

 
11,869

 
10,056

 
7,428

Southwestern US
 
26,336

 
1,149

 
5,081

 
2,966

 
1,493

 
278

 
426

 
442

Rocky Mountains
 
12,442

 
2,044

 
7,050

 
4,440

 
4,018

 
934

 
1,157

 
1,714

Eastern US
 
1,988

 
256

 
886

 
1,027

 
995

 
22

 
24

 
25

Mid-Continent
 
7,960

 
4,162

 
2,366

 
2,343

 
2,602

 
1,120

 
1,287

 
1,456

Western US
 
831

 
1

 
270

 
269

 
275

 

 

 

Total
 
61,259

 
9,919

 
32,078

 
24,061

 
20,618

 
14,223

 
12,950

 
11,065

1 
We own both mineral and royalty interests and working interests in 4,192 of the wells shown in each column above.
2 
Refers to mineral and royalty interest wells.

Material Resource Plays
The following is an overview of 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, 2018.
Bakken/Three Forks. The Bakken shale and underlying Three Forks formation are located in the Williston Basin, which covers parts of North Dakota, South Dakota, and Montana in the United States, and Saskatchewan and Manitoba in Canada. The U.S. portion of the Bakken/Three Forks play is within the Rocky Mountains BSM Land Region. We have significant exposure in these plays through our mineral and royalty interests as well as through our working interests.
Haynesville/Bossier. The Haynesville/Bossier formation, located in East Texas and Western Louisiana, is within the Gulf Coast BSM Land Region and is one of the largest producing natural gas formations in the United States. The play’s prospective acreage is evenly divided between East Texas and Western Louisiana, and while we have significant exposure through our mineral and royalty interests and working interests across the entire play, the majority of our acreage is located in East Texas, with a particular concentration in the prolific southern portion of the Shelby Trough in San Augustine, Nacogdoches, and Angelina Counties.
Permian-Midland. The Midland Basin, which is a sub-basin within the Permian Basin, is located in West Texas in the Southwestern US BSM Land Region. It is separated from the Delaware Basin to the west by a carbonate platform called the Central Basin Platform. We refer to the various Permian-aged resource plays within the Midland Basin as the Permian-Midland. These plays include the various members of the Spraberry and Wolfcamp formations. Our interests in the Permian-Midland resource plays are almost exclusively mineral and royalty interests.
Permian-Delaware. The Delaware Basin, which is a sub-basin within the Permian Basin, is located in West Texas and southeastern New Mexico in the Southwestern US BSM Land Region. It is separated from the Midland Basin to the east by a carbonate platform called the Central Basin Platform. We refer to the various Permian-aged resource

7


plays within the Delaware Basin as the Permian-Delaware. These plays include the various members of the Bone Spring, Avalon, and Wolfcamp formations. Our interests in the Permian-Delaware resource plays are almost exclusively mineral and royalty interests.
Eagle Ford. The Eagle Ford shale is located in South Texas within the Gulf Coast BSM Land Region and produces from various depths between 4,000 and 14,000 feet. 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.
The following tables present information about our mineral and royalty interests and non-operated working interests by material resource play.
 
 
 
Acreage as of December 31, 20181
 
 
 
Mineral and Royalty Interests
 
 
 
Working Interests2
Resource Play
 
Mineral Interests
 
NPRIs
 
ORRIs
 
 
 
 
 
 
Gross Acres
 
Net %3
 
Gross Acres
 
Net %4
 
Gross Acres
 
Net %4
 
Gross Acres
 
Net Acres
Bakken/
Three Forks
 
399,691

 
16.9
%
 
39,744

 
1.3
%
 
15,450

 
1.3
%
 
55,480

 
7,300

Haynesville/Bossier
 
393,744

 
62.0
%
 
28,442

 
1.6
%
 
29,488

 
4.8
%
 
231,269

 
53,994

Permian-Midland
 
291,770

 
5.7
%
 
146,786

 
0.6
%
 
107,996

 
0.6
%
 
160

 
4

Permian-Delaware
 
132,897

 
10.5
%
 
37,301

 
0.7
%
 
6,643

 
2.4
%
 
2,522

 
1,171

Eagle Ford
 
67,447

 
14.2
%
 
106,729

 
1.2
%
 
49,572

 
2.2
%
 
1,147

 
87

1 
We may own more than one type of interest in the same tract of land. For example, where we have acquired non-operated working interests related to our mineral interests 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 may also be included in the acreage shown for another type of interest. Because of our non-operated working interests, 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.
2 
Excludes acreage for which we have incomplete seller records.
3 
Reflects our average ownership interest. Ownership interest is the percentage that our undivided ownership interest in a tract bears to the entire tract. The average ownership interests shown reflect the weighted averages of our ownership interests in all tracts in the resource 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 interests.
4 
Reflects our average royalty interest. 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 resource play. 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.

8


 
 
 
 
 
 
 
Mineral and Royalty Interests
 
Working Interests
 
 
 
Gross Well Count as of December 31, 20181
 
Average Daily Production (Boe/d) for the Year Ended December 31,
 
Average Daily Production (Boe/d) for the Year Ended December 31,
Resource Play
 
MRI Wells2
 
WI Wells
 
2018
 
2017
 
2016
 
2018
 
2017
 
2016
Bakken/
Three Forks
 
3,322

 
513

 
5,007

 
2,769

 
2,789

 
693

 
812

 
1,359

Haynesville/Bossier
 
1,013

 
326

 
10,273

 
5,943

 
4,962

 
10,657

 
10,972

 
5,439

Permian-Midland
 
1,287

 
2

 
1,792

 
717

 
150

 
1

 

 
1

Permian-Delaware
 
375

 
20

 
2,207

 
791

 
443

 
65

 
157

 
150

Eagle Ford
 
797

 
27

 
1,920

 
1,768

 
2,210

 
12

 
16

 
76

1 
We own both mineral and royalty interests and working interests in 840 of the wells shown in each column above.
2 
Refers to mineral and royalty interest wells.
Estimated Proved Reserves
Evaluation and Review of Estimated Proved Reserves
The reserves estimates as of December 31, 2018, 2017, and 2016 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, 2018 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 33 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, net revenue interests, and royalty interests in the reserves database against our well ownership system;

9


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.
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, 2018, 2017, and 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.
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 and royalty 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.

10


The following table presents our estimated proved oil and natural gas reserves:
 
As of December 31,
 
20181
 
20172
 
20163
 
(Unaudited)
Estimated proved developed reserves4:
 
 
 
 
 
Oil (MBbls)
17,567

 
17,891

 
18,150

Natural gas (MMcf)
278,233

 
233,017

 
223,057

Total (MBoe)
63,939

 
56,727

 
55,327

Estimated proved undeveloped reserves5:
 
 
 
 
 
Oil (MBbls)

 
8

 
218

Natural gas (MMcf)
35,787

 
67,257

 
47,282

Total (MBoe)
5,965

 
11,218

 
8,098

Estimated proved reserves:
 
 
 
 
 
Oil (MBbls)
17,567

 
17,899

 
18,368

Natural gas (MMcf)
314,020

 
300,274

 
270,339

Total (MBoe)
69,904

 
67,945

 
63,425

Percent proved developed
91.5
%
 
83.5
%
 
87.2
%
1  
Estimates of reserves as of December 31, 2018, 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 2018. For oil volumes, the average WTI spot oil price of $65.56 per barrel is used for estimates of reserves for all the properties as of December 31, 2018. This average price is adjusted for quality, transportation fees, and market differentials.  For natural gas volumes, the average Henry Hub price of $3.10 per MMBTU is used for estimates of reserves for all the properties as of December 31, 2018. 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 $62.81 per barrel for oil and $2.98 per Mcf for natural gas.
2 
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 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. These average prices are 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. 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 $46.59 per barrel for oil and $2.70 per Mcf for natural gas. 
3 
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.
4  
As of December 31, 2018, no proved developed reserves were attributable to noncontrolling interests in our consolidated subsidiaries. Proved developed reserves of 61 and 74 MBoe were attributable to noncontrolling interests in our consolidated subsidiaries as of December 31, 2017 and 2016, respectively.

11


5  
As of December 31, 2018, 2017, and 2016, no proved undeveloped reserves were attributable to noncontrolling interests in our consolidated subsidiaries.
Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary for the same property. In addition, the results of drilling, testing, and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices, and future production rates and costs. Please read Part I, Item 1A. “Risk Factors.”
Additional information regarding our estimated proved reserves can be found in the notes to our consolidated financial statements included elsewhere in this Annual Report and the estimated proved reserve report as of December 31, 2018, which is included as an exhibit to this Annual Report.
Estimated Proved Undeveloped Reserves
As of December 31, 2018, our PUDs comprised 35,787 MMcf of natural gas, for a total of 5,965 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, 2018 (in MBoe):
 
Estimated Proved Undeveloped Reserves
 
(Unaudited)
As of December 31, 2017
11,218

Acquisitions of reserves

Divestiture of reserves

Extensions and discoveries
5,965

Revisions of previous estimates
(1,725
)
Transfers to estimated proved developed
(9,493
)
As of December 31, 2018
5,965

New PUD reserves totaling 5,965 MBoe were added during the year ended December 31, 2018, resulting from development activities in the Haynesville/Bossier play. In 2018 we did not acquire or divest any PUD reserves.
During the year ended December 31, 2018, we had reductions of 1,725 MBoe of PUD reserves, primarily as a result of the plugging and abandonment of two wells due to mechanical issues and converted the remaining 9,493 MBoe of PUD reserves to PDP reserves.
During the year ended December 31, 2018, we incurred $8.6 million relating to the development of locations that were classified as PUDs as of December 31, 2017. Additionally, during the year ended December 31, 2018, we incurred $13.1 million drilling and completing other wells that were not classified as PUDs as of December 31, 2017. There are no estimated future development costs projected for the development of PUD reserves as of December 31, 2018. All our PUD drilling locations as of December 31, 2018 are scheduled to be drilled within five years 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, 2018. As of December 31, 2018, approximately 8.5% of our total proved reserves were classified as PUDs.

12



Oil and Natural Gas Production Prices and Production Costs
Production and Price History
For the year ended December 31, 2018, 29.4% of our production and 55.6% 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 70.6% of our production and 44.4% 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,
 
 
2018
 
2017
 
2016
Production:
 
 

 
 

 
 

Oil and condensate (MBbls)1
 
4,962

 
3,552

 
3,680

Natural gas (MMcf)1
 
71,622

 
59,779

 
47,498

Total (MBoe)
 
16,899

 
13,515

 
11,596

Average daily production (MBoe/d)
 
46.3

 
37.0

 
31.7

Realized Prices2:
 
 

 
 

 
 

Oil and condensate (per Bbl)
 
$
62.53

 
$
47.78

 
$
38.69

Natural gas and natural gas liquids (per Mcf)1
 
$
3.47

 
$
3.19

 
$
2.59

Unit Cost per Boe:
 
 
 
 

 
 

Production costs and ad valorem taxes
 
$
3.81

 
$
3.51

 
$
3.06

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.
The following table sets forth information about our mineral and royalty interest and working interest wells:
 
 
Productive Wells as of December 31, 20181
 
 
Mineral and Royalty Interests
 
Working Interests
Well Type
 
Gross
 
Gross
 
Net
Oil
 
41,557

 
3,909

 
65

Natural Gas
 
19,702

 
6,010

 
289

Total
 
61,259

 
9,919

 
354

1 
We own both mineral and royalty interests and working interests in 4,192 gross wells.



13


Acreage
Mineral and Royalty Interests
The following table sets forth information relating to our acreage for our mineral and royalty interests as of December 31, 2018:
BSM Land Region
 
Developed Acreage1
 
Undeveloped Acreage1
 
Total Acreage1
Gulf Coast
 
744,647

 
8,147,656

 
8,892,303

Southwestern US
 
1,043,364

 
3,032,623

 
4,075,987

Rocky Mountains
 
928,972

 
2,487,125

 
3,416,097

Eastern US
 
82,072

 
1,652,381

 
1,734,453

Mid-Continent
 
656,770

 
1,024,754

 
1,681,524

Western US
 
17,489

 
1,038,821

 
1,056,310

Total
 
3,473,314

 
17,383,360

 
20,856,674

1 
Includes acreage for mineral interests, NPRIs, and ORRIs. We may own more than one type of interest in the same tract of land. For example, where we have acquired non-operated working interests related to our mineral interests 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 may also be included in the acreage shown for another type of interest. Because of our non-operated working interests, 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.
Working Interests
The following table sets forth information relating to our acreage for our non-operated working interests as of December 31, 2018:
 
 
Developed Acreage1
 
Undeveloped Acreage1
 
Total Acreage1
BSM Land Region
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Gulf Coast
 
218,353

 
36,717

 
214,130

 
59,316

 
432,483

 
96,033

Southwestern US
 
15,910

 
11,632

 
44,969

 
5,998

 
60,879

 
17,630

Rocky Mountains
 
85,384

 
15,411

 
12,548

 
1,309

 
97,932

 
16,720

Eastern US
 
13,408

 
1,346

 
79

 

 
13,487

 
1,346

Mid-Continent
 
39,636

 
23,840

 
986

 
20

 
40,622

 
23,860

Western US
 

 

 

 

 

 

Total
 
372,691

 
88,946

 
272,712

 
66,643

 
645,403

 
155,589

1 
We may own more than one type of interest in the same tract of land. For example, where we have acquired non-operated working interests related to our mineral interests 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 may also be included in the acreage shown for another type of interest. Because of our non-operated working interests, 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.




14


The following table lists the net undeveloped acres, the net acres expiring in the years ending December 31, 2019, 2020, and 2021, and, where applicable, the net acres expiring that are subject to extension options:
 
 
2019 Expirations
 
2020 Expirations
 
2021 Expirations
Net Undeveloped
Acreage
 
Net Acreage
without Ext. Opt.
 
Net Acreage
with Ext. Opt.
 
Net Acreage
without Ext. Opt.
 
Net Acreage
with Ext. Opt.
 
Net Acreage
without Ext. Opt.
 
Net Acreage
with Ext. Opt.
66,643

 
3,184

 
501

 
3,829

 
1,234

 
3,267

 
311

Drilling Results for Our Working Interests
The following table sets forth information with respect to the number of wells completed on our properties during the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled, the quantities of reserves found, and the economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return.
 
 
Year Ended December 31,
 
 
2018
 
2017
 
2016
Gross development wells:
 
 

 
 

 
 

Productive
 
6.0

 
23.0

 
47.0

Dry
 

 

 

Total
 
6.0

 
23.0

 
47.0

Net development wells:
 
 

 
 

 
 

Productive
 
2.5

 
6.1

 
4.7

Dry
 

 

 

Total
 
2.5

 
6.1

 
4.7

Gross exploratory wells:
 
 

 
 

 
 

Productive
 

 

 

Dry
 
1.0

 

 

Total
 
1.0

 

 

Net exploratory wells:
 
 

 
 

 
 

Productive
 

 

 

Dry
 
1.0

 

 

Total
 
1.0

 

 

For the years ended December 31, 2017 and 2016 we did not have any productive or dry exploratory wells on a gross or net basis. As of December 31, 2018, we had one gross well in the process of drilling, completing or dewatering, or shut in awaiting infrastructure that is not reflected in the above table.

15



Environmental Matters
Oil and natural gas exploration, development, and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. These laws and regulations have the potential to impact production on our properties, which could materially adversely affect our business and our prospects. Numerous federal, state, and local governmental agencies, such as the U.S. Environmental Protection Agency (“EPA”), issue regulations that often require compliance measures that carry substantial administrative, civil, and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities, and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive, and other protected areas, require action to prevent, or remediate pollution from current or historic operations, such as plugging abandoned wells or closing earthen pits, result in the suspension or revocation of necessary permits, licenses, and authorizations, require that additional pollution controls be installed, and impose substantial liabilities for pollution resulting from operations. The strict, joint, and several liability nature of such laws and regulations could impose liability upon our operators, or us as working interest owners if the operator fails to perform, regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons, or other waste products into the environment. In addition, many environmental statues contain citizen suit provisions, and environmental groups frequently use these provisions to oppose oil and natural gas exploration and development activities and related projects. The long-term trend in environmental regulation has been towards more stringent regulations, and any changes that impact our operators and result in more stringent and costly pollution control or waste handling, storage, transport, disposal, or cleanup requirements could materially adversely affect our business and prospects. Below is a summary of environmental laws applicable to operations on our properties.
Waste Handling
The Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development, and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal, and cleanup of hazardous and non- hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development, and production of oil and natural gas are exempt from regulation as hazardous wastes under RCRA, these wastes typically constitute “solid wastes” that are subject to less stringent non-hazardous waste requirements. However, it is possible that RCRA could be amended or the EPA or state environmental agencies could adopt policies to require oil and natural gas exploration, development, and production wastes to become subject to more stringent waste handling requirements. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and natural gas wastes from regulation as hazardous wastes under RCRA. The consent decree requires EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and natural gas wastes or to sign a determination that revision of the regulations is not necessary. Pursuant to the consent decree, EPA must complete any revisions to RCRA's Subtitle D regulations by 2021. Removal of RCRA’s exemption for exploration and production wastes has the potential to significantly increase waste disposal costs, which in turn will result in increased operating costs and could adversely impact production on our properties. Administrative, civil, and criminal penalties can be imposed for failure to comply with waste handling requirements. Any changes in the laws and regulations could have a material adverse effect on our operators’ capital expenditures and operating expenses, which in turn could affect production from our properties and adversely affect our business and prospects.
Remediation of Hazardous Substances
The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, and analogous state laws generally impose strict, joint, and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility (which can include working interest owners), a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” may be subject to strict and joint and several liability for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and

16



property damage allegedly caused by the hazardous substances released into the environment. Oil and natural gas exploration and production activities on our properties use materials that, if released, would be subject to CERCLA and comparable state statutes. Therefore, governmental agencies or third parties may seek to hold our operators, or us as working interest owners if the operator fails to perform, responsible under CERCLA and comparable state statutes for all or part of the costs to clean-up sites at which these “hazardous substances” have been released.
Water Discharges
 The Federal Water Pollution Control Act of 1972, also known as the “Clean Water Act” (“CWA”), the Safe Drinking Water Act (“SDWA”), the Oil Pollution Act (“OPA”), and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. In June 2015, the EPA and the U.S. Army Corps of Engineers (the “Corps”) published a final rule attempting to clarify the federal jurisdictional reach over waters of the United States ("WOTUS"). Several legal challenges to the rule followed, along with attempts to stay implementation following the change in presidential administration. Currently, the WOTUS rule is active in 26 states and enjoined in 24 states. Future implementation of the June 2015 rule is uncertain at this time. To the extent this rule or a revised rule expands the scope of the CWA’s jurisdiction, operations on our properties could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas in connection with any expansion activities. In addition, spill prevention, control, and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture, or leak. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges.     
The OPA is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint, and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil into surface waters.
In addition, while the SDWA, generally excludes hydraulic fracturing from the definition of underground injection, it does not exclude hydraulic fracturing involving the use of diesel fuels. In 2014, the EPA published draft permitting guidance governing hydraulic fracturing with diesel fuels. In addition, the SDWA grants the EPA broad authority to take action to protect public health when an underground source of drinking water is threatened with pollution that presents an imminent and substantial endangerment to humans, which could result in orders prohibiting or limiting the operations of oil and natural gas production facilities. Moreover, the SDWA also regulates saltwater disposal wells under the Underground Injection Control Program. Recent concerns related to the operation of saltwater disposal wells and induced seismicity have led some states to impose limits on the total volume of produced water such wells can dispose of, order disposal wells to cease operations, or limited the construction of new wells. These seismic events have also resulted in environmental groups and local residents filing lawsuits against operators in areas where the events occur seeking damages and injunctions limiting or prohibiting saltwater disposal well construction activities and operations. A lack of saltwater disposal wells in production areas could result in increased disposal costs for our operators if they are forced to transport produced water by truck, pipeline, or other method over long distances, or force them to curtail operations.
Noncompliance with the Clean Water Act, SDWA, or the OPA may result in substantial administrative, civil, and criminal penalties, as well as injunctive obligations, all of which could affect production from our properties and adversely affect our business and prospects.
Air Emissions
The federal Clean Air Act and comparable state laws and regulations regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, in August 2012, the EPA adopted new regulations under the Clean Air Act that established new

17



emission control requirements for oil and natural gas production and processing operations. In addition, in October 2015, the EPA lowered the National Ambient Air Quality Standard, (“NAAQS”) for ozone from 75 to 70 parts per billion for both the 8- hour primary and secondary standards, and the agency completed attainment/non-attainment designations in July 2018. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit the ability of our operators to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. Separately, in June 2016, the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and natural gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements. These laws and regulations may increase the costs of compliance for oil and natural gas producers and impact production on our properties, and federal and state regulatory agencies can impose administrative, civil, and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. Moreover, obtaining or renewing permits has the potential to delay the development of oil and natural gas exploration and development projects. All of these factors could impact production on our properties and adversely affect our business and results of operations.
Climate Change
In response to findings that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, require preconstruction and operating permits for certain large stationary sources. Facilities required to obtain preconstruction permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established on a case-by-case basis. These EPA rulemakings could adversely affect operations on our properties and restrict or delay the ability of our operators to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis, which include gathering and boosting facilities as well as GHG emissions from completions and workovers of hydraulically fractured wells. Also, in June 2016, the EPA finalized rules that establish new air emission controls for methane emissions from certain new, modified, or reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission, and storage activities, otherwise known as Subpart OOOOa. Following the change in administration, there have been attempts to modify these regulations, and litigation is ongoing. As a result, we cannot predict the scope of any final methane regulatory requirements or the cost to comply with such requirements with any certainty. Several states, including Colorado, where we hold interests, have also adopted rules to control and minimize methane emissions from the production of oil and natural gas. Moreover, in response to public concerns regarding methane emissions, many operators have recently voluntarily agreed to implement methane controls with respect to their operations. State and existing federal methane rules have substantial similarities with respect to pollution control equipment and leak detection and repair (“LDAR”) requirements. These rules could result in increased compliance costs for operations on our properties and require compliance expenditures to purchase pollution control equipment and hire additional personnel to assist with complying with LDAR requirements, such as increased frequency of inspections and repairs for certain processes and equipment. Consequently, these and other regulations related to controlling GHG emissions could have an adverse impact on production on our properties, our business, and results of operations.
While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of federal climate legislation, a number of state and regional GHG cap and trade programs have emerged. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our operators’ equipment and operations could require them to incur costs to reduce emissions of GHGs associated with their operations. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas produced from our properties and lower the value of our reserves. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states, as well as state and local climate change initiatives, could adversely affect the oil and natural gas industry, and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business. Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for energy companies, which has resulted in certain financial institutions, funds, and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult for operators on our properties to secure funding for exploration and production activities. Additionally, activist shareholders have introduced proposals that may seek to force companies to adopt aggressive emission reduction targets or restrict more carbon-intensive activities. While we cannot predict the outcomes of such proposals, they could ultimately make it more difficult for operators to engage in exploration and production activities.

18



Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and gas will continue to represent a substantial percentage of global energy use over that time. Exploration and production activities are capital intensive, and capital constraints of our operators could have a material adverse impact on production from our properties. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts, and other extreme climatic events; if any of these effects were to occur, they could have a material adverse effect on our properties and operations.
Hydraulic Fracturing
Our operators engage in hydraulic fracturing. Hydraulic fracturing is a common practice that is used to stimulate production of hydrocarbons from tight formations, including shales. The process involves the injection of water, sand, and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and natural gas commissions, but recently the EPA and other federal agencies have asserted jurisdiction over certain aspects of hydraulic fracturing. For example, the EPA issued effluent limitation guidelines in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants.
In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals, or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. The EPA has not proposed to take any action in response to the report’s findings.
Several states where we own interests in oil and gas producing properties, including Colorado, North Dakota, Louisiana, Oklahoma, and Texas, have adopted regulations that could restrict or prohibit hydraulic fracturing in certain circumstances or require the disclosure of the composition of hydraulic-fracturing fluids. For example, in Texas, the Texas Railroad Commission (“RRC”) published a final rule in October 2014 governing permitting or re-permitting of disposal wells that requires, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections, and structure maps relating to the disposal area in question.  If the permittee or an applicant of a disposal well permit fails to demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the RRC may deny, modify, suspend, or terminate the permit application or existing operating permit for that well. Similarly, Oklahoma has imposed strict limits on the operation of disposal wells in areas with increased instances of induced seismic events. These existing or any new legal requirements establishing seismic permitting requirements or similar restrictions on the construction or operation of disposal wells for the injection of produced water likely will result in added costs to comply and affect our operators’ rate of production, which in turn could have a material adverse effect on our results of operations and financial position. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general or hydraulic fracturing in particular. For example, from time to time in Colorado there have been various ballot initiatives to impose strict setback requirements on oil and gas activities from certain occupied structures and environmental sensitive areas, which could have potentially prohibited future production in areas in which we own interests. We cannot predict what additional state or local requirements may be imposed in the future on oil and gas operations in the states in which we own interests. In the event state, local, or municipal legal restrictions are adopted in areas where our operators conduct operations, our operators may incur substantial costs to comply with these requirements, which may be significant in nature, experience delays, or curtailment in the pursuit of exploration, development, or production activities and perhaps even be precluded from the drilling of wells.

19



There has been increasing public controversy regarding hydraulic fracturing with regard to increased risks of induced seismicity, the use of fracturing fluids, impacts on drinking water supplies, use of water, and the potential for impacts to surface water, groundwater, and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic-fracturing practices. If new laws or regulations are adopted that significantly restrict hydraulic fracturing, those laws could make it more difficult or costly for our operators to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing is further regulated at the federal or state level, fracturing activities on our properties could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements, and also to attendant permitting delays and potential increases in costs. Legislative changes could cause operators to incur substantial compliance costs. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.
Occupational Safety and Health Act
The Occupational Safety and Health Act (“OSHA”) and comparable state laws and regulations govern the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard, the Emergency Planning and Community Right to Know Act and implementing regulations, and similar state statutes and regulations require that information be maintained about hazardous materials used or produced in operations on our properties and that this information be provided to employees, state and local government authorities, and citizens.
Endangered Species
The Endangered Species Act (“ESA”) and analogous state laws restrict activities that may affect endangered or threatened species or their habitats. Pursuant to a settlement with environmental groups, the U.S. Fish and Wildlife Service (“USFWS”) was required to determine whether over 250 species required listing as threatened or endangered under the ESA. USFWS has not yet completed its review, but the potential remains for new species to be listed under the ESA. Some of our properties may be located in areas that are or may be designated as habitats for endangered or threatened species, and previously unprotected species may later be designated as threatened or endangered in areas where we hold interests. For example, recently, there have been renewed calls to review protections currently in place for the Dunes Sagebrush Lizard, whose habitat includes portions of the Permian Basin, and to reconsider listing the species under the ESA. Likewise, there have been calls to review protections in place for the Greater Sage Grouse, which can be found across a large swath of the northwestern United States in oil and gas producing states. The listing of either of these species, or any others, in areas where we hold interests could cause our operators to incur increased costs arising from species protection measures, delay the completion of exploration and production activities, and/or result in limitations on operating activities that could have an adverse impact on our business.
Title to Properties
Prior to completing an acquisition of oil and natural gas properties, we perform title reviews on high-value tracts. Our title reviews are meant to confirm quantum of oil and natural gas properties being acquired, lease status, and royalties as well as encumbrances and other related burdens. Depending on the materiality of properties, we may obtain a title opinion if we believe additional title due diligence is necessary. As a result, title examinations have been obtained on a significant portion of our properties. After an acquisition, we review the assignments from the seller for scrivener’s and other errors and execute and record corrective assignments as necessary.
In addition to our initial title work, our operators conduct a thorough title examination prior to leasing and drilling a well. Should our operators’ title work uncover any title defects, either we or our operators will perform curative work with respect to such defects. Our operators generally will not commence drilling operations on a property until any material title defects on such property have been cured.
We believe that the title to our assets is satisfactory in all material respects. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions, and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens, and encumbrances will materially detract from the value of these properties or from our interest in these properties or materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects.

20



Marketing and Major Customers
If we were to lose a significant customer, such loss could impact revenue derived from our mineral and royalty interest or working interest properties. The loss of any single lessee is mitigated by our diversified customer base.  The following table indicates our significant customers that accounted for 10% or more of our total revenues for the periods indicated:
 
 
 
Year Ended December 31,
 
 
2018
 
2017
 
2016
XTO Energy Inc.
 
15.4%
 
20.8%
 
11.0%
Competition
The oil and natural gas business is highly competitive in the exploration for and acquisition of reserves, the acquisition of minerals and oil and natural gas leases, and personnel required to find and produce reserves. Many companies not only explore for and produce oil and natural gas, but also conduct midstream and refining operations and market petroleum and other products on a regional, national, or worldwide basis. Certain of our competitors may possess financial or other resources substantially larger than we possess. Our ability to acquire additional minerals and properties and to discover reserves in the future will be dependent upon our ability to identify and evaluate suitable acquisition prospects and to consummate transactions in a highly competitive environment. Oil and natural gas products compete with other sources of energy available to customers, primarily based on price. These alternate sources of energy include coal, nuclear, solar, and wind. Changes in the availability or price of oil and natural gas or other sources of energy, as well as business conditions, conservation, legislation, regulations, and the ability to convert to alternate fuels and other sources of energy may affect the demand for oil and natural gas. 
Seasonal Nature of Business
Weather conditions affect the demand for, and prices of, natural gas and can also delay drilling activities, disrupting our overall business plans. Demand for natural gas is typically higher during the winter, resulting in higher natural gas prices for our natural gas production during our first and fourth quarters. Certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal weather conditions can limit drilling and producing activities and other oil and natural gas operations in a portion of our operating areas. Due to these seasonal fluctuations, our results of operations for individual quarterly periods may not be indicative of the results that we may realize on an annual basis.
Employees
We are managed and operated by the board of directors and executive officers of our general partner. All of our employees, including our executive officers, are employees of Black Stone Natural Resources Management Company (“Black Stone Management”). As of December 31, 2018, Black Stone Management had 116 full-time employees. None of Black Stone Management’s employees are represented by labor unions or covered by any collective bargaining agreements.
Facilities
Our principal office location is in Houston, Texas and consists of 55,862 square feet of leased space.

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ITEM 1A.      Risk Factors
Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business.  If any of the following risks were to occur, our financial condition, results of operations, cash flows, and ability to make distributions could be materially adversely affected. In that case, we might not be able to make distributions on our common units, the trading price of our common units could decline, and holders of our units could lose all or part of their investment.
Risks Related to Our Business
We may not generate sufficient cash from operations after establishment of cash reserves to pay the minimum quarterly distribution on our common and subordinated units. If we make distributions, the holders of our Series B cumulative convertible preferred units have priority with respect to rights to share in those distributions over our common and subordinated unitholders for so long as our Series B cumulative convertible preferred units are outstanding.
We may not generate sufficient cash from operations each quarter to pay the full minimum quarterly distribution to our common and subordinated unitholders. Our Series B cumulative convertible preferred unitholders have priority with respect to rights to share in distributions over our common and subordinated unitholders for so long as our Series B cumulative convertible preferred units are outstanding. Furthermore, our partnership agreement does not require us to pay distributions to our common and subordinated unitholders on a quarterly basis or otherwise. The amount of cash to be distributed each quarter will be determined by the board of directors of our general partner.
The amount of cash we are able to distribute each quarter principally depends upon the amount of revenues we generate, which are largely dependent upon the prices that our operators realize from the sale of oil and natural gas. The actual amount of cash we are able to distribute each quarter will be reduced by principal and interest payments on our outstanding debt, working-capital requirements, and other cash needs. In addition, we may restrict distributions, in whole or in part, to fund replacement capital expenditures, acquisitions, and participation in working interests. If over the long term we do not retain cash for replacement capital expenditures in amounts necessary to maintain our asset base, a portion of future distributions will represent distribution of our assets and the value of our common units could be adversely affected. Withholding cash for our capital expenditures may have an adverse impact on the cash distributions in the quarter in which amounts are withheld.
For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read Part II, Item 5. “Market for Registrant’s Common Equity, Related Unitholder Matters, and Issuer Purchases of Equity Securities — Cash Distribution Policy.”
The amount of cash we distribute to holders of our units depends primarily on our cash generated from operations and not our profitability, which may prevent us from making cash distributions during periods when we record net income.
The amount of cash we distribute depends primarily upon our cash generated from operations and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods in which we record net losses for financial accounting purposes and may be unable to make cash distributions during periods in which we record net income.
The volatility of oil and natural gas prices due to factors beyond our control greatly affects our financial condition, results of operations, and cash distributions to unitholders.
Our revenues, operating results, cash distributions to unitholders, and the carrying value of our oil and natural gas properties depend significantly upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty, and a variety of additional factors that are beyond our control, including:
the domestic and foreign supply of and demand for oil and natural gas;
market expectations about future prices of oil and natural gas;
the level of global oil and natural gas exploration and production;
the cost of exploring for, developing, producing, and delivering oil and natural gas;
the price and quantity of foreign imports and exports of oil and natural gas;

22


political and economic conditions in oil producing regions, including the Middle East, Africa, South America, and Russia;
the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
trading in oil and natural gas derivative contracts;
the level of consumer product demand;
weather conditions and natural disasters;
technological advances affecting energy consumption;
domestic and foreign governmental regulations and taxes;
the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East;
the proximity, cost, availability, and capacity of oil and natural gas pipelines and other transportation facilities;
the price and availability of alternative fuels; and
overall domestic and global economic conditions.
These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. The table below demonstrates such volatility for the periods presented.
 
 
Year Ended December 31, 2018
 
During the Five Years Prior to 2019
 
As of December 31,
 
 
High
 
Low
 
High2
 
Low3
 
2018
 
2017
 
2016
WTI spot crude oil ($/Bbl)1
 
$
77.41

 
$
44.48

 
$
107.95

 
$
26.19

 
$
45.15

 
$
60.46

 
$
53.75

Henry Hub spot natural gas ($/MMBtu)1
 
$
6.24

 
$
2.49

 
$
8.15

 
$
1.49

 
$
3.25

 
$
3.69

 
$
3.71

1  
Source: EIA
2  
High prices for WTI and Henry Hub were in 2014
3  
Low prices for WTI and Henry Hub were in 2016
Any prolonged substantial decline in the price of oil and natural gas will likely have a material adverse effect on our financial condition, results of operations, and cash distributions to unitholders. We may use various derivative instruments in connection with anticipated oil and natural gas sales to minimize the impact of commodity price fluctuations. However, we cannot always hedge the entire exposure of our operations from commodity price volatility. To the extent we do not hedge against commodity price volatility, or our hedges are not effective, our results of operations and financial position may be diminished.
In addition, lower oil and natural gas prices may also reduce the amount of oil and natural gas that can be produced economically by our operators. This scenario may result in our having to make substantial downward adjustments to our estimated proved reserves, which could negatively impact our borrowing base and our ability to fund our operations. If this occurs or if production estimates change or exploration or development results deteriorate, successful efforts method of accounting principles may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. Our operators could also determine during periods of low commodity prices to shut in or curtail production from wells on our properties. In addition, they could determine during periods of low commodity prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, they may abandon any well if they reasonably believe that the well can no longer produce oil or natural gas in commercially paying quantities.  
For the foreseeable future, oil prices are expected to trade in a lower range compared to recent historical highs. Approximately 56% of our 2018 oil and natural gas revenues were derived from oil and condensate sales. Any additional decreases in prices of oil may adversely affect our cash generated from operations, results of operations, financial position, and our ability to pay the minimum quarterly distribution on all our outstanding common and subordinated units, perhaps materially.
The spot WTI market price at Cushing, Oklahoma has declined from $98.17 per Bbl on December 31, 2013 to $45.15 per Bbl on December 31, 2018. The reduction in price has been caused by many factors, including substantial increases in U.S. oil

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production from unconventional (shale) reservoirs, with limited increases in demand. If prices for oil are depressed for an extended period of time or there are future declines, we may be required to write down the value of our oil and natural gas properties in addition to impairments taken during 2015 and 2016, and some of our undeveloped locations may no longer be economically viable. In addition, sustained low prices for oil may negatively impact the value of our estimated proved reserves and the amount that we are allowed to borrow under our bank credit facility and reduce the amounts of cash we would otherwise have available to pay expenses, fund capital expenditures, make distributions to our unitholders, and service our indebtedness.
For the forseeable future, natural gas prices are expected to trade in a range lower than historical highs. Approximately 44% of our 2018 oil and natural gas revenues were derived from natural gas and natural gas liquids sales. Any future decreases in prices of natural gas may adversely affect our cash generated from operations, results of operations, financial position, and our ability to pay the minimum quarterly distribution on all our outstanding common and subordinated units, perhaps materially.
During the ten years prior to 2018, natural gas prices at Henry Hub have ranged from a high of $13.31 per MMBtu in 2008 to a low of $1.49 per MMBtu in 2016. On December 31, 2018, the Henry Hub spot market price of natural gas was $3.25 per MMBtu. The reduction in prices has been caused by many factors, including increases in natural gas production from unconventional (shale) reservoirs, without an offsetting increase in demand. The expected increase in natural gas production, based on reports from the EIA, could cause the prices for natural gas to remain at current levels or fall to lower levels. If prices for natural gas are depressed for an extended period of time or there are future declines, we may be required to further write down the value of our oil and natural gas properties in addition to impairments taken during 2015 and 2016, and some of our undeveloped locations may no longer be economically viable. In addition, sustained low prices for natural gas may negatively impact the value of our estimated proved reserves and the amount that we are allowed to borrow under our bank credit facility and reduce the amounts of cash we would otherwise have available to pay expenses, make distributions to our unitholders, and service our indebtedness.
Our failure to successfully identify, complete, and integrate acquisitions could adversely affect our growth, results of operations, and cash distributions to unitholders.
We depend partly on acquisitions to grow our reserves, production, and cash generated from operations. Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic data, and other information, the results of which are often inconclusive and subject to various interpretations. The successful acquisition of properties requires an assessment of several factors, including:
recoverable reserves;
future oil and natural gas prices and their applicable differentials;
development plans;
operating costs; and
potential environmental and other liabilities.
The accuracy of these assessments is inherently uncertain and we may not be able to identify attractive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections may not always be performed on every well, if applicable, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.  
There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain financing. In addition, compliance with regulatory requirements may impose substantial additional obligations on our operators, causing them to expend additional time and resources in compliance activities, and potentially increase our operators’ exposure to penalties or fines for non-compliance with additional legal requirements. Further, the process of integrating acquired assets may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources.

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No assurance can be given that we will be able to identify suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms, or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully, or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition, results of operations, and cash distributions to unitholders. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our growth, results of operations, and cash distributions to unitholders.
Any acquisitions of additional mineral and royalty interests that we complete will be subject to substantial risks.
Even if we do make acquisitions that we believe will increase our cash generated from operations, these acquisitions may nevertheless result in a decrease in our cash distributions per unit. Any acquisition involves potential risks, including, among other things:
the validity of our assumptions about estimated proved reserves, future production, prices, revenues, capital expenditures, operating expenses, and costs;
a decrease in our liquidity by using a significant portion of our cash generated from operations or borrowing capacity to finance acquisitions;
a significant increase in our interest expense or financial leverage if we incur debt to finance acquisitions;
the assumption of unknown liabilities, losses, or costs for which we are not indemnified or for which any indemnity we receive is inadequate;
mistaken assumptions about the overall cost of equity or debt;
our ability to obtain satisfactory title to the assets we acquire;
an inability to hire, train, or retain qualified personnel to manage and operate our growing business and assets; and
the occurrence of other significant changes, such as impairment of oil and natural gas properties, goodwill or other intangible assets, asset devaluation, or restructuring charges.
We depend on various unaffiliated operators for all exploration, development, and production on the properties underlying our mineral and royalty interests and non-operated working interests. Substantially all our revenue is derived from the sale of oil and natural gas production from producing wells in which we own a royalty interest or a non-operated working interest. A reduction in the expected number of wells to be drilled on our acreage by these operators or the failure of our operators to adequately and efficiently develop and operate our acreage could have an adverse effect on our results of operations.
Our assets consist of mineral and royalty interests and non-operated working interests. For the year ended December 31, 2018, we received revenue from over 1,000 operators. The failure of our operators to adequately or efficiently perform operations or an operator’s failure to act in ways that are in our best interests could reduce production and revenues. Our operators are often not obligated to undertake any development activities other than those required to maintain their leases on our acreage. In the absence of a specific contractual obligation, any development and production activities will be subject to their reasonable discretion. Our operators could determine to drill and complete fewer wells on our acreage than is currently expected. The success and timing of drilling and development activities on our properties, and whether the operators elect to drill any additional wells on our acreage, depends on a number of factors largely outside of our control, including:
the capital costs required for drilling activities by our operators, which could be significantly more than anticipated;
the ability of our operators to access capital;
prevailing commodity prices;
the availability of suitable drilling equipment, production and transportation infrastructure, and qualified operating personnel;
the operators’ expertise, operating efficiency, and financial resources;
approval of other participants in drilling wells;
the operators’ expected return on investment in wells drilled on our acreage as compared to opportunities in other areas;  
the selection of technology;
the selection of counterparties for the marketing and sale of production; and
the rate of production of the reserves.

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The operators may elect not to undertake development activities, or may undertake these activities in an unanticipated fashion, which may result in significant fluctuations in our results of operations and cash distributions to our unitholders. Sustained reductions in production by the operators on our properties may also adversely affect our results of operations and cash distributions to unitholders.
If operators slow or cease activity in the Shelby Trough area, our results of operations could be adversely affected.
In 2018, we generated 21.4% of our revenues and 36.7% of our production from two operators in the Shelby Trough area of the Haynesville play in East Texas, where we own a concentrated, relatively high-interest royalty position; we expect that these operators will continue to conduct significant operations in this area for the foreseeable future in accordance with contractual arrangements. Geographic and operator concentration heightens the effect of operational risks, including:
operators’ diversion of drilling capital to other areas, where our royalty interest is less meaningful or nonexistent;
adverse changes to the operators’ financial positions;
unanticipated geographic or environmental constraints in the Shelby Trough
If any of these risks are realized and production is not replaced by another operator in this area or another area, production may decrease, reducing cash generated from operations and cash available for distribution.
We may experience delays in the payment of royalties and be unable to replace operators that do not make required royalty payments, and we may not be able to terminate our leases with defaulting lessees if any of the operators on those leases declare bankruptcy.
A failure on the part of the operators to make royalty payments gives us the right to terminate the lease, repossess the property, and enforce payment obligations under the lease. If we repossessed any of our properties, we would seek a replacement operator. However, we might not be able to find a replacement operator and, if we did, we might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, the outgoing operator could be subject to a proceeding under title 11 of the United States Code (the “Bankruptcy Code”), in which case our right to enforce or terminate the lease for any defaults, including non-payment, may be substantially delayed or otherwise impaired. In general, in a proceeding under the Bankruptcy Code, the bankrupt operator would have a substantial period of time to decide whether to ultimately reject or assume the lease, which could prevent the execution of a new lease or the assignment of the existing lease to another operator. In the event that the operator rejected the lease, our ability to collect amounts owed would be substantially delayed, and our ultimate recovery may be only a fraction of the amount owed or nothing. In addition, if we are able to enter into a new lease with a new operator, the replacement operator may not achieve the same levels of production or sell oil or natural gas at the same price as the operator it replaced.
Acquisitions, funding our non-operated working interests, and our operators’ development activities of our leases will require substantial capital, and we and our operators may be unable to obtain needed capital or financing on satisfactory terms or at all.
The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in connection with the acquisition of mineral and royalty interests and participation in our non-operated working interests. To date, we have financed capital expenditures primarily with funding from cash generated by operations, limited borrowings under our credit facility, executed farmout agreements, and the issuance of equity securities.
In the future, we may restrict distributions to fund acquisitions and participation in our working interests but eventually we may need capital in excess of the amounts we retain in our business or borrow under our credit facility. We cannot assure you that we will be able to access external capital on terms favorable to us or at all. If we are unable to fund our capital requirements, we may be unable to complete acquisitions, take advantage of business opportunities, or respond to competitive pressures, any of which could have a material adverse effect on our results of operation and cash distributions to unitholders.
Most of our operators are also dependent on the availability of external debt and equity financing sources to maintain their drilling programs. If those financing sources are not available to the operators on favorable terms or at all, then we expect the development of our properties to be adversely affected. If the development of our properties is adversely affected, then revenues from our mineral and royalty interests and non-operated working interests may decline.

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Unless we replace the oil and natural gas produced from our properties, our cash generated from operations and our ability to make distributions to our common and subordinated unitholders could be adversely affected.
Producing oil and natural gas wells are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and our operators’ production thereof and our cash generated from operations and ability to make distributions are highly dependent on the successful development and exploitation of our current reserves. The production decline rates of our properties may be significantly higher than currently estimated if the wells on our properties do not produce as expected. We may also not be able to find, acquire, or develop additional reserves to replace the current and future production of our properties at economically acceptable terms, which would adversely affect our business, financial condition, results of operations, and cash distributions to our common and subordinated unitholders.
We either have little or no control over the timing of future drilling with respect to our mineral and royalty interests and non-operated working interests.
Our proved undeveloped reserves may not be developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations, and the decision to pursue development of a proved undeveloped drilling location will be made by the operator and not by us. The reserve data included in the reserve report of our engineer assume that substantial capital expenditures are required to develop the reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled, or that the results of the development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop our reserves, or decreases in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our undeveloped reserves as unproved reserves.  
Project areas on our properties, which are in various stages of development, may not yield oil or natural gas in commercially viable quantities.
Project areas on our properties are in various stages of development, ranging from project areas with current drilling or production activity to project areas that have limited drilling or production history. If the wells in the process of being completed do not produce sufficient revenues or if dry holes are drilled, our financial condition, results of operations, and cash distributions to unitholders may be adversely affected.
Our operators’ identified potential drilling locations are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
The ability of our operators to drill and develop identified potential drilling locations depends on a number of uncertainties, including the availability of capital, construction of infrastructure, inclement weather, regulatory changes and approvals, oil and natural gas prices, costs, drilling results, and the availability of water. Further, our operators’ identified potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation. The use of technologies and the study of producing fields in the same area will not enable our operators to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, our operators may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If our operators drill additional wells that they identify as dry holes in current and future drilling locations, their drilling success rate may decline and materially harm their business as well as ours.
We cannot assure you that the analogies our operators draw from available data from the wells on our acreage, more fully explored locations, or producing fields will be applicable to their drilling locations. Further, initial production rates reported by our or other operators in the areas in which our reserves are located may not be indicative of future or long-term production rates. Because of these uncertainties, we do not know if the potential drilling locations our operators have identified will ever be drilled or if our operators will be able to produce oil or natural gas from these or any other potential drilling locations. As such, the actual drilling activities of our operators may materially differ from those presently identified, which could adversely affect our business, results of operation, and cash distributions to unitholders.

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The unavailability, high cost, or shortages of rigs, equipment, raw materials, supplies, or personnel may restrict or result in increased costs for operators related to developing and operating our properties.
The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies, and personnel. When shortages occur, the costs and delivery times of rigs, equipment, and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases in demand. In accordance with customary industry practice, our operators rely on independent third-party service providers to provide many of the services and equipment necessary to drill new wells. If our operators are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer. Shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies, personnel, trucking services, tubulars, fracking and completion services, and production equipment could delay or restrict our operators’ exploration and development operations, which in turn could have a material adverse effect on our financial condition, results of operations, and cash distributions to unitholders.
The marketability of oil and natural gas production is dependent upon transportation, pipelines, and refining facilities, which neither we nor many of our operators control. Any limitation in the availability of those facilities could interfere with our or our operators’ ability to market our or our operators’ production and could harm our business.
The marketability of our or our operators’ production depends in part on the availability, proximity, and capacity of pipelines, tanker trucks, and other transportation methods, and processing and refining facilities owned by third parties. The amount of oil that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage, or lack of available capacity on these systems, tanker truck availability, and extreme weather conditions. Also, the shipment of our or our operators’ oil and natural gas on third-party pipelines may be curtailed or delayed if it does not meet the quality specifications of the pipeline owners. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we or our operators are provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or transportation, processing, or refining-facility capacity could reduce our or our operators’ ability to market oil production and have a material adverse effect on our financial condition, results of operations, and cash distributions to unitholders. Our or our operators’ access to transportation options and the prices we or our operators receive can also be affected by federal and state regulation—including regulation of oil production, transportation, and pipeline safety—as well by general economic conditions and changes in supply and demand. In addition, the third parties on whom we or our operators rely for transportation services are subject to complex federal, state, tribal, and local laws that could adversely affect the cost, manner, or feasibility of conducting our business.  
Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
Oil and natural gas reserve engineering is not an exact science and requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, ultimate recoveries, and operating and development costs. As a result, estimated quantities of proved reserves, projections of future production rates, and the timing of development expenditures may be incorrect. Our estimates of proved reserves and related valuations as of December 31, 2018, 2017, and 2016 were prepared by NSAI, a third-party petroleum engineering firm, which conducted a detailed review of all of our properties for the period covered by its reserve report using information provided by us. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling, testing, and production. Also, certain assumptions regarding future oil and natural gas prices, production levels, and operating and development costs may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves and future cash generated from operations. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil and natural gas that are ultimately recovered being different from our reserve estimates.
The estimates of reserves as of December 31, 2018, 2017, and 2016 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the years ended December 31, 2018, 2017, and 2016, respectively, in accordance with the SEC guidelines applicable to reserve estimates for those periods. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for unproved undeveloped acreage.

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Conservation measures, technological advances, and general concern about the environmental impact of the production and use of fossil fuels could materially reduce demand for oil and natural gas and adversely affect our results of operations and the trading market for our common units.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy, and energy-generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations, and cash distributions to unitholders. It is also possible that the concerns about the production and use of fossil fuels will reduce the number of investors willing to own our common units, adversely affecting the market price of our common units.
We rely on a few key individuals whose absence or loss could adversely affect our business.
Many key responsibilities within our business have been assigned to a small number of individuals. The loss of their services could adversely affect our business. In particular, the loss of the services of one or more members of our executive team could disrupt our business. Further, we do not maintain “key person” life insurance policies on any of our executive team or other key personnel. As a result, we are not insured against any losses resulting from the death of these key individuals.
The results of exploratory drilling in shale plays will be subject to risks associated with drilling and completion techniques and drilling results may not meet our expectations for reserves or production.
Our operators use the latest drilling and completion techniques in their operations, and these techniques come with inherent risks. When drilling horizontal wells, operators risk not landing the well bore in the desired drilling zone and straying from the desired drilling zone. When drilling horizontally through a formation, operators risk being unable to run casing through the entire length of the well bore and being unable to run tools and other equipment consistently through the horizontal well bore. Risks that our operators face while completing wells include being unable to fracture stimulate the planned number of stages, to run tools the entire length of the well bore during completion operations, and to clean out the well bore after completion of the final fracture stimulation stage. In addition, to the extent our operators engage in horizontal drilling, those activities may adversely affect their ability to successfully drill in identified vertical drilling locations. Furthermore, certain of the new techniques that our operators may adopt, such as infill drilling and multi-well pad drilling, may cause irregularities or interruptions in production due to, in the case of infill drilling, offset wells being shut in and, in the case of multi-well pad drilling, the time required to drill and complete multiple wells before these wells begin producing. The results of drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas often have limited or no production history and consequently our operators will be less able to predict future drilling results in these areas.
Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our operators’ drilling results are weaker than anticipated or they are unable to execute their drilling program on our properties, our operating and financial results in these areas may be lower than we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline, and our results of operations and cash distributions to unitholders could be adversely affected.  
Oil and natural gas operations are subject to various governmental laws and regulations. Compliance with these laws and regulations can be burdensome and expensive, and failure to comply could result in significant liabilities, which could reduce cash distributions to our unitholders.
Operations on the properties in which we hold interests are subject to various federal, state, and local governmental regulations that may be changed from time to time in response to economic and political conditions. Matters subject to regulation include drilling operations, production and distribution activities, discharges or releases of pollutants or wastes, plugging and abandonment of wells, maintenance and decommissioning of other facilities, the spacing of wells, unitization and pooling of properties, and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of oil and natural gas. In addition, the production, handling, storage and transportation of oil and natural gas, as well as the remediation, emission, and disposal of oil and natural gas wastes, by-products thereof, and other substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state, and local laws and regulations primarily relating to protection of worker health and safety, natural resources, and the environment. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil, or criminal penalties, permit revocations, requirements for additional pollution controls, and injunctions limiting or prohibiting some or all

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of the operations on our properties. Moreover, these laws and regulations have generally imposed increasingly strict requirements related to water use and disposal, air pollution control, and waste management.
Laws and regulations governing exploration and production may also affect production levels. Our operators must comply with federal and state laws and regulations governing conservation matters, including:
provisions related to the unitization or pooling of the oil and natural gas properties;
the establishment of maximum rates of production from wells;
the spacing of wells;
the plugging and abandonment of wells; and
the removal of related production equipment.
Additionally, federal and state regulatory authorities may expand or alter applicable pipeline-safety laws and regulations, compliance with which may require increased capital costs for third-party oil and natural gas transporters.  These transporters may attempt to pass on such costs to our operators, which in turn could affect profitability on the properties in which we own mineral and royalty interests.
Our operators must also comply with laws and regulations prohibiting fraud and market manipulations in energy markets. To the extent the operators of our properties are shippers on interstate pipelines, they must comply with the tariffs of those pipelines and with federal policies related to the use of interstate capacity.
Our operators may be required to make significant expenditures to comply with the governmental laws and regulations described above. We believe the trend of more expansive and stricter environmental legislation and regulations will continue. Please read Part I, Items 1 and 2. “Business and Properties — Environmental Matters” for a description of the laws and regulations that affect our operators and that may affect us. These and other potential regulations could increase the operating costs of our operators and delay production, which could reduce the amount of cash distributions to our unitholders.
Louisiana mineral servitudes are subject to reversion to the surface owner after ten years’ nonuse.
We own mineral servitudes covering several hundred thousand acres in Louisiana. A mineral servitude is created in Louisiana when the mineral rights are separated from the ownership of the surface, whether by sale or reservation. These mineral servitudes, once created, are subject to a ten-year prescription of nonuse. During the ten-year period, the mineral-servitude owner has to conduct good-faith operations on the servitude for the discovery and production of minerals, or the mineral servitude “prescribes,” and the mineral rights associated with that servitude revert to the surface owner. A good-faith operation for the discovery and production of minerals, even one resulting in a dry hole, conducted within the ten-year period will interrupt the prescription of nonuse and restart the running of the ten-year prescriptive period. If the operation results in production, prescription is interrupted as long as the production continues or operations are conducted in good faith to secure or restore production. If any of our mineral servitudes are prescribed by operation of Louisiana law, our operating results may be adversely affected.
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs, additional operating restrictions or delays, and fewer potential drilling locations.
Our operators engage in hydraulic fracturing. Hydraulic fracturing is a common practice that is used to stimulate production of hydrocarbons from tight formations, including shales. The process involves the injection of water, sand, and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal SDWA regulates the underground injection of substances through the Underground Injection Control (“UIC”) program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic-fracturing process is typically regulated by state oil and natural gas commissions. The EPA however, has recently taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program and issued permitting guidance in February 2014 applicable to hydraulic fracturing involving the use of diesel fuel. The EPA has also issued effluent limitation guidelines in June 2016 to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants.
In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for

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fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals, or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. The EPA has not proposed to take any action in response to the report’s findings.
Several states where we own interests in oil and natural gas producing properties, including Colorado, North Dakota, Louisiana, Oklahoma, and Texas, have adopted regulations that could restrict or prohibit hydraulic fracturing in certain circumstances or require the disclosure of the composition of hydraulic-fracturing fluids. For example, in Texas, the Texas Railroad Commission ("RRC") published a final rule in October 2014 governing permitting or re-permitting of disposal wells that require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the RRC may deny, modify, suspend, or terminate the permit application or existing operating permit for that well. Similarly, Oklahoma has imposed strict limits on the operation of disposal wells in areas with increased instances of induced seismic events. These existing or any new legal requirements establishing seismic permitting requirements or similar restrictions on the construction or operation of disposal wells for the injection of produced water likely will result in added costs to comply and affect our operators’ rate of production, which in turn could have a material adverse effect on our results of operations and financial position. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general or hydraulic fracturing in particular. For example, from time to time in Colorado there have been various ballot initiatives to impose strict setback requirements on oil and gas activities from certain occupied structures and environmental sensitive areas, which could have potentially prohibited future production in areas in which we own interests. We cannot predict what additional state or local requirements may be imposed in the future on oil and gas operations in the states in which we own interests. In the event state, local, or municipal legal restrictions are adopted in areas where our operators conduct operations, our operators may incur substantial costs to comply with these requirements, which may be significant in nature, experience delays, or curtailment in the pursuit of exploration, development, or production activities and perhaps even be precluded from the drilling of wells.
There has been increasing public controversy regarding hydraulic fracturing with regard to increased risks of induced seismicity, the use of fracturing fluids, impacts on drinking water supplies, use of water, and the potential for impacts to surface water, groundwater, and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic-fracturing practices. If new laws or regulations are adopted that significantly restrict hydraulic fracturing, those laws could make it more difficult or costly for our operators to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing is further regulated at the federal or state level, fracturing activities on our properties could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements, and also to attendant permitting delays and potential increases in costs. Legislative changes could cause operators to incur substantial compliance costs. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.
Our credit facility has substantial restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions.
Our credit facility limits the amounts we can borrow to a borrowing base amount, as determined by the lenders at their sole discretion based on their valuation of our proved reserves and their internal criteria. The borrowing base is redetermined at least semi-annually, and the available borrowing amount could be decreased as a result of such redeterminations. Decreases in the available borrowing amount could result from declines in oil and natural gas prices, operating difficulties or increased costs, decreases in reserves, lending requirements, or regulations or certain other circumstances. As of December 31, 2018, we had outstanding borrowings of $410.0 million and the aggregate maximum credit amounts of the lenders were $1.0 billion. Our borrowing base determined by the lenders under our credit facility in October 2018 is $675.0 million and the next semi-annual redetermination is scheduled for April 2019. A future decrease in our borrowing base could be substantial and could be to a level below our then-outstanding borrowings. Outstanding borrowings in excess of the borrowing base are required to be repaid in five equal monthly payments, or we are required to pledge other oil and natural gas properties as additional collateral, within 30 days following notice from the administrative agent of the new or adjusted borrowing base. If we do not have sufficient funds on hand for repayment, we may be required to seek a waiver or amendment from our lenders, refinance our credit facility, or sell assets, debt, or equity. We may not be able to obtain such financing or complete such transactions on terms acceptable to us or at all. Failure to make the required repayment could result in a default under our credit facility, which could materially adversely affect our business, financial condition, results of operations, and distributions to our unitholders.

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The operating and financial restrictions and covenants in our credit facility restrict, and any future financing agreements likely will restrict, our ability to finance future operations or capital needs, engage in, expand, or pursue our business activities, or pay distributions. Our credit facility restricts, and any future credit facility likely will restrict, our ability to:
incur indebtedness;
grant liens;
make certain acquisitions and investments;
enter into hedging arrangements;
enter into transactions with our affiliates;
make distributions to our unitholders; or
enter into a merger, consolidation, or sale of assets.
    
Our credit facility restricts our ability to make distributions to unitholders or to repurchase units unless after giving effect to such distribution or repurchase, there is no event of default under our credit facility and our outstanding borrowings are not in excess of our borrowing base. While we currently are not restricted by our credit facility from declaring a distribution, we may be restricted from paying a distribution in the future.
We also are required to comply with certain financial covenants and ratios under the credit facility. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control, such as reduced oil and natural gas prices. If we violate any of the restrictions, covenants, ratios, or tests in our credit facility, a significant portion of our indebtedness may become immediately due and payable, our ability to make distributions will be inhibited, and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our credit facility are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our credit facility, the lenders can seek to foreclose on our assets.
The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the oil and natural gas that our operators produce.
In response to findings that emissions of carbon dioxide, methane, and other greenhouse gases ("GHGs") present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, require preconstruction and operating permits for certain large stationary sources. Facilities required to obtain preconstruction permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established on a case-by-case basis. These EPA rulemakings could adversely affect operations on our properties and restrict or delay the ability of our operators to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis, which include gathering and boosting facilities as well as GHG emissions from completions and workovers of hydraulically fractured wells. Also, in June 2016, the EPA finalized rules that establish new air emission controls for methane emissions from certain new, modified, or reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission, and storage activities, otherwise known as Subpart OOOOa. Following the change in administration, there have been attempts to modify these regulations, and litigation is ongoing. As a result, we cannot predict the scope of any final methane regulatory requirements or the cost to comply with such requirements with any certainty. Several states, including Colorado, where we hold interests, have also adopted rules to control and minimize methane emissions from the production of oil and natural gas. Moreover, in response to public concerns regarding methane emissions, many operators have recently voluntarily agreed to implement methane controls with respect to their operations. State and federal methane rules have substantial similarities with respect to pollution control equipment and leak detection and repair (“LDAR”) requirements. These rules could result in increased compliance costs for our operators and require them to make expenditures to purchase pollution control equipment and hire additional personnel to assist with complying with LDAR requirements, such as increased frequency of inspections and repairs for certain processes and equipment. Consequently, these and other regulations related to controlling GHG emissions could have an adverse impact on production on our properties, our business and results of operations.     
While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of federal climate legislation, a number of state and regional cap and trade programs have emerged. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would

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impact our business, any future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our operators’ equipment and operations could require them to incur costs to reduce emissions of GHGs associated with their operations. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas produced from our properties and lower the value of our reserves. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states, as well as state and local climate change initiatives, could adversely affect the oil and natural gas industry, and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business. Moreover, activists concerned about the potential effects of climate change have directed their attention at sources of funding for energy companies, which has resulted in certain financial institutions, funds, and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult for operators on our properties to secure funding for exploration and production activities. Additionally, activist shareholders have introduced proposals that may seek to force companies to adopt aggressive emission reduction targets or restrict more carbon-intensive activities. While we cannot predict the outcomes of such proposals, they could ultimately make it more difficult for operators to engage in exploration and production activities. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and gas will continue to represent a substantial percentage of global energy use over that time. Exploration and production activities are capital intensive, and capital constraints of our operators could have a material adverse impact on production from our properties. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts, and other extreme climatic events; if any of these effects were to occur, they could have a material adverse effect on our properties and operations.
Operating hazards and uninsured risks may result in substantial losses to us or our operators, and any losses could adversely affect our results of operations and cash distributions to unitholders.
We may be secondarily liable for damage to the environment caused by our operators. The operations of our operators will be subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses, and environmental hazards such as oil spills, natural gas leaks and ruptures, or discharges of toxic gases. In addition, their operations will be subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage, or potential underground migration of fracturing fluids, including chemical additives. The occurrence of any of these events could result in substantial losses to our operators due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension of operations, and repairs required to resume operations.
In accordance with what we believe to be customary industry practice, we maintain insurance against some, but not all, of our business risks. Our insurance may not be adequate to cover any losses or liabilities we may suffer. Also, insurance may no longer be available to us or, if it is, its availability may be at premium levels that do not justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations, or cash distributions to unitholders. In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. We may also be liable for environmental damage caused by previous owners of properties purchased by us, which liabilities may not be covered by insurance.
We may not have coverage if we are unaware of a sudden and accidental pollution event and unable to report the “occurrence” to our insurance providers within the time frame required under our insurance policy. We do not have, and do not intend to obtain, coverage for gradual, long-term pollution events. In addition, these policies do not provide coverage for all liabilities, and we cannot assure our unitholders that the insurance coverage will be adequate to cover claims that may arise or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations, and cash distributions to unitholders.
Title to the properties in which we have an interest may be impaired by title defects.
No assurance can be given that we will not suffer a monetary loss from title defects or title failure. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.

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Various security risks, including cybersecurity threats, data breaches, and other disruptions, could significantly affect us.

Various securities risks, including cyber attacks on businesses, have escalated in recent years. As one of the largest owners and managers of oil and natural gas mineral interests in the United States, we rely on electronic systems and networks to control and manage our business and have multiple layers of security to monitor, mitigate and manage these risks. However, these systems and networks, as well as our operators’ systems and networks and third-party infrastructure and operations, such as pipelines and transportation facilities, may be subject to sophisticated and deliberate security attacks and security breaches, which could lead to the corruption or loss of sensitive and valuable data, delays in production or delivery, difficulty in completing and settling transactions, challenges in maintaining our books and records, environmental damage, communication interruptions, material adverse effects on our reputation or financial position and other operational disruptions and third-party liabilities, including the cost of remedial actions. Cyber attacks and data breaches in particular are becoming more sophisticated and include, but are not limited to, malicious software, ransomware, attempts to gain unauthorized access to data, employee and third-party errors, and other electronic security breaches. If we or our operators were to experience an attack or a breach and security measures failed, the potential consequences to our businesses and the communities in which we operate could be significant. In addition, our efforts to monitor, mitigate and manage these evolving risks may result in increased capital and operating costs, but there can be no assurance that such efforts will be sufficient to prevent attacks or breaches from occurring. 
Risks Inherent in an Investment in Us
We expect to distribute a substantial majority of the cash we generate from operations each quarter, which could limit our ability to grow and make acquisitions.
We expect to distribute a substantial majority of the cash we generate from operations each quarter. As a result, we will have limited cash generated from operations to reinvest in our business or to fund acquisitions, and we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and growth capital expenditures. If we are unable to finance growth externally, our distribution policy will significantly impair our ability to grow.
If we issue additional units in connection with any acquisitions or growth capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. Other than limitations restricting our ability to issue units ranking senior or on parity with our Series B cumulative convertible preferred units, there are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units with respect to distributions. The incurrence of additional commercial borrowings or other debt to finance our growth would result in increased interest expense and required principal repayments, which, in turn, may reduce the cash that we have available to distribute to our unitholders. Please read Part II, Item 5. “Market for Registrant’s Common Equity, Related Unitholder Matters, and Issuer Purchases of Equity Securities — Cash Distribution Policy.”
The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion. Our partnership agreement does not require us to pay any distributions at all on our common and subordinated units. If we make distributions, our Series B cumulative convertible unitholders have priority with respect to rights to share in those distributions over our common and subordinated unitholders for so long as our Series B cumulative convertible preferred units are outstanding.
Our partnership agreement generally provides that, during the subordination period (as defined in our partnership agreement), we will pay any distributions each quarter as follows: (i) first, to the holders of Series B cumulative convertible preferred units equal to 7% per annum, subject to certain adjustments, (ii) second, to the holders of common units, until each common unit has received the applicable minimum quarterly distribution plus any arrearages from prior quarters, and (iii) third, to the holders of subordinated units, until each subordinated unit has received the applicable minimum quarterly distribution. If the distributions to our common and subordinated unitholders exceed the applicable minimum quarterly distribution per unit, then such excess amounts will be distributed pro rata on the common and subordinated units as if they were a single class. Our minimum quarterly distribution is $1.35 per common and subordinated unit on an annualized basis (or $0.3375 per unit on a quarterly basis) for the four quarters ending March 31, 2019 and thereafter. We expect that we will distribute a substantial majority of the cash we generate from operations each quarter. However, the board of directors of our general partner could elect not to pay distributions for one or more quarters or at all. Please read Part II, Item 5. “Market for Registrant’s Common Equity, Related Unitholder Matters, and Issuer Purchases of Equity Securities — Cash Distribution Policy.”
Our partnership agreement does not require us to pay any distributions at all on our common units. Accordingly, investors are cautioned not to place undue reliance on the permanence of any distribution policy in making an investment decision. Any

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modification or revocation of our cash distribution policy could substantially reduce or eliminate the amounts of distributions to our unitholders. The amount of distributions we make, if any, and the decision to make any distribution at all will be determined by the board of directors of our general partner. If we make distributions, our Series B cumulative convertible preferred unitholders have priority with respect to rights to share in those distributions over our common and subordinated unitholders for so long as our Series B cumulative convertible preferred units are outstanding. Please read Part II, Item 5. “Market for Registrant’s Common Equity, Related Unitholder Matters, and Issuer Purchases of Equity Securities — Cash Distribution Policy — Series B Cumulative Convertible Preferred Units.”
Our minimum quarterly distribution provides the common unitholders a specified priority right to distributions over the subordinated unitholders if we pay distributions. It does not provide the common unitholders the right to require payment of any distributions.
Our partnership agreement does not require us to pay any distributions on our common and subordinated units. The provision providing for a minimum quarterly distribution merely provides the common unitholders with a specified priority right to distributions before the subordinated unitholders receive distributions, if distributions are made with respect to the common and subordinated units.
Uncertainty associated with the end of the subordination period could result in volatility in the market price of our common units and in the amount of our quarterly cash distributions.
The subordination period under our partnership agreement will end on the first business day after we have earned and paid an aggregate amount of at least $1.35 (the annualized minimum quarterly distribution applicable for quarterly periods ending March 31, 2019 and thereafter) multiplied by the total number of outstanding common and subordinated units for a period of four consecutive, non-overlapping quarters ending on or after March 31, 2019, and there are no outstanding arrearages on our common units. This could be as early as May 2019. If the subordination period ends as a result of our having met the test described above, the subordinated units will convert into common units on a one-to-one basis. If holders of the common units resulting from conversion attempt to liquidate those common units, the market price of our common units could fall.
In addition, the elimination of the subordinated units means that all units (other than the Series B cumulative convertible preferred units) have equal priority with respect to distributions. Consequently, reductions of our quarterly cash distributions will affect all unitholders equally. 
After the subordination period ends, our common unitholders will no longer be entitled to arrearages in the payment of the minimum quarterly distribution from prior quarters. The board of directors of our general partner has not yet adopted a distribution policy for periods following the subordination period. Distributions following the end of the subordination period could vary significantly from quarter to quarter, may be lower than the applicable minimum quarterly distribution, or may not be paid at all. Please read “- Risks Inherent in an Investment in Us - The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion. Our partnership agreement does not require us to pay any distributions at all on our common and subordinated units. If we make distributions, our Series B cumulative convertible preferred unitholders have priority with respect to rights to share in those distributions over our common and subordinated unitholders for so long as our Series B cumulative convertible preferred units are outstanding."
Our partnership agreement eliminates the fiduciary duties that might otherwise be owed to the partnership and its partners by our general partner and its directors and executive officers under Delaware law.
Our partnership agreement contains provisions that eliminate the fiduciary duties that might otherwise be owed by our general partner and its directors and executive officers. For example, our partnership agreement provides that our general partner and its directors and executive officers have no duties to the partnership or its partners except as expressly set forth in the partnership agreement. In place of default fiduciary duties, our partnership agreement imposes a contractual standard requiring our general partner and its directors and executive officers to act in good faith, meaning they cannot cause the general partner to take an action that they subjectively believe is adverse to our interests. Such contractual standards allow our general partner and its directors and executive officers to manage and operate our business with greater flexibility and to subject the actions and determinations of our general partner and its directors and executive officers to lesser legal or judicial scrutiny than would be the case if state law fiduciary standards were applicable.

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Our partnership agreement restricts the situations in which remedies may be available to our unitholders for actions taken that might constitute breaches of duty under applicable Delaware law and breaches of the contractual obligations in our partnership agreement.
Our partnership agreement restricts the potential liability of our general partner and its directors and executive officers to our unitholders. For example, our partnership agreement provides that our general partner and its directors and executive officers will not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in willful misconduct or fraud or, with respect to any criminal conduct, with the knowledge that its conduct was unlawful.
Unitholders are bound by the provisions of our partnership agreement, including the provisions described above.
Our partnership agreement restricts the voting rights of unitholders owning 15% or more of our units, subject to certain exceptions.
Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person or group that owns 15% or more of any class of units then outstanding, other than the limited partners in BSMC prior to the IPO, their transferees, persons who acquired such units with the prior approval of the board of directors of our general partner, holders of Series B cumulative convertible preferred units in connection with any vote, consent or approval of the Series B cumulative convertible preferred units as a separate class, and persons who own 15% or more of any class as a result of any redemption or purchase of any other person's units or similar action by us or any conversion of the Series B cumulative convertible preferred units at our option or in connection with a change of control may not vote on any matter.
Actions taken by our general partner may affect the amount of cash generated from operations that is available for distribution to unitholders or accelerate the right to convert subordinated units.
The amount of cash generated from operations available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:
amount and timing of asset purchases and sales;
cash expenditures;
borrowings and repayment of current and future indebtedness;
issuance of additional units; and
the creation, reduction, or increase of reserves in any quarter.
In addition, borrowings by us do not constitute a breach of any duty owed by our general partner to our unitholders, including borrowings that have the purpose or effect of:
enabling holders of subordinated units to receive distributions; or
hastening the expiration of the subordination period.
In addition, our general partner may use an initial amount, equal to $137.6 million, which would not otherwise constitute cash generated from operations, in order to permit the payment of distributions on subordinated units. All these actions may affect the amount of cash distributed to our unitholders and may facilitate the conversion of subordinated units into common units.
For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, our partnership agreement permits us to borrow funds, which would enable us to make such distribution on all outstanding units.
We have a call right that may require common unitholders to sell their common units at an undesirable time or price.
If at any point in time prior to the end of the subordination period we have acquired more than 80% of the total number of common units outstanding, we have the right, but not the obligation, to purchase all of the remaining common units at a price equal to the greater of (1) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (2) the highest per-unit price paid by us or any of our

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affiliates for common units during the 90-day period preceding the date such notice is first mailed. This limited call right is not exercisable as long as any of our Series B cumulative convertible preferred units are outstanding, or at any time after the subordination period has ended.
Unitholders may have liability to repay distributions.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
Increases in interest rates may cause the market price of our common units to decline.
An increase in interest rates may cause a corresponding decline in demand for equity investments in general, and in particular, for yield-based equity investments such as our common units. Any such increase in interest rates or reduction in demand for our common units resulting from other investment opportunities may cause the trading price of our common units to decline.
We may issue additional common units and other equity interests without common and subordinated unitholder approval, which would dilute holders of common and subordinated units. However, subject to certain exceptions, our partnership agreement does not authorize us to issue units ranking senior to or at parity with our Series B cumulative convertible preferred units without Series B cumulative convertible preferred unitholder approval.
Under our partnership agreement, we are authorized to issue an unlimited number of additional interests, including common units, without a vote of the unitholders other than, in certain instances, approval of holders of our Series B cumulative convertible preferred units. Our issuance of additional common units or other equity interests of equal or senior rank will have the following effects:
the proportionate ownership interest of common and subordinated unitholders in us immediately prior to the issuance will decrease;
the amount of cash distributions on each common and subordinated unit may decrease;
the ratio of our taxable income to distributions may increase;
the relative voting strength of each previously outstanding common and subordinated unit may be diminished; and
the market price of the common units may decline.
However, subject to certain exceptions, our partnership agreement does not authorize us to issue securities having preferences or rights with priority over or on a parity with the Series B cumulative convertible preferred units with respect to rights to share in distributions, redemption obligations, or redemption rights without Series B cumulative convertible preferred unitholder approval.
The market price of our common units could be adversely affected by sales of substantial amounts of our common units in the public or private markets.
As of December 31, 2018, we had 108,362,876 common units and 96,328,836 subordinated units and 14,711,219 Series B cumulative convertible preferred units outstanding. All the subordinated units could convert into common units on no more than a one-to-one basis at the end of the subordination period. Each holder may elect to convert all or any portion of its Series B cumulative convertible preferred units into common units on a one-for-one basis, subject to customary anti-dilution adjustments and an adjustment for any distributions that have accrued but not been paid when due, at any time after the second anniversary of November 28, 2017. Under certain conditions, we may elect to convert all or any portion of the Series B cumulative convertible preferred units into common units at any time after the second anniversary of November 28, 2017. Sales by holders of a substantial number of our common units in the public markets, or the perception that these sales might occur, could have a material adverse effect on the price of our common units or impair our ability to obtain capital through an offering of equity securities.

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The price of our common units may fluctuate significantly, and unitholders could lose all or part of their investment.
The market price of our common units may be influenced by many factors, some of which are beyond our control, including those described elsewhere in these risk factors.
We have and will continue to incur increased costs as a result of being a publicly traded partnership.
As a publicly traded partnership, we have and will continue to incur significant legal, accounting, and other expenses that we did not incur prior to the IPO. In addition, the Sarbanes-Oxley Act, as well as rules implemented by the SEC and the NYSE, require publicly traded entities to maintain various corporate governance practices that further increase our costs. Before we are able to make distributions to our unitholders, we must first pay or reserve for our expenses, including the costs of being a publicly traded partnership. As a result, the amount of cash we have available to distribute to our unitholders will be affected by the costs associated with being a publicly traded partnership.
Following the IPO, we became subject to the public reporting requirements of the Securities Exchange Act of 1934 (the “Exchange Act”). These requirements have increased our legal and financial compliance costs.
If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.
Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud, and operate successfully as a publicly traded partnership. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future, or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act. For example, Section 404 requires us, among other things, to annually review and report on, and our independent registered public accounting firm to attest to, the effectiveness of our internal controls over financial reporting. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common units.
The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.
Because we are a publicly traded partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. In addition, because we are a publicly traded partnership, the NYSE does not require us to obtain unitholder approval prior to certain unit issuances. Accordingly, unitholders will not have the same protections afforded to stockholders of certain corporations that are subject to all of the NYSE’s corporate governance requirements.
Our partnership agreement includes exclusive forum, venue, and jurisdiction provisions. By purchasing a common unit, a limited partner is irrevocably consenting to these provisions regarding claims, suits, actions, or proceedings, and submitting to the exclusive jurisdiction of Delaware courts.
Our partnership agreement is governed by Delaware law. Our partnership agreement includes exclusive forum, venue, and jurisdiction provisions designating Delaware courts as the exclusive venue for all claims, suits, actions, or proceedings arising out of or relating in any way to the partnership agreement, brought in a derivative manner on behalf of the partnership, asserting a claim of breach of a fiduciary or other duty owed by any director, officer, or other employee of the partnership or the general partner, or owed by the general partner to the partnership or the partners, asserting a claim arising pursuant to any provision of the Delaware Act, or asserting a claim governed by the internal affairs doctrine. By purchasing a common unit, a limited partner is irrevocably consenting to these provisions regarding claims, suits, actions, or proceedings and submitting to the exclusive jurisdiction of Delaware courts. If a dispute were to arise between a limited partner and us or our officers, directors, or employees, the limited partner may be required to pursue its legal remedies in Delaware, which may be an inconvenient or distant location and which is considered to be a more corporate-friendly environment.  

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If a unitholder is not an Eligible Holder, the common units of such unitholder may be subject to redemption.
We have adopted certain requirements regarding those investors who may own our units. Eligible Holders are limited partners (a) whose, or whose owners’, U.S. federal income tax status does not have or is not reasonably likely to have a material adverse effect on the rates chargeable by us to customers and (b) whose ownership could not result in our loss of ownership in any material part of our assets, as determined by our general partner with the advice of counsel. If an investor is not an Eligible Holder, in certain circumstances as set forth in our partnership agreement, units held by such investor may be redeemed by us at the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.
Tax Risks to Common Unitholders
Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, and not being subject to a material amount of entity-level taxation. If the Internal Revenue Service (“IRS”) were to treat us as a corporation for U.S. federal income tax purposes or we were to become subject to entity-level taxation for state tax purposes, then our cash distributions to common unitholders could be substantially reduced.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income tax purposes.
Despite the fact that we are organized as a limited partnership under Delaware law, we will be treated as a corporation for U.S. federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations and current Treasury Regulations, we believe that we satisfy the qualifying income requirement. However, we have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate. Distributions to our common unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, or deductions would flow through to our common unitholders. Because a tax would be imposed upon us as a corporation, cash distributions to our common unitholders would be substantially reduced. In addition, changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, and other forms of taxation. Imposition of any of those taxes may substantially reduce the cash distributions to our common unitholders. Therefore, treatment of us as a corporation or the assessment of a material amount of entity-level taxation would result in a material reduction in the anticipated cash generated from operations and after-tax return to the common unitholders, likely causing a substantial reduction in the value of our common units.
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial, or administrative changes and differing interpretations, possibly applied on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative, or judicial changes or differing interpretations at any time. From time to time, members of Congress propose and consider similar substantive changes to the existing U.S. federal income tax laws that would affect publicly traded partnerships, including a prior legislative proposal that would have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes.
In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect publicly traded partnerships. Although there are no current legislative or administrative proposals, there can be no assurance that there will not be further changes to U.S. federal income tax laws or the Treasury Department's interpretation of the qualifying income rules in a manner that could impact our ability to qualify as a partnership in the future.
Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted or adopted. Any such changes could negatively impact the value of an investment in our common units. You are urged to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potential effect on your investment in our common units.

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Future legislation may result in the elimination of certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and production. Additionally, future federal or state legislation may impose new or increased taxes or fees on oil and natural gas extraction.
In past years, legislation has been proposed that would, if enacted into law, make significant changes to tax laws, including to certain key U.S. federal income tax provisions currently available to oil and gas companies. Such legislative changes have included, but not been limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; and (iii) an extension of the amortization period for certain geological and geophysical expenditures. Congress could consider, and could include, some or all of these proposals as part of tax reform legislation, to accompany lower U.S. federal income tax rates. Moreover, other more general features of tax reform legislation including changes to cost recovery rules and to the deductibility of interest expense may be developed that also would change the taxation of oil and gas companies. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available to us or our services providers with respect to oil and gas development, or increase costs, and any such changes could have an adverse effect on the Company’s financial position, results of operations and cash flows.
If the IRS were to contest the U.S. federal income tax positions we take, it may adversely affect the market for our common units, and the costs of any such contest would reduce cash available for distribution to our common unitholders.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely affect the market for our common units and the price at which they trade. Moreover, the costs of any contest between us and the IRS will result in a reduction in cash available for distribution to our common unitholders and thus will be borne indirectly by our common unitholders.
If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case cash available for distribution to our common unitholders might be substantially reduced and our current and former common unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such common unitholders' behalf.
Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes an audit adjustment to our income tax return, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. To the extent possible under the new rules, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised information statement to each common unitholder and former common unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our common unitholders and former common unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current common unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such common unitholders did not own common units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties, and interest, cash available for distribution to our common unitholders might be substantially reduced and our current and former common unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustment that were paid on such common unitholders' behalf. These rules are not applicable for tax years beginning on or prior to December 31, 2017.
Even if you, as a common unitholder, do not receive any cash distributions from us, you will be required to pay taxes on your share of our taxable income.
You will be required to pay U.S. federal income taxes and, in some cases, state and local income taxes, on your share of our taxable income, whether or not you receive cash distributions from us. For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, you may be allocated taxable income and gain resulting from the sale and our cash available for distribution would not increase. Similarly, taking advantage of opportunities to reduce our existing debt,

40


such as debt exchanges, debt repurchases, or modifications of our existing debt could result in “cancellation of indebtedness income” being allocated to our common unitholders as taxable income without any increase in our cash available for distribution. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax due from you with respect to that income.
Tax gain or loss on disposition of our common units could be more or less than expected.
If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of prior excess distributions with respect to the common units you sell will, in effect, become taxable income to you if you sell your common units at a price greater than your tax basis in those common units, even if the price you receive is less than your original cost. In addition, because the amount realized includes a common unitholder’s share of our nonrecourse liabilities, if you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale.
A substantial portion of the amount realized from the sale of your common units, whether or not representing gain, may be taxed as ordinary income to you due to potential recapture items, including depreciation recapture. Thus, you may recognize both ordinary income and capital loss from the sale of your common units if the amount realized on a sale of your common units is less than your adjusted basis in the common units. Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which you sell your common units, you may recognize ordinary income from our allocations of income and gain to you occurring prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of common units.
Tax-exempt entities face unique tax issues from owning our common units that may result in adverse tax consequences to them.
Investment in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs) raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, may be unrelated business taxable income and may be taxable to them. With respect to taxable years beginning after December 31, 2017, subject to the proposed aggregation rules for certain similarly situated businesses/activities issued by the Treasury Department, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours) is required to compute the unrelated business taxable income of such tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, for years beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax-exempt entities should consult a tax advisor before investing in our common units.
Non-U.S. common unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our common units.
Non-U.S. common unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business (“effectively connected income”). Income allocated to our common unitholders and any gain from the sale of our common units will generally be considered to be “effectively connected” with a U.S. trade or business. As a result, distributions to a non-U.S. common unitholder will be subject to withholding at the highest applicable effective tax rate and a non-U.S. common unitholder who sells or otherwise disposes of a common unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that common unit.
The Tax Cuts and Jobs Act imposes a withholding obligation of 10% of the amount realized upon a non-U.S. common unitholder’s sale or exchange of an interest in a partnership that is engaged in a U.S. trade or business. However, due to challenges of administering a withholding obligation applicable to open market trading and other complications, the IRS has temporarily suspended the application of this withholding rule to open market transfers of interests in publicly traded partnerships pending promulgation of regulations or other guidance that resolves the challenges. It is not clear if or when such regulations or other guidance will be issued. Non-U.S. common unitholders should consult a tax advisor before investing in our common units.

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We treat each purchaser of common units as having the same tax benefits without regard to the common units actually purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Because we cannot match transferors and transferees of our common units and because of other reasons, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns.
We generally prorate our items of income, gain, loss, and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss, and deduction among our common unitholders.
We generally prorate our items of income, gain, loss, and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month (the “Allocation Date”), instead of on the basis of the date a particular common unit is transferred. Similarly, we generally allocate certain deductions for depreciation of capital additions, gain or loss realized on a sale or other disposition of our assets and, in the discretion of the general partner, any other extraordinary item of income, gain, loss, or deduction based upon ownership on the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss, and deduction among our common unitholders.
A common unitholder whose common units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of common units) may be considered to have disposed of those common units. If so, he would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and could recognize gain or loss from the disposition.
Because there are no specific rules governing the U.S. federal income tax consequences of loaning a partnership interest, a common unitholder whose common units are the subject of a securities loan may be considered to have disposed of the loaned common units. In that case, the common unitholder may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the common unitholder may recognize gain or loss from this disposition. Moreover, during the period of the loan, any of our income, gain, loss, or deduction with respect to those common units may not be reportable by the common unitholder and any cash distributions received by the common unitholder as to those common units could be fully taxable as ordinary income. Common unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.
You, as a common unitholder, may be subject to state and local taxes and return filing requirements in states where you do not live as a result of investing in our common units.
In addition to U.S. federal income taxes, you likely will be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance, or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if you do not live in any of those jurisdictions. We own assets and conduct business in several states, many of which impose a personal income tax and also impose income taxes on corporations and other entities. You may be required to file state and local income tax returns and pay state and local income taxes in these jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. As we make acquisitions or expand our business, we may own assets or conduct business in additional states or foreign jurisdictions that impose a personal income tax. It is your responsibility to file all U.S. federal, foreign, state, and local tax returns.
Although we believe our common unitholders are entitled to a 20% deduction related to qualified business income, application of the deduction to royalty income is not free from doubt.
For taxable years beginning after December 31, 2017 and ending on or before December 31, 2025, an individual common unitholder is entitled to a deduction equal to 20% of his or her allocable share of our "qualified business income". Although we expect most of our income to qualify for this deduction, application of these rules to income from mineral interests, such as royalty income, is not entirely clear. The IRS may challenge our treatment of royalty income as qualifying for the deduction. Although our counsel has advised us that under current law our royalty income should qualify for the deduction, no assurances can be given that the IRS will not challenge our treatment of royalty income as qualifying for the deduction.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 3. LEGAL PROCEEDINGS
Although we may, from time to time, be involved in various legal claims arising out of our operations in the normal course of business, we do not believe that the resolution of these matters will have a material adverse impact on our financial condition or results of operations.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.

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PART II



ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common units are listed on the NYSE under the symbol “BSM.” The following table sets forth the daily high and low sales price for our common units as reported by the NYSE, as well as the quarterly distributions per common and subordinated unit paid for the indicated periods. 
 
 
Price Range of Common Units
 
Distributions1
 
 
High
 
Low
 
Per Common Unit
 
Per Subordinated Unit
2017
 
 
 
 
 
 
 
 
First Quarter
 
$
19.55

 
$
15.58

 
$
0.2875

 
$
0.18375

Second Quarter
 
$
17.21

 
$
15.12

 
$
0.3125

 
$
0.20875

Third Quarter
 
$
17.92

 
$
15.52

 
$
0.3125

 
$
0.20875

Fourth Quarter
 
$
18.57

 
$
16.71

 
$
0.3125

 
$
0.20875

 
 
 
 
 
 
 
 
 
2018
 
 
 
 
 
 
 
 
First Quarter
 
$
19.03

 
$
16.36

 
$
0.3125

 
$
0.20875

Second Quarter
 
$
19.01

 
$
16.40

 
$
0.3375

 
$
0.33750

Third Quarter
 
$
19.29

 
$
17.02

 
$
0.3700

 
$
0.37000

Fourth Quarter
 
$
18.59

 
$
15.23

 
$
0.3700

 
$
0.37000

1 
Represents cash distributions attributable to the quarter. Cash distributions declared in respect of a quarter are paid in the following quarter.
As of February 19, 2019, there were 108,851,353 common units outstanding held by 458 holders of record. Because many of our common units are held by brokers and other institutions on behalf of unitholders, we are unable to estimate the total number of unitholders represented by these holders of record. As of February 19, 2019, we also had outstanding 96,328,836 subordinated units and 14,711,219 Series B cumulative convertible preferred units. There is no established public market in which the subordinated units or the Series B cumulative convertible preferred units are traded.


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Common Unit Performance Graph
The graph below compares our cumulative total unitholder return on our common units beginning on April 30, 2015, the date of pricing for our IPO, through December 31, 2018 with the S&P 500 index and the Alerian MLP index. The graph assumes that the value of the investment in our common units was $100.00 on April 30, 2015. Cumulative return is computed assuming reinvestment of distributions. 
chart-5c98cca824bc5be4b51.jpg

Comparison of Cumulative Total Return
Assumes Initial Investment of $100
 
 
 
 
As of December 31,
 
 
As of April 30, 2015
 
2015
 
2016
 
2017
 
2018
Black Stone Minerals, L.P.
 
$
100.00

 
$
78.22

 
$
109.07

 
$
110.89

 
$
101.80

S&P 500 Index
 
100.00

 
99.47

 
111.37

 
135.69

 
129.74

Alerian MLP Index
 
100.00

 
66.99

 
79.25

 
74.08

 
64.88

The information in this Annual Report appearing under the heading “Common Unit Performance Graph” is being furnished pursuant to Item 201(e) of Regulation S-K and shall not be deemed to be “soliciting material” or to be “filed” with the SEC or subject to Regulation 14A or 14C, other than as provided in Item 201(e) of Regulation S-K, or to the liabilities of Section 18 of the Exchange Act.




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Securities Authorized for Issuance under Equity Compensation Plans
See the information incorporated by reference under “Part III, Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters” regarding securities authorized for issuance under our equity compensation plans.
Recent Sales of Unregistered Securities
On October 26, 2018, we closed on the purchase of certain mineral interests using 7,664 common units valued at $0.1 million to fund the purchase price.
The issuance of the common units was made in reliance upon an exemption from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(a)(2) thereunder.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
The following tables set forth our purchases of our common units for each month during the three months ended December 31, 2018:
Purchases of Common Units
Period
 
Total Number of Common Units Purchased
 
Average Price Paid Per Unit
 
Total Number of Common Units Purchased as Part of Publicly Announced Plans or Programs2
 
Maximum Dollar Value of Common Units That May Yet Be Purchased Under the Plans or Programs
December 1 – December 31, 2018
 
137,0851
 
$
15.67

 
128,627

 
$
72,992,543

1  
Includes units withheld to satisfy tax withholding obligations upon the vesting of certain restricted common units held by our executive officers and certain other employees.
2 
On November 5, 2018, the board of directors of our general partner authorized the repurchase of up to $75.0 million in common units. The repurchase program authorizes us to make repurchases on a discretionary basis as determined by management, subject to market conditions, applicable legal requirements, available liquidity, and other appropriate factors. All or a portion of any repurchases may be made under a Rule 10b5-1 plan, which would permit common units to be repurchased when we might otherwise be precluded from doing so under insider trading laws. The repurchase program does not obligate us to acquire any particular amount of common units and may be modified or suspended at any time and could be terminated prior to completion.
Cash Distribution Policy
Our partnership agreement generally provides that we will pay any distributions each quarter during the subordination period in the following manner:
first, to the holders of the Series B cumulative convertible preferred units in an amount equal to 7% per annum, subject to certain adjustments;
second, to the holders of common units, until each common unit has received the applicable minimum quarterly distribution in the amounts specified below plus any arrearages from prior quarters; and
third, to the holders of subordinated units, until each subordinated unit has received the applicable minimum quarterly distribution.

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If the distributions to our common and subordinated unitholders exceed the applicable minimum quarterly distribution per unit, then such excess amounts will be distributed pro rata on the common and subordinated units as if they were a single class. The minimum quarterly distribution is currently $1.35 per common and subordinated unit on an annualized basis (or $0.3375 per unit on a quarterly basis) for the four quarters ending March 31, 2019 and thereafter. The minimum quarterly distribution does not provide the common unitholders the right to require payment of any distributions. It merely reflects the specified priority right of our common unitholders to distributions before the subordinated unitholders receive distributions, if distributions are paid.
The amount of cash to be distributed each quarter will be determined by the board of directors of our general partner following the end of that quarter after a review of our cash generated from operations for such quarter. We expect that we will distribute a substantial majority of the cash generated from our operations each quarter. The cash generated from operations for each quarter will generally equal our Adjusted EBITDA for the quarter, less cash needed for debt service, other contractual obligations, fixed charges, and reserves for future operating or capital needs that the board of directors may determine are appropriate. It is our intent, for at least the next several years, to finance most of our acquisitions and working interest capital needs with cash generated from operations, borrowings under our credit facility, our executed farmout agreements, and, in certain circumstances, proceeds from future equity and debt issuances. We may also borrow to make distributions to our unitholders where, for example, we believe that the distribution level is sustainable over the long term, but short-term factors may cause cash generated from operations to be insufficient to pay distributions at the applicable minimum quarterly distribution level on our common and subordinated units. The board of directors of our general partner can change the amount of the quarterly distributions, if any, at any time and from time to time. Our partnership agreement does not require us to pay cash distributions on a quarterly or other basis on our common and subordinated units. Please read Part I, Item 1A. “Risk Factors — Risks Inherent in an Investment in Us — The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion. Our partnership agreement does not require us to pay any distributions at all on our common and subordinated units. If we make distributions, our Series B cumulative convertible preferred unitholders have priority with respect to rights to share in those distributions over our common and subordinated unitholders for so long as our Series B cumulative convertible preferred units are outstanding.” For a description of the relative rights and privileges of our Series B cumulative convertible preferred units to distributions, please read "Series B Cumulative Convertible Preferred Units" below.
Replacement capital expenditures are expenditures necessary to replace our existing oil and natural gas reserves or otherwise maintain our asset base over the long term. Like a number of other master limited partnerships, we are required by our partnership agreement to retain cash from our operations in an amount equal to our estimated replacement capital requirements. We believe the level of our distribution rate will allow us to retain in our business sufficient cash generated from our operations to satisfy our replacement capital expenditure needs and to fund a portion of our growth capital expenditures. The board of directors of our general partner is responsible for establishing the amount of our estimated replacement capital expenditures on annual basis. On August 3, 2016, the board of directors established a replacement capital expenditure estimate of $15.0 million for the period of April 1, 2016 to March 31, 2017; there was no established estimate of replacement capital prior to this period. On June 8, 2017, the board of directors established a replacement capital expenditure estimate of $13.0 million for the period April 1, 2017 to March 31, 2018. On April 27, 2018, the board of directors approved a replacement capital expenditure estimate of $11.0 million for the period of April 1, 2018 to March 31, 2019.
Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy
There is no guarantee that we will make cash distributions to our unitholders. Our cash distribution policy may be changed at any time by the board of directors of our general partner and is subject to certain restrictions, including the following:
Our common and subordinated unitholders have no contractual or other legal right to receive cash distributions from us on a quarterly or other basis, and if distributions are paid, common and subordinated unitholders will receive distributions only to the extent the distribution amount exceeds distributions that are required to be paid to our Series B cumulative convertible preferred unitholders.
Our credit facility restricts our distributions if there is a default under our credit facility or if our borrowing base is lower than the outstanding loans under our credit facility. Among other covenants, our credit facility requires we maintain a ratio of total debt to EBITDAX of 3.50:1.00 or less and a current ratio of 1.00:1.00 or greater. If we are unable to comply with these financial covenants or if we breach any other covenant under our credit facility or any future debt agreements, we could be prohibited from making distributions notwithstanding our stated distribution policy.
Our general partner has the authority to establish cash reserves for the prudent conduct of our business, and the establishment of, or increase in, those reserves could result in a reduction in cash distributions to our unitholders. Our

47



partnership agreement does not limit the amount of cash reserves that our general partner may establish. Any decision to establish cash reserves made by our general partner will be binding on our unitholders.
Under Section 17-607 of the Delaware Act, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets.
We may lack sufficient cash to pay distributions to our unitholders due to shortfalls in cash generated from operations attributable to a number of operational, commercial, or other factors as well as increases in our operating or general and administrative expenses, principal and interest payments on our outstanding debt, working-capital requirements, and anticipated cash needs.
We expect to continue to distribute a substantial majority of our cash from operations to our unitholders on a quarterly basis, after, among other things, the establishment of cash reserves. To fund our growth, we may eventually need capital in excess of the amounts we may retain in our business or borrow under our credit facility. To the extent efforts to access capital externally are unsuccessful, our ability to grow could be significantly impaired.
Any distributions paid on our common and subordinated units with respect to a quarter will be paid within 60 days after the end of such quarter.
Subordinated Units
    
The limited partners of BSM’s Predecessor acquired all of our subordinated units in connection with our IPO. The principal difference between our common and subordinated units is that, for any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution until the holders of the common units have received the applicable minimum quarterly distribution for such quarter plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units do not accrue arrearages. Our common unitholders are only entitled to arrearages in the payment of the minimum quarterly distribution from prior quarters during the subordination period. To the extent we have cash generated from operations available for distribution in any quarter during the subordination period in excess of the amount necessary to pay the applicable minimum quarterly distribution to holders of our common units, we will use this excess cash to pay any distribution arrearages on the common units related to prior quarters before any cash distribution is made on our subordinated units. Please read “Cash Distribution Policy.” 
The subordination period will end on the first business day after we have earned and paid an aggregate amount of at least $1.35 (the annualized minimum quarterly distribution applicable for quarterly periods ending March 31, 2019 and thereafter) multiplied by the total number of outstanding common and subordinated units for a period of four consecutive, non-overlapping quarters ending on or after March 31, 2019, and there are no outstanding arrearages on our common units. When the subordination period ends as a result of our having met the test described above, all subordinated units will convert into common units on a one-to-one basis, and common units will thereafter no longer be entitled to arrearages.
In addition, at any time on or after March 31, 2019, provided there are no arrearages in the payment of the minimum quarterly distribution on the common units, our general partner may decide in its sole discretion to convert each subordinated unit into a number of common units at a ratio that will be less than one to one. If our general partner makes such election, all outstanding subordinated units will be converted into common units, and the conversion ratio will be equal to the distributions paid out with respect to the subordinated units over the previous four-quarter period in relation to the total amount of distributions required to pay the applicable minimum quarterly distribution in full with respect to the subordinated units over the previous four quarters. If at the time our general partner elects to convert the subordinated units under this provision our forecasted distributions on our subordinated units (as determined by the conflicts committee of our general partner’s board of directors) for the next four quarters are lower than our actual distributions for the previous four-quarter period referred to above, then the conversion ratio will be based on the forecasted distributions instead of the actual distributions.

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Series A Redeemable Preferred Units
Until March 31, 2018, the holders of our outstanding Series A redeemable preferred units had the option to elect to have us redeem, effective as of December 31, 2017, their Series A redeemable preferred units at face value, plus any accrued and unpaid distributions. All Series A redeemable preferred units not redeemed by March 31, 2018 automatically converted to common and subordinated units effective as of January 1, 2018 or as soon as practicable thereafter. Therefore, there are currently no Series A redeemable preferred units outstanding.
Series B Cumulative Convertible Preferred Units
The holders of our Series B cumulative convertible preferred units will receive cumulative quarterly distributions in an amount equal to 7.0% of the face amount of the preferred units per annum (the “Distribution Rate”), provided that the Distribution Rate will be adjusted as follows: commencing on the sixth anniversary of November 28, 2017 and readjusting every two years thereafter (each, a “Readjustment Date”), the rate will equal the greater of (i) the Distribution Rate in effect immediately prior to the relevant Readjustment Date and (ii) the 10-year Treasury Rate as of such Readjustment Date plus 5.5% per annum; provided, however, that for any quarter commencing after the second anniversary of November 28, 2017 in which quarterly distributions are accrued but unpaid, the then-Distribution Rate shall be increased by 2.0% per annum for such quarter. We cannot pay any distributions on any junior securities, including any of our common units and subordinated units, prior to paying the quarterly distribution payable to the Series B cumulative convertible preferred units, including any previously accrued and unpaid distributions.


49



ITEM 6. SELECTED FINANCIAL DATA
The financial information below should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data” of this Annual Report. 
 
At December 31,
 
2018
 
2017
 
2016
 
2015
 
2014
 
(in thousands, except per unit amounts)
Total revenue
$
609,568

 
$
429,659

 
$
260,833

 
$
392,924

 
$
548,321

Net income (loss)
295,560

 
157,153

 
20,188

 
(101,305
)
 
169,187

Net income (loss) attributable to the general partner and common units and subordinated units
274,511

 
152,145

 
14,437

 
(108,017
)
 
*
Net income (loss) attributable to limited partners per common and subordinated unit (basic)1
 
 
 
 
 

 
 

 
 
Per common unit (basic)
1.46

 
1.01

 
0.26

 
(0.56
)
 
*
Per subordinated unit (basic)
1.25

 
0.56

 
(0.11
)
 
(0.56
)
 
*
Net income (loss) attributable to limited partners per common and subordinated unit (diluted)1
 
 
 
 
 
 
 

 
 
Per common unit (diluted)
1.45

 
1.01

 
0.26

 
(0.56
)
 
*
Per subordinated unit (diluted)
1.25

 
0.56

 
(0.11
)
 
(0.56
)
 
*
Cash distributions declared per common and subordinated unit
 
 
 
 
 

 
 

 
 
Per common unit
$
1.33

 
$
1.20

 
$
1.10

 
$
0.42

 
*
Per subordinated unit
$
1.13

 
$
0.79

 
$
0.74

 
$
0.42

 
*
Total assets2
$
1,750,124

 
$
1,576,451

 
$
1,128,827

 
$
1,061,436

 
$
1,326,782

Long-term debt
410,000

 
388,000

 
316,000

 
66,000

 
394,000

Total mezzanine equity
298,361

 
322,422

 
54,015

 
79,162

 
161,165

*
Information is not applicable for the periods prior to our IPO.
1  
See Note 13 – Earnings Per Unit in the consolidated financial statements included elsewhere in this Annual Report.
2  
We recorded noncash impairments of oil and natural gas properties in the amounts of $6.8 million, $249.6 million, and $117.9 million for the years ended December 31, 2016, 2015, and 2014, respectively. We did not have impairments of oil and natural gas properties for the years ended December 31, 2018 and 2017.


50



ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and notes thereto presented elsewhere in this Annual Report.   This discussion and analysis contains forward-looking statements that involve risks, uncertainties, and assumptions. Actual results may differ materially from those anticipated in these forward-looking statements as a result of a number of factors, including those set forth under “Cautionary Note Regarding Forward-Looking Statements” and “Part I, Item 1A. Risk Factors.”
Overview
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 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 the marketing of our mineral assets for lease, creatively structuring the terms on those leases to encourage and accelerate drilling activity, and selectively participating alongside our lessees on a working interest basis. 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.
As of December 31, 2018, our mineral and royalty interests were located in 41 states in the continental United States including all of the major onshore producing basins. These non-cost-bearing interests include ownership in over 60,000 producing wells. We also own non-operated working interests, a significant portion of which are on our positions where we also have a mineral and royalty interest. We recognize oil and natural gas revenue from our mineral and royalty and non-operated working interests in producing wells when control of the oil and natural gas produced is transferred to the customer and collectability of the sales price is reasonably assured. Our other sources of revenue include mineral lease bonus and delay rentals, which are recognized as revenue according to the terms of the lease agreements.
Recent Developments
Acquisitions
In 2018 we acquired mineral and royalty interests primarily in the Permian Basin and in East Texas for aggregate consideration of $127.3 million in cash and $22.6 million in our common units. Additional information regarding acquisitions is contained in Note 4 – Oil and Natural Gas Properties Acquisitions to our consolidated financial statements included elsewhere in this Annual Report.
PepperJack Prospect
We have cumulatively spent approximately $13.1 million to drill two wells within our PepperJack prospect in Hardin and Liberty counties, Texas. The PepperJack A#1 well targeting the Lower Wilcox formation was drilled during the fourth quarter of 2017 and the first quarter of 2018. The PepperJack B#1 well, also targeting the Lower Wilcox formation, was drilled during the second quarter of 2018 to further delineate the prospect.
Based on the log results, we believe the PepperJack A#1 well is highly prospective and will be completed as a commercially productive well. The PepperJack B#1 well, which was a significant step-out from the PepperJack A#1 well, is not likely to be completed in the near term. Accordingly, we have recorded $6.8 million of costs for the PepperJack B#1 well to the Exploration expense line item of the consolidated statements of operations for the year ended December 31, 2018.
On September 21, 2018, we entered into an exploration agreement with a consortium of private exploration and production companies (the “Development Partners”) to further delineate and develop the PepperJack prospect. As part of the agreement, we assigned 75% of our working interest in the PepperJack A#1 well and acreage in the associated unit to the Development Partners and transferred our status as the operator of record. We received proceeds of $6.4 million for the assignment, which represented a reimbursement for 100% of the drilling costs and associated acreage, proceeds of $1.0 million for an option covering our minerals and leases in the PepperJack prospect area, and an overriding royalty interest in the PepperJack prospect area. The Development Partners began completion operations on the PepperJack A#1 well in the fourth quarter of 2018 and we are participating as a 25% non-operated working interest owner.



51




Common Unit Repurchase Program
In the fourth quarter of 2018, the board of directors of our general partner authorized a $75.0 million common unit repurchase program. The repurchase program authorizes us to make repurchases on a discretionary basis as determined by management, subject to market conditions, applicable legal requirements, available liquidity, and other appropriate factors. All or a portion of any repurchases may be made under a Rule 10b5-1 plan, which would permit common units to be repurchased when we might otherwise be precluded from doing so under applicable laws. The repurchase program does not obligate us to acquire any particular amount of common units and may be modified or suspended at any time and could be terminated prior to completion. We will periodically report the number of common units repurchased. In 2018, we repurchased a total of 128,627 common units for an aggregate cost of $2.0 million. The program is funded from cash on hand or through borrowings under the credit facility. Any repurchased units are canceled.
Business Environment
The information below is designed to give a broad overview of the oil and natural gas business environment as it affects us.
Commodity Prices and Demand
Oil and natural gas prices have been historically volatile based upon the dynamics of supply and demand. The EIA forecasts that WTI oil prices will average approximately $54.79 per Bbl in 2019 and $58.00 per Bbl in 2020. During the year ended December 31, 2018, the WTI oil spot price reached a high of $77.41 per Bbl on June 27, 2018 but decreased to a low of $44.48 per Bbl on December 27, 2018.
The EIA forecasts that the Henry Hub spot natural gas price will average $2.83 per MMBtu for 2019 and $2.80 per MMBtu for 2020. During the year ended December 31, 2018, Henry Hub spot natural gas prices ranged from a high of $6.24 per MMBtu on January 3, 2018 to a low of $2.49 per MMBtu on February 16, 2018.
To manage the variability in cash flows associated with the projected sale of our oil and natural gas production, we use various derivative instruments, which have recently consisted of fixed-price swap contracts and costless collar contracts.
The following table reflects commodity prices at the end of each quarter presented:
 
 
2018
Benchmark Prices
 
Fourth Quarter
 
Third Quarter
 
Second Quarter
 
First Quarter
WTI spot crude oil ($/Bbl)1
 
$
45.15

 
$
73.16

 
$
74.13

 
$
64.87

Henry Hub spot natural gas ($/MMBtu)1
 
$
3.25

 
$
3.01

 
$
2.96

 
$
2.81

1 
Source: EIA
Rig Count
As we are not the operator of record on any producing properties, drilling on our acreage is dependent upon the exploration and production companies that lease our acreage. In addition to drilling plans that we seek from our operators, we also monitor rig counts in an effort to identify existing and future leasing and drilling activity on our acreage.

52



The following table shows the rig count at the end of each quarter presented:
 
 
2018
U.S. Rotary Rig Count1
 
Fourth Quarter
 
Third Quarter
 
Second Quarter
 
First Quarter
Oil
 
885

 
863

 
858

 
797

Natural gas
 
198

 
189

 
187

 
194

Other
 

 
2

 
2

 
2

Total
 
1,083

 
1,054

 
1,047

 
993

 1 
Source: Baker Hughes Incorporated
Natural Gas Storage
A substantial portion of our revenue is derived from sales of oil production attributable to our interests; however, the majority of our production is natural gas. Natural gas prices are significantly influenced by storage levels throughout the year. Accordingly, we monitor the natural gas storage reports regularly in the evaluation of our business and its outlook.
Historically, natural gas supply and demand fluctuates on a seasonal basis. From April to October, when the weather is warmer and natural gas demand is lower, natural gas storage levels generally increase. From November to March, storage levels typically decline as utility companies draw natural gas from storage to meet increased heating demand due to colder weather. In order to maintain sufficient storage levels for increased seasonal demand, a portion of natural gas production during the summer months must be used for storage injection. The portion of production used for storage varies from year to year depending on the demand from the previous winter and the demand for electricity used for cooling during the summer months. The EIA forecasts that inventories will conclude the withdrawal season, which is the end of March 2019, at 1,417 Bcf, or 14% below the five-year average. The EIA expects inventories to build slightly over the five-year average to a projected 3,761 Bcf at the end of October 2019; in 2020, inventories are expected to be about 5% higher on average than 2019 levels.

The following table shows natural gas storage volumes by region at the end of each quarter presented:
 
 
 
2018
Region1
 
Fourth Quarter
 
Third Quarter
 
Second Quarter
 
First Quarter
 
 
(Bcf)
East
 
661

 
763

 
460

 
229

Midwest
 
798

 
836

 
455

 
266

Mountain
 
147

 
177

 
139

 
87

Pacific
 
220

 
262

 
257

 
166

South Central
 
878

 
829

 
841

 
606

Total
 
2,704

 
2,867

 
2,152

 
1,354

1  
Source: EIA

53



How We Evaluate Our Operations
We use a variety of operational and financial measures to assess our performance. Among the measures considered by management are the following:
volumes of oil and natural gas produced;
commodity prices including the effect of derivative instruments; and
Adjusted EBITDA and distributable cash flow.
Volumes of Oil and Natural Gas Produced
In order to track and assess the performance of our assets, we monitor and analyze our production volumes from the various basins and plays that constitute our extensive asset base. We also regularly compare projected volumes to actual reported volumes and investigate unexpected variances.
Commodity Prices
Factors Affecting the Sales Price of Oil and Natural Gas
The prices we receive for oil, natural gas, and NGLs vary by geographical area. The relative prices of these products are determined by the factors affecting global and regional supply and demand dynamics, such as economic conditions, production levels, availability of transportation, weather cycles, and other factors. In addition, realized prices are influenced by product quality and proximity to consuming and refining markets. Any differences between realized prices and NYMEX prices are referred to as differentials. All our production is derived from properties located in the United States.
Oil. The substantial majority of our oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of our control. NYMEX light sweet crude oil, commonly referred to as WTI, is the prevailing domestic oil pricing index. The majority of our oil production is priced at the prevailing market price with the final realized price affected by both quality and location differentials.
The chemical composition of oil plays an important role in its refining and subsequent sale as petroleum products.  As a result, variations in chemical composition relative to the benchmark oil, usually WTI, will result in price adjustments, which are often referred to as quality differentials. The characteristics that most significantly affect quality differentials include the density of the oil, as characterized by its API gravity, and the presence and concentration of impurities, such as sulfur.
Location differentials generally result from transportation costs based on the produced oil’s proximity to consuming and refining markets and major trading points.
Natural Gas. The NYMEX price quoted at Henry Hub is a widely used benchmark for the pricing of natural gas in the United States. The actual volumetric prices realized from the sale of natural gas differ from the quoted NYMEX price as a result of quality and location differentials. 
Quality differentials result from the heating value of natural gas measured in Btus and the presence of impurities, such as hydrogen sulfide, carbon dioxide, and nitrogen. Natural gas containing ethane and heavier hydrocarbons has a higher Btu value and will realize a higher volumetric price than natural gas which is predominantly methane, which has a lower Btu value. Natural gas with a higher concentration of impurities will realize a lower volumetric price due to the presence of the impurities in the natural gas when sold or the cost of treating the natural gas to meet pipeline quality specifications.
Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply and demand conditions and the cost to transport natural gas to end user markets.


54



Hedging
We enter into derivative instruments to partially mitigate the impact of commodity price volatility on our cash generated from operations. From time to time, such instruments may include variable-to-fixed-price swaps, fixed-price contracts, costless collars, and other contractual arrangements. The impact of these derivative instruments could affect the amount of revenue we ultimately realize.
Our open derivative contracts consist of fixed-price swap contracts and costless collar contracts. Under fixed-price swap contracts, a counterparty is required to make a payment to us if the settlement price is less than the swap strike price. Conversely, we are required to make a payment to the counterparty if the settlement price is greater than the swap strike price. Our costless collar contracts contain a fixed floor price and a fixed ceiling price. If the market price exceeds the fixed ceiling price, we receive the fixed ceiling price from the counterparty and we pay the market price. If the market price is below the fixed floor price, we receive the fixed floor price and we pay the market price. If the market price is between the fixed floor and fixed ceiling price, no payments are due from either party. If we have multiple contracts outstanding with a single counterparty, unless restricted by our agreement, we will net settle the contract payments.
We may employ contractual arrangements other than fixed-price swap contracts and costless collar contracts in the future to mitigate the impact of price fluctuations. If commodity prices decline in the future, our hedging contracts will partially mitigate the effect of lower prices on our future revenue. Our open oil and natural gas derivative contracts as of December 31, 2018 are detailed in Note 5 – Commodity Derivative Financial Instruments to our consolidated financial statements included els