Black Stone Minerals
Annual Report 2018

Plain-text annual report

UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549FORM 10-KxANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the fiscal year ended December 31, 2018OR¨TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934For the transition period _______________ to _______________Commission file number 001-37362Black Stone Minerals, L.P.(Exact Name of Registrant As Specified in Its Charter)Delaware 47-1846692(State or Other Jurisdiction ofIncorporation or Organization) (I.R.S. EmployerIdentification No.)1001 Fannin Street, Suite 2020Houston, Texas 77002(Address of Principal Executive Offices) (Zip Code)Registrant’s telephone number, including area code: (713) 445-3200Securities registered pursuant to Section 12(b) of the Act:Title of each class Name of each exchange on which registeredCommon Units Representing Limited Partner Interests New York Stock ExchangeSecurities 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 xx 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 xxIndicate 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 12months (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 xx 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 ofthis chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes xx 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 thebest 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 Filerxx 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 financialaccounting 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 xxThe 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 secondfiscal 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 proxystatement for the annual meeting of unitholders. BLACK STONE MINERALS, L.P.TABLE OF CONTENTS PAGEPART I ITEMS 1 AND 2.BUSINESS AND PROPERTIES2ITEM 1A.RISK FACTORS22ITEM 1B.UNRESOLVED STAFF COMMENTS43ITEM 3.LEGAL PROCEEDINGS43ITEM 4.MINE SAFETY DISCLOSURES43 PART II ITEM 5.MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS, AND ISSUER PURCHASESOF EQUITY SECURITIES44ITEM 6.SELECTED FINANCIAL DATA50ITEM 7.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS51ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK68ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA68ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE69ITEM 9A.CONTROLS AND PROCEDURES69ITEM 9B.OTHER INFORMATION69 PART III ITEM 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE70ITEM 11.EXECUTIVE COMPENSATION70ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDERMATTERS70ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE70ITEM 14.PRINCIPAL ACCOUNTING FEES AND SERVICES70 PART IV ITEM 15.EXHIBITS AND FINANCIAL STATEMENT SCHEDULES71iiGLOSSARY OF TERMSThe 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 (“AnnualReport”).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 isbased 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 caseof 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 theliquid 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 continuethe 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, oreconomic 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 andnatural 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 ornatural 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 productionexceed 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 alower 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 anotherreservoir.iiiGLOSSARY OF TERMSExtension 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 interestto another party, called the "farmee," in exchange for certain contractually agreed services with respect to such acreage or for payment for drilling operationson 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 featureand/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 aspecified interval.Hydraulic fracturing. A process used to stimulate production of hydrocarbons. The process involves the injection of water, sand, and chemicals underpressure 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 thehydrocarbons 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 orcompletion 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, andproduce 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 undergroundaccumulations, and may potentially be dissolved in oil or may also be found in its gaseous state.NGLs. Natural gas liquids.ivGLOSSARY OF TERMSNonparticipating 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 oilor 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 theexpense 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 sourcerock, 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 intoanother 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, inorder 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 productionexceed 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 inwhich the cost of the required equipment is relatively minor compared to the cost of a new well, and through installed extraction equipment andinfrastructure 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 becommercially 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 relativelymajor 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 toprovide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.vGLOSSARY OF TERMSReserves. Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a givendate, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there willexist, 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 froma known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may containprospective 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 byimpermeable 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 assource 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 oroperating 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 isacquired by transmitting a signal from an energy source, such as dynamite or water, into the earth. The energy so transmitted is subsequently reflectedbeneath 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 includerelatively large amounts of organic material compared with other rock types and thus has the potential to become rich hydrocarbon source rock. Its fine grainsize 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 accordancewith the rules and regulations of the Securities and Exchange Commission (using prices and costs in effect as of the date of estimation), less futuredevelopment, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Standardized measure doesnot 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 havebeen ascertained through supporting geological, geophysical, or other data to contain the potential for oil and/or natural gas reserves in a particularformation 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 quantitiesof 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 ashare 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 anda 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 STATEMENTSCertain 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 generallynot historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and theirpotential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance thatfuture developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results arebased on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involvesignificant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from ourhistorical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in theforward-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, Item1A. “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 topublicly 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 IUnless 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 StoneMinerals, L.P. on May 6, 2015 (the “IPO”), and references to “BSM,” “Black Stone,” “we,” “our,” “us,” “the Partnership,” or like terms refer to BlackStone Minerals, L.P. and its subsidiaries for time periods subsequent to the IPO.ITEMS 1 AND 2. BUSINESS AND PROPERTIESGeneralWe are one of the largest owners and managers of oil and natural gas mineral interests in the United States. Our principal business is maximizing thevalue of our existing mineral and royalty assets through active management and expanding our asset base through acquisitions of additional mineral androyalty interests. We maximize value through marketing our mineral assets for lease, creatively structuring the terms on those leases to encourage andaccelerate drilling activity, and selectively participating alongside our lessees on a working interest basis. Our primary business objective is to grow ourreserves, production, and cash generated from operations over the long term, while paying, to the extent practicable, a growing quarterly distribution to ourunitholders.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 millionacres and ORRIs in 2.1 million acres. These non-cost-bearing interests, which we refer to collectively as our “mineral and royalty interests,” includeownership in over 60,000 producing wells. Our mineral and royalty interests are located in 41 states in the continental United States, including all of themajor onshore producing basins. Many of these interests are in active resource plays, including the Haynesville/Bossier shales in East Texas/WesternLouisiana, the Wolfcamp/Spraberry/Bone Spring in the Permian Basin, the Bakken/Three Forks in the Williston Basin, and the Eagle Ford shale in SouthTexas. The combination of the breadth of our asset base, the long-lived, non-cost-bearing nature of our mineral and royalty interests, and our activemanagement 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 of22,500,000 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 thesereports with the U.S. Securities and Exchange Commission (“SEC”). Through our website, http://www.blackstoneminerals.com, we make available electroniccopies 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 afterfiling or furnishing them to the SEC.2PART IOur AssetsAs 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 providedbelow under "Our Properties" based on major geographical region and by material resource play as denoted on the map below.Mineral and Royalty InterestsMineral 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 rightsto 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 rightsare 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 entitlesus 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 initiallease term with continuous drilling, production, or other operating activities, or by making an extension payment. When production or drilling ceases, thelease terminates, allowing us to lease the exploration and development rights to another party. Mineral interests generate the substantial majority of ourrevenue 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 istypically perpetual, to receive a fixed, cost-free percentage of production or revenue from production, without an associated right to lease or receivelease bonus; and•Overriding royalty interests (“ORRIs”), which are royalty interests that burden working interests and represent the right to receive a fixed, cost-freepercentage 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 sametract 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 ofDecember 31, 2018, approximately 28% of our mineral and royalty interests are leased, calculated on a cumulative gross acreage basis for all three types ofmineral and royalty interests. We have relied on representations made in the relevant purchase agreements to determine leasing status of recently acquiredacreage.The majority of our producing mineral and royalty interest acreage is pooled with third party acreage to form pooled units. Pooling proportionatelyreduces our royalty interest in wells drilled in a pooled unit, and it proportionately increases the number of wells in which we have such reduced royaltyinterest.Non-Operated Working InterestsWe own non-operated working interests related to our mineral interests in various plays across our asset base. The majority of our working interestexposure is in the Haynesville/Bossier play in East Texas where we own non-operated working interests alongside XTO Energy Inc., a subsidiary of ExxonMobil Corporation, and our other major operator in the area. In 2017, we entered into farmout arrangements (discussed below) for our entire working interestposition 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. Underthe 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 indrilling opportunities on our mineral acreage. This right to participate in a unit or well is exercisable at our sole discretion. We generally only exercise thisoption when the results from prior drilling and production activities have substantially reduced the economic risk associated with development drilling andwhere 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 theseparticipation 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 andoperating these wells. Working interest production represented 31% of our total production volumes during the year ended December 31, 2018. As ofDecember 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 ofthis 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 AgreementsOn February 21, 2017, we announced that we entered into a farmout agreement with Canaan Resource Partners ("Canaan", and such farmout, the "CanaanFarmout"), which covers certain Haynesville and Bossier shale acreage in San Augustine County, Texas operated by XTO Energy Inc. We have anapproximate 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 andfunds 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 thewells 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 inthe 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 ORRIafter4payout on all wells drilled under the agreement. From the inception of the agreement through December 31, 2018, we have received $80.7 million fromCanaan 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 Texastargeting 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 8/8thsbasis), 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 operatorin San Augustine and Angelina counties, Texas. Initially, Pivotal is obligated to fund the development of up to 80 wells across several development areasand then has options to continue funding our working interest across those areas for the duration of the farmout agreement. Pivotal will fund designatedgroups 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 wellgroup. From the inception of the agreement through December 31, 2018, we have received $63.0 million from Pivotal under the agreement and assigned toPivotal 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 beminimal in 2019.PepperJack ProspectWe have cumulatively spent approximately $13.1 million to drill two wells within our PepperJack prospect in Hardin and Liberty counties, Texas. ThePepperJack 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#1well, 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. ThePepperJack 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 haverecorded $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 yearended 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 thePepperJack A#1 well and acreage in the associated unit to the Development Partners and transferred our status as the operator of record. We received proceedsof $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 anoption covering our mineral interests and leases in the PepperJack prospect area, and an overriding royalty interest in the PepperJack prospect area. TheDevelopment 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 PropertiesBSM Land RegionsWe divide the contiguous United States into major geographical regions that we refer to as "BSM Land Regions". The following is an overview of theseregions.•Gulf Coast. The Gulf Coast region consists of the land area along the Gulf of Mexico from South Texas through Florida. This region includes theWestern 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 throughArizona. 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 Montanaand 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 thethe 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, ArkomaBasin, 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 theSan 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 Interests2BSM Land Region Mineral Interests NPRIs ORRIs Gross Acres Net %3 Gross Acres Net %4 Gross Acres Net %4 Gross Acres Net AcresGulf Coast 7,870,800 52.3% 615,430 3.6% 406,073 3.8% 432,483 96,033Southwestern US 2,856,033 24.9% 1,006,317 2.4% 213,637 1.8% 60,879 17,630RockyMountains 2,144,803 15.3% 244,839 3.4% 1,026,455 2.6% 97,932 16,720Eastern US 1,657,834 47.4% 1,727 4.0% 74,892 1.4% 13,487 1,346Mid-Continent 1,292,995 34.2% 39,483 3.9% 349,046 3.3% 40,622 23,860Western 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% 645,403 155,5891 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 ourmineral 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 ournon-operated working interests, overlap between working interest acreage and mineral and royalty interest acreage can be significant, while overlapbetween 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. Theaverage ownership interests shown reflect the weighted averages of our ownership interests in all tracts in the BSM Land Region. Our weighted averagemineral royalty for all of our mineral interests is approximately 20%, which may be multiplied by our ownership interest to approximate the averageroyalty 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 operatingcosts) 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 theowner 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 ourland 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 YearEnded December 31, Average Daily Production (Boe/d) for the YearEnded December 31,BSM Land Region MRI Wells2 WI Wells 2018 2017 2016 2018 2017 2016Gulf Coast 11,702 2,307 16,425 13,016 11,235 11,869 10,056 7,428SouthwesternUS 26,336 1,149 5,081 2,966 1,493 278 426 442RockyMountains 12,442 2,044 7,050 4,440 4,018 934 1,157 1,714Eastern US 1,988 256 886 1,027 995 22 24 25Mid-Continent 7,960 4,162 2,366 2,343 2,602 1,120 1,287 1,456Western US 831 1 270 269 275 — — —Total 61,259 9,919 32,078 24,061 20,618 14,223 12,950 11,0651 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 PlaysThe following is an overview of the resource plays we consider most material to our current and future business. These plays accounted for 70% of ouraggregate 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 NorthDakota, South Dakota, and Montana in the United States, and Saskatchewan and Manitoba in Canada. The U.S. portion of the Bakken/Three Forksplay is within the Rocky Mountains BSM Land Region. We have significant exposure in these plays through our mineral and royalty interests aswell 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 Regionand is one of the largest producing natural gas formations in the United States. The play’s prospective acreage is evenly divided between East Texasand Western Louisiana, and while we have significant exposure through our mineral and royalty interests and working interests across the entireplay, the majority of our acreage is located in East Texas, with a particular concentration in the prolific southern portion of the Shelby Trough in SanAugustine, 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 LandRegion. It is separated from the Delaware Basin to the west by a carbonate platform called the Central Basin Platform. We refer to the variousPermian-aged resource plays within the Midland Basin as the Permian-Midland. These plays include the various members of the Spraberry andWolfcamp 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 inthe Southwestern US BSM Land Region. It is separated from the Midland Basin to the east by a carbonate platform called the Central BasinPlatform. We refer to the various Permian-aged resource7plays within the Delaware Basin as the Permian-Delaware. These plays include the various members of the Bone Spring, Avalon, and Wolfcampformations. 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 between4,000 and 14,000 feet. We are experiencing a significant level of development drilling on our mineral interests within the oil and rich-gas andcondensate 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 Interests2Resource Play Mineral Interests NPRIs ORRIs Gross Acres Net %3 Gross Acres Net %4 Gross Acres Net %4 Gross Acres Net AcresBakken/Three Forks 399,691 16.9% 39,744 1.3% 15,450 1.3% 55,480 7,300Haynesville/Bossier 393,744 62.0% 28,442 1.6% 29,488 4.8% 231,269 53,994Permian-Midland 291,770 5.7% 146,786 0.6% 107,996 0.6% 160 4Permian-Delaware 132,897 10.5% 37,301 0.7% 6,643 2.4% 2,522 1,171Eagle Ford 67,447 14.2% 106,729 1.2% 49,572 2.2% 1,147 871 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 ourmineral 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 ournon-operated working interests, overlap between working interest acreage and mineral and royalty interest acreage can be significant, while overlapbetween 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. Theaverage ownership interests shown reflect the weighted averages of our ownership interests in all tracts in the resource play. Our weighted average mineralroyalty for all of our mineral interests is approximately 20%, which may be multiplied by our ownership interest to approximate the average royaltyinterest 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 operatingcosts) 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 tothe stated fraction of gross production, or a “fraction of royalty,” where the stated fraction is multiplied by the lease royalty. In cases where our landdocumentation 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 December31, 20181 Average Daily Production (Boe/d) for the YearEnded December 31, Average Daily Production (Boe/d) for the YearEnded December 31,Resource Play MRI Wells2 WI Wells 2018 2017 2016 2018 2017 2016Bakken/Three Forks 3,322 513 5,007 2,769 2,789 693 812 1,359Haynesville/Bossier 1,013 326 10,273 5,943 4,962 10,657 10,972 5,439Permian-Midland 1,287 2 1,792 717 150 1 — 1Permian-Delaware 375 20 2,207 791 443 65 157 150Eagle Ford 797 27 1,920 1,768 2,210 12 16 761 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 ReservesEvaluation and Review of Estimated Proved ReservesThe reserves estimates as of December 31, 2018, 2017, and 2016 shown herein have been independently evaluated by NSAI, a worldwide leader ofpetroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consultingpetroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical person primarilyresponsible for preparing the estimates set forth in the NSAI summary reserves report incorporated herein is Mr. J. Carter Henson, Jr. Mr. Henson, a LicensedProfessional Engineer in the State of Texas (License No. 73964), has been practicing consulting petroleum engineering at NSAI since 1989 and has over 8years of prior industry experience. He graduated from Rice University in 1981 with Bachelor of Science Degree in Mechanical Engineering. As technicalprincipal, Mr. Henson meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating andAuditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in judiciously applying industry standardpractices to engineering evaluations as well as applying SEC and other industry reserves definitions and guidelines. NSAI does not own an interest in us orany 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 asan 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 ensurethe 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 thereserve 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 ourproperties. Brock Morris, our Senior Vice President, Engineering and Geology, is primarily responsible for overseeing the preparation of all of our reserveestimates. 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 metwith NSAI to review properties and discuss evaluation methods and assumptions used in the proved reserves estimates, in accordance with our prescribedinternal control procedures. Our internal controls over the reserves estimation process include verification of input data used in the reserves evaluationsoftware 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 ReservesIn accordance with rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities, proved reserves arethose quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economicallyproducible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Theterm “reasonable certainty” means deterministically, the quantities of oil and/or natural gas are much more likely to be achieved than not, andprobabilistically, there should be at least a 90% probability of recovering volumes equal to or exceeding the estimate. All of our estimated proved reserves asof December 31, 2018, 2017, and 2016 are based on deterministic methods. Reasonable certainty can be established using techniques that have been provedeffective by actual production from projects in the same reservoir or an analogous reservoir or by using reliable technology. Reliable technology is agrouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonablycertain 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 wellswith sufficient production history were estimated using appropriate decline curves or other performance relationships. Reserves attributable to producingwells with limited production history and for undeveloped locations were estimated using performance from analogous wells in the surrounding area andgeologic data to assess the reservoir continuity. In addition to assessing reservoir continuity, geologic data from well logs, core analyses, and seismic datawere used to estimate original oil and natural gas in place.Summary of Estimated Proved ReservesReserve estimates do not include any value for probable or possible reserves that may exist. The reserve estimates represent our net revenue interest androyalty 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 18,150Natural gas (MMcf)278,233 233,017 223,057Total (MBoe)63,939 56,727 55,327Estimated proved undeveloped reserves5: Oil (MBbls)— 8 218Natural gas (MMcf)35,787 67,257 47,282Total (MBoe)5,965 11,218 8,098Estimated proved reserves: Oil (MBbls)17,567 17,899 18,368Natural gas (MMcf)314,020 300,274 270,339Total (MBoe)69,904 67,945 63,425Percent proved developed91.5% 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 perbarrel is used for estimates of reserves for all the properties as of December 31, 2018. This average price is adjusted for quality, transportation fees, andmarket 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 ofDecember 31, 2018. This average price is adjusted for energy content, transportation fees, and market differentials. Natural gas prices are also adjusted toaccount for NGL revenue since there is not sufficient data to account for NGL volumes separately in the reserve estimates. These reserve estimates excludeNGL quantities. When taking these adjustments into account, the average adjusted prices weighted by production over the remaining lives of theproperties 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 barrelis used for estimates of reserves for all the properties as of December 31, 2017. These average prices are adjusted for quality, transportation fees, and marketdifferentials. 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 ofDecember 31, 2017. These average prices are adjusted for energy content, transportation fees, and market differentials. Natural gas prices are also adjustedto account for NGL revenue since there is not sufficient data to account for NGL volumes separately in the reserve estimates. These reserve estimatesexclude NGL quantities. When taking these adjustments into account, the average adjusted prices weighted by production over the remaining lives of theproperties 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 barrelis used for estimates of reserves for all the properties as of December 31, 2016. These average prices are adjusted for quality, transportation fees, and marketdifferentials. 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 ofDecember 31, 2016. These average prices are adjusted for energy content, transportation fees, and market differentials. Natural gas prices are also adjustedto account for NGL revenue since there is not sufficient data to account for NGL volumes separately in the reserve estimates. These reserve estimatesexclude NGL quantities. When taking these adjustments into account, the average adjusted prices weighted by production over the remaining lives of theproperties 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 developedreserves 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 cannotbe measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geologicalinterpretation. As a result, the estimates of different engineers often vary for the same property. In addition, the results of drilling, testing, and production mayjustify 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 mayvary 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 inthis 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 ReservesAs 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 todeveloped 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, 201711,218Acquisitions of reserves—Divestiture of reserves—Extensions and discoveries5,965Revisions of previous estimates(1,725)Transfers to estimated proved developed(9,493)As of December 31, 20185,965New PUD reserves totaling 5,965 MBoe were added during the year ended December 31, 2018, resulting from development activities in theHaynesville/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 oftwo 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 ofDecember 31, 2017. Additionally, during the year ended December 31, 2018, we incurred $13.1 million drilling and completing other wells that were notclassified as PUDs as of December 31, 2017. There are no estimated future development costs projected for the development of PUD reserves as ofDecember 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 wereinitially 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 tothose 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 CostsProduction and Price HistoryFor 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 condensateproduction 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 gasrevenues.The following table sets forth information regarding production of oil and natural gas and certain price and cost information for each of the periodsindicated: Year Ended December 31, 2018 2017 2016Production: Oil and condensate (MBbls)1 4,962 3,552 3,680Natural gas (MMcf)1 71,622 59,779 47,498Total (MBoe) 16,899 13,515 11,596Average daily production (MBoe/d) 46.3 37.0 31.7Realized Prices2: Oil and condensate (per Bbl) $62.53 $47.78 $38.69Natural gas and natural gas liquids (per Mcf)1 $3.47 $3.19 $2.59Unit Cost per Boe: Production costs and ad valorem taxes $3.81 $3.51 $3.061As 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 unableto reliably determine the total volumes of NGLs associated with the production of natural gas on our acreage. As such, the realized prices for natural gasaccount for all value attributable to NGLs. The oil and condensate production volumes and natural gas production volumes do not include NGL volumes.2Excludes the effect of commodity derivative instruments.Productive WellsProductive 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 InterestsWell Type Gross Gross NetOil 41,557 3,909 65Natural Gas 19,702 6,010 289Total 61,259 9,919 3541 We own both mineral and royalty interests and working interests in 4,192 gross wells.13AcreageMineral and Royalty InterestsThe 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 Acreage1Gulf Coast 744,647 8,147,656 8,892,303Southwestern US 1,043,364 3,032,623 4,075,987Rocky Mountains 928,972 2,487,125 3,416,097Eastern US 82,072 1,652,381 1,734,453Mid-Continent 656,770 1,024,754 1,681,524Western US 17,489 1,038,821 1,056,310Total 3,473,314 17,383,360 20,856,6741 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 haveacquired non-operated working interests related to our mineral interests in a given tract, our working interest acreage in that tract will relate to the sameacres 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 acreageshown for another type of interest. Because of our non-operated working interests, overlap between working interest acreage and mineral and royaltyinterest acreage can be significant, while overlap between the different types of mineral and royalty interests is not significant.Working InterestsThe 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 Acreage1BSM Land Region Gross Net Gross Net Gross NetGulf Coast 218,353 36,717 214,130 59,316 432,483 96,033Southwestern US 15,910 11,632 44,969 5,998 60,879 17,630Rocky Mountains 85,384 15,411 12,548 1,309 97,932 16,720Eastern US 13,408 1,346 79 — 13,487 1,346Mid-Continent 39,636 23,840 986 20 40,622 23,860Western US — — — — — —Total 372,691 88,946 272,712 66,643 645,403 155,5891 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 ourmineral 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 ournon-operated working interests, overlap between working interest acreage and mineral and royalty interest acreage can be significant, while overlapbetween 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, whereapplicable, the net acres expiring that are subject to extension options: 2019 Expirations 2020 Expirations 2021 ExpirationsNet UndevelopedAcreage Net Acreagewithout Ext. Opt. Net Acreagewith Ext. Opt. Net Acreagewithout Ext. Opt. Net Acreagewith Ext. Opt. Net Acreagewithout Ext. Opt. Net Acreagewith Ext. Opt.66,643 3,184 501 3,829 1,234 3,267 311Drilling Results for Our Working InterestsThe following table sets forth information with respect to the number of wells completed on our properties during the periods indicated. The informationshould not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productivewells 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 2016Gross development wells: Productive 6.0 23.0 47.0Dry — — —Total 6.0 23.0 47.0Net development wells: Productive 2.5 6.1 4.7Dry — — —Total 2.5 6.1 4.7Gross 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 MattersOil and natural gas exploration, development, and production operations are subject to stringent laws and regulations governing the discharge ofmaterials into the environment or otherwise relating to protection of the environment or occupational health and safety. These laws and regulations have thepotential to impact production on our properties, which could materially adversely affect our business and our prospects. Numerous federal, state, and localgovernmental agencies, such as the U.S. Environmental Protection Agency (“EPA”), issue regulations that often require compliance measures that carrysubstantial administrative, civil, and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may requirethe acquisition of a permit before drilling commences, restrict the types, quantities, and concentrations of various substances that can be released into theenvironment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying withinwilderness, 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, requirethat additional pollution controls be installed, and impose substantial liabilities for pollution resulting from operations. The strict, joint, and several liabilitynature of such laws and regulations could impose liability upon our operators, or us as working interest owners if the operator fails to perform, regardless offault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedlycaused by the release of hazardous substances, hydrocarbons, or other waste products into the environment. In addition, many environmental statues containcitizen suit provisions, and environmental groups frequently use these provisions to oppose oil and natural gas exploration and development activities andrelated projects. The long-term trend in environmental regulation has been towards more stringent regulations, and any changes that impact our operators andresult in more stringent and costly pollution control or waste handling, storage, transport, disposal, or cleanup requirements could materially adversely affectour business and prospects. Below is a summary of environmental laws applicable to operations on our properties.Waste HandlingThe Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes and regulations promulgated thereunder, affect oiland 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 productionof oil and natural gas are exempt from regulation as hazardous wastes under RCRA, these wastes typically constitute “solid wastes” that are subject to lessstringent non-hazardous waste requirements. However, it is possible that RCRA could be amended or the EPA or state environmental agencies could adoptpolicies to require oil and natural gas exploration, development, and production wastes to become subject to more stringent waste handling requirements. Forexample, in December 2016, the EPA and environmental groups entered into a consent decree to address EPA’s alleged failure to timely assess its RCRASubtitle D criteria regulations exempting certain exploration and production related oil and natural gas wastes from regulation as hazardous wastes underRCRA. The consent decree requires EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulationspertaining 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 mustcomplete any revisions to RCRA's Subtitle D regulations by 2021. Removal of RCRA’s exemption for exploration and production wastes has the potential tosignificantly 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 regulationscould have a material adverse effect on our operators’ capital expenditures and operating expenses, which in turn could affect production from our propertiesand adversely affect our business and prospects.Remediation of Hazardous SubstancesThe Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, and analogous statelaws generally impose strict, joint, and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered tobe 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 orarranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” maybe subject to strict and joint and several liability for the costs of removing or remediating previously disposed wastes (including wastes disposed of orreleased by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs ofcertain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and16property damage allegedly caused by the hazardous substances released into the environment. Oil and natural gas exploration and production activities onour properties use materials that, if released, would be subject to CERCLA and comparable state statutes. Therefore, governmental agencies or third partiesmay seek to hold our operators, or us as working interest owners if the operator fails to perform, responsible under CERCLA and comparable state statutes forall 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 OilPollution Act (“OPA”), and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorizeddischarge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. Thedischarge 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 WaterAct 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 ruleattempting to clarify the federal jurisdictional reach over waters of the United States ("WOTUS"). Several legal challenges to the rule followed, along withattempts to stay implementation following the change in presidential administration. Currently, the WOTUS rule is active in 26 states and enjoined in 24states. 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’sjurisdiction, operations on our properties could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areasin connection with any expansion activities. In addition, spill prevention, control, and countermeasure plan requirements under federal law requireappropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tankspill, rupture, or leak. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individualpermits 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 topetroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near orcrossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to coverpotential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint, and several liability for all containment andcleanup 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 hydraulicfracturing involving the use of diesel fuels. In 2014, the EPA published draft permitting guidance governing hydraulic fracturing with diesel fuels. Inaddition, the SDWA grants the EPA broad authority to take action to protect public health when an underground source of drinking water is threatened withpollution that presents an imminent and substantial endangerment to humans, which could result in orders prohibiting or limiting the operations of oil andnatural gas production facilities. Moreover, the SDWA also regulates saltwater disposal wells under the Underground Injection Control Program. Recentconcerns related to the operation of saltwater disposal wells and induced seismicity have led some states to impose limits on the total volume of producedwater such wells can dispose of, order disposal wells to cease operations, or limited the construction of new wells. These seismic events have also resulted inenvironmental groups and local residents filing lawsuits against operators in areas where the events occur seeking damages and injunctions limiting orprohibiting saltwater disposal well construction activities and operations. A lack of saltwater disposal wells in production areas could result in increaseddisposal 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 curtailoperations.Noncompliance with the Clean Water Act, SDWA, or the OPA may result in substantial administrative, civil, and criminal penalties, as well as injunctiveobligations, all of which could affect production from our properties and adversely affect our business and prospects.Air EmissionsThe federal Clean Air Act and comparable state laws and regulations regulate emissions of various air pollutants through the issuance of permits and theimposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specifiedsources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incurcapital costs in order to remain in compliance. For example, in August 2012, the EPA adopted new regulations under the Clean Air Act that established new17emission control requirements for oil and natural gas production and processing operations. In addition, in October 2015, the EPA lowered the NationalAmbient Air Quality Standard, (“NAAQS”) for ozone from 75 to 70 parts per billion for both the 8- hour primary and secondary standards, and the agencycompleted 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 whichcould be significant. Separately, in June 2016, the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source forair-quality permitting purposes applicable to the oil and natural gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed amajor source, thereby triggering more stringent air permitting processes and requirements. These laws and regulations may increase the costs of compliancefor oil and natural gas producers and impact production on our properties, and federal and state regulatory agencies can impose administrative, civil, andcriminal 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 factorscould impact production on our properties and adversely affect our business and results of operations.Climate ChangeIn response to findings that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”) present an endangerment to public health andthe environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, require preconstructionand operating permits for certain large stationary sources. Facilities required to obtain preconstruction permits for their GHG emissions also will be requiredto meet “best available control technology” standards that will be established on a case-by-case basis. These EPA rulemakings could adversely affectoperations 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 hasadopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in theUnited States on an annual basis, which include gathering and boosting facilities as well as GHG emissions from completions and workovers of hydraulicallyfractured wells. Also, in June 2016, the EPA finalized rules that establish new air emission controls for methane emissions from certain new, modified, orreconstructed 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 isongoing. As a result, we cannot predict the scope of any final methane regulatory requirements or the cost to comply with such requirements with anycertainty. Several states, including Colorado, where we hold interests, have also adopted rules to control and minimize methane emissions from theproduction of oil and natural gas. Moreover, in response to public concerns regarding methane emissions, many operators have recently voluntarily agreed toimplement methane controls with respect to their operations. State and existing federal methane rules have substantial similarities with respect to pollutioncontrol equipment and leak detection and repair (“LDAR”) requirements. These rules could result in increased compliance costs for operations on ourproperties and require compliance expenditures to purchase pollution control equipment and hire additional personnel to assist with complying withLDAR requirements, such as increased frequency of inspections and repairs for certain processes and equipment. Consequently, these and other regulationsrelated 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 adoptedlegislation 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 capand trade programs have emerged. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in returnfor 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 emissionswould impact our business, future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our operators’ equipment andoperations could require them to incur costs to reduce emissions of GHGs associated with their operations. In addition, substantial limitations on GHGemissions could adversely affect demand for the oil and natural gas produced from our properties and lower the value of our reserves. Restrictions onemissions of methane or carbon dioxide that may be imposed in various states, as well as state and local climate change initiatives, could adversely affect theoil and natural gas industry, and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissionswould impact our business. Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding forenergy companies, which has resulted in certain financial institutions, funds, and other sources of capital restricting or eliminating their investment in oil andnatural 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 restrictmore carbon-intensive activities. While we cannot predict the outcomes of such proposals, they could ultimately make it more difficult for operators toengage 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 andwill 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 andproduction 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 climatechanges that have significant physical effects, such as increased frequency and severity of storms, floods, droughts, and other extreme climatic events; if anyof these effects were to occur, they could have a material adverse effect on our properties and operations.Hydraulic FracturingOur operators engage in hydraulic fracturing. Hydraulic fracturing is a common practice that is used to stimulate production of hydrocarbons from tightformations, including shales. The process involves the injection of water, sand, and chemicals under pressure into formations to fracture the surrounding rockand stimulate production. The process is typically regulated by state oil and natural gas commissions, but recently the EPA and other federal agencies haveasserted jurisdiction over certain aspects of hydraulic fracturing. For example, the EPA issued effluent limitation guidelines in June 2016 that prohibit thedischarge 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 reportconcluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that thefollowing hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severeimpacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals, orproduced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwaterresources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. The EPAhas 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, haveadopted 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 thedisposal 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 ofa 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 likelyto be or determined to be contributing to seismic activity, then the RRC may deny, modify, suspend, or terminate the permit application or existing operatingpermit for that well. Similarly, Oklahoma has imposed strict limits on the operation of disposal wells in areas with increased instances of induced seismicevents. These existing or any new legal requirements establishing seismic permitting requirements or similar restrictions on the construction or operation ofdisposal 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 couldhave 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 havebeen various ballot initiatives to impose strict setback requirements on oil and gas activities from certain occupied structures and environmental sensitiveareas, which could have potentially prohibited future production in areas in which we own interests. We cannot predict what additional state or localrequirements 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 legalrestrictions are adopted in areas where our operators conduct operations, our operators may incur substantial costs to comply with these requirements, whichmay be significant in nature, experience delays, or curtailment in the pursuit of exploration, development, or production activities and perhaps even beprecluded 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 fracturingfluids, impacts on drinking water supplies, use of water, and the potential for impacts to surface water, groundwater, and the environment generally. A numberof lawsuits and enforcement actions have been initiated across the country implicating hydraulic-fracturing practices. If new laws or regulations are adoptedthat significantly restrict hydraulic fracturing, those laws could make it more difficult or costly for our operators to perform fracturing to stimulate productionfrom tight formations. In addition, if hydraulic fracturing is further regulated at the federal or state level, fracturing activities on our properties could becomesubject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting andrecordkeeping obligations, plugging and abandonment requirements, and also to attendant permitting delays and potential increases in costs. Legislativechanges 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 orpotential federal or state legislation governing hydraulic fracturing.Occupational Safety and Health ActThe Occupational Safety and Health Act (“OSHA”) and comparable state laws and regulations govern the protection of the health and safety ofemployees. In addition, OSHA’s hazard communication standard, the Emergency Planning and Community Right to Know Act and implementingregulations, and similar state statutes and regulations require that information be maintained about hazardous materials used or produced in operations on ourproperties and that this information be provided to employees, state and local government authorities, and citizens.Endangered SpeciesThe 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 speciesrequired listing as threatened or endangered under the ESA. USFWS has not yet completed its review, but the potential remains for new species to be listedunder 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 previouslyunprotected species may later be designated as threatened or endangered in areas where we hold interests. For example, recently, there have been renewedcalls to review protections currently in place for the Dunes Sagebrush Lizard, whose habitat includes portions of the Permian Basin, and to reconsider listingthe 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 swathof 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 couldcause our operators to incur increased costs arising from species protection measures, delay the completion of exploration and production activities, and/orresult in limitations on operating activities that could have an adverse impact on our business.Title to PropertiesPrior to completing an acquisition of oil and natural gas properties, we perform title reviews on high-value tracts. Our title reviews are meant to confirmquantum of oil and natural gas properties being acquired, lease status, and royalties as well as encumbrances and other related burdens. Depending on themateriality of properties, we may obtain a title opinion if we believe additional title due diligence is necessary. As a result, title examinations have beenobtained on a significant portion of our properties. After an acquisition, we review the assignments from the seller for scrivener’s and other errors and executeand 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’ titlework uncover any title defects, either we or our operators will perform curative work with respect to such defects. Our operators generally will not commencedrilling 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 andrestrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and otherburdens, 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 interferewith 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 permitsfrom public authorities and private parties for us to operate our business in all material respects.20Marketing and Major CustomersIf we were to lose a significant customer, such loss could impact revenue derived from our mineral and royalty interest or working interest properties. Theloss of any single lessee is mitigated by our diversified customer base. The following table indicates our significant customers that accounted for 10% ormore of our total revenues for the periods indicated: Year Ended December 31, 2018 2017 2016XTO Energy Inc. 15.4% 20.8% 11.0%CompetitionThe oil and natural gas business is highly competitive in the exploration for and acquisition of reserves, the acquisition of minerals and oil and naturalgas leases, and personnel required to find and produce reserves. Many companies not only explore for and produce oil and natural gas, but also conductmidstream and refining operations and market petroleum and other products on a regional, national, or worldwide basis. Certain of our competitors maypossess financial or other resources substantially larger than we possess. Our ability to acquire additional minerals and properties and to discover reserves inthe future will be dependent upon our ability to identify and evaluate suitable acquisition prospects and to consummate transactions in a highly competitiveenvironment. Oil and natural gas products compete with other sources of energy available to customers, primarily based on price. These alternate sources ofenergy 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 businessconditions, conservation, legislation, regulations, and the ability to convert to alternate fuels and other sources of energy may affect the demand for oil andnatural gas. Seasonal Nature of BusinessWeather conditions affect the demand for, and prices of, natural gas and can also delay drilling activities, disrupting our overall business plans. Demandfor 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 lessenseasonal demand fluctuations. Seasonal weather conditions can limit drilling and producing activities and other oil and natural gas operations in a portion ofour operating areas. Due to these seasonal fluctuations, our results of operations for individual quarterly periods may not be indicative of the results that wemay realize on an annual basis.EmployeesWe are managed and operated by the board of directors and executive officers of our general partner. All of our employees, including our executiveofficers, are employees of Black Stone Natural Resources Management Company (“Black Stone Management”). As of December 31, 2018, Black StoneManagement had 116 full-time employees. None of Black Stone Management’s employees are represented by labor unions or covered by any collectivebargaining agreements.FacilitiesOur principal office location is in Houston, Texas and consists of 55,862 square feet of leased space.21ITEM 1A. Risk FactorsLimited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subjectare 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 makedistributions 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 BusinessWe may not generate sufficient cash from operations after establishment of cash reserves to pay the minimum quarterly distribution on our commonand subordinated units. If we make distributions, the holders of our Series B cumulative convertible preferred units have priority with respect to rightsto share in those distributions over our common and subordinated unitholders for so long as our Series B cumulative convertible preferred units areoutstanding.We may not generate sufficient cash from operations each quarter to pay the full minimum quarterly distribution to our common and subordinatedunitholders. Our Series B cumulative convertible preferred unitholders have priority with respect to rights to share in distributions over our common andsubordinated unitholders for so long as our Series B cumulative convertible preferred units are outstanding. Furthermore, our partnership agreement does notrequire us to pay distributions to our common and subordinated unitholders on a quarterly basis or otherwise. The amount of cash to be distributed eachquarter 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 dependentupon 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 reducedby principal and interest payments on our outstanding debt, working-capital requirements, and other cash needs. In addition, we may restrict distributions, inwhole or in part, to fund replacement capital expenditures, acquisitions, and participation in working interests. If over the long term we do not retain cash forreplacement capital expenditures in amounts necessary to maintain our asset base, a portion of future distributions will represent distribution of our assets andthe value of our common units could be adversely affected. Withholding cash for our capital expenditures may have an adverse impact on the cashdistributions 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 forRegistrant’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, whichmay 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 bynon-cash items. As a result, we may make cash distributions during periods in which we record net losses for financial accounting purposes and may beunable 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 cashdistributions to unitholders.Our revenues, operating results, cash distributions to unitholders, and the carrying value of our oil and natural gas properties depend significantly uponthe prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changesin 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 YearsPrior to 2019 As of December 31, High Low High2 Low3 2018 2017 2016WTI spot crude oil ($/Bbl)1 $77.41 $44.48 $107.95 $26.19 $45.15 $60.46 $53.75Henry Hub spot natural gas ($/MMBtu)1 $6.24 $2.49 $8.15 $1.49 $3.25 $3.69 $3.711 Source: EIA2 High prices for WTI and Henry Hub were in 20143 Low prices for WTI and Henry Hub were in 2016Any prolonged substantial decline in the price of oil and natural gas will likely have a material adverse effect on our financial condition, results ofoperations, and cash distributions to unitholders. We may use various derivative instruments in connection with anticipated oil and natural gas sales tominimize the impact of commodity price fluctuations. However, we cannot always hedge the entire exposure of our operations from commodity pricevolatility. To the extent we do not hedge against commodity price volatility, or our hedges are not effective, our results of operations and financial positionmay 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. Thisscenario may result in our having to make substantial downward adjustments to our estimated proved reserves, which could negatively impact our borrowingbase and our ability to fund our operations. If this occurs or if production estimates change or exploration or development results deteriorate, successfulefforts method of accounting principles may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and naturalgas properties. Our operators could also determine during periods of low commodity prices to shut in or curtail production from wells on our properties. Inaddition, they could determine during periods of low commodity prices to plug and abandon marginal wells that otherwise may have been allowed tocontinue to produce for a longer period under conditions of higher prices. Specifically, they may abandon any well if they reasonably believe that the wellcan 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 oiland natural gas revenues were derived from oil and condensate sales. Any additional decreases in prices of oil may adversely affect our cashgenerated from operations, results of operations, financial position, and our ability to pay the minimum quarterly distribution on all our outstandingcommon 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. Thereduction in price has been caused by many factors, including substantial increases in U.S. oil23production from unconventional (shale) reservoirs, with limited increases in demand. If prices for oil are depressed for an extended period of time or there arefuture 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, andsome of our undeveloped locations may no longer be economically viable. In addition, sustained low prices for oil may negatively impact the value of ourestimated proved reserves and the amount that we are allowed to borrow under our bank credit facility and reduce the amounts of cash we would otherwisehave 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 andnatural gas revenues were derived from natural gas and natural gas liquids sales. Any future decreases in prices of natural gas may adversely affectour cash generated from operations, results of operations, financial position, and our ability to pay the minimum quarterly distribution on all ouroutstanding 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 MMBtuin 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 manyfactors, including increases in natural gas production from unconventional (shale) reservoirs, without an offsetting increase in demand. The expected increasein 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 fornatural 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 naturalgas properties in addition to impairments taken during 2015 and 2016, and some of our undeveloped locations may no longer be economically viable. Inaddition, sustained low prices for natural gas may negatively impact the value of our estimated proved reserves and the amount that we are allowed to borrowunder our bank credit facility and reduce the amounts of cash we would otherwise have available to pay expenses, make distributions to our unitholders, andservice our indebtedness.Our failure to successfully identify, complete, and integrate acquisitions could adversely affect our growth, results of operations, and cashdistributions to unitholders.We depend partly on acquisitions to grow our reserves, production, and cash generated from operations. Our decision to acquire a property will dependin part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic data, and otherinformation, the results of which are often inconclusive and subject to various interpretations. The successful acquisition of properties requires an assessmentof 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 withthese assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not revealall 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 necessarilyobservable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractualprotection against all or part of the problems. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition ordo 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 refrainfrom, 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 andresources in compliance activities, and potentially increase our operators’ exposure to penalties or fines for non-compliance with additional legalrequirements. Further, the process of integrating acquired assets may involve unforeseen difficulties and may require a disproportionate amount of ourmanagerial and financial resources.24No assurance can be given that we will be able to identify suitable acquisition opportunities, negotiate acceptable terms, obtain financing foracquisitions on acceptable terms, or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businessesand assets into our existing operations successfully, or to minimize any unforeseen operational difficulties could have a material adverse effect on ourfinancial condition, results of operations, and cash distributions to unitholders. The inability to effectively manage the integration of acquisitions couldreduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our growth, results of operations, and cashdistributions 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 adecrease 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, andcosts;•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 royaltyinterests and non-operated working interests. Substantially all our revenue is derived from the sale of oil and natural gas production from producingwells 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 acreageby these operators or the failure of our operators to adequately and efficiently develop and operate our acreage could have an adverse effect on ourresults 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 fromover 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 bestinterests could reduce production and revenues. Our operators are often not obligated to undertake any development activities other than those required tomaintain their leases on our acreage. In the absence of a specific contractual obligation, any development and production activities will be subject to theirreasonable discretion. Our operators could determine to drill and complete fewer wells on our acreage than is currently expected. The success and timing ofdrilling and development activities on our properties, and whether the operators elect to drill any additional wells on our acreage, depends on a number offactors 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.25The operators may elect not to undertake development activities, or may undertake these activities in an unanticipated fashion, which may result insignificant fluctuations in our results of operations and cash distributions to our unitholders. Sustained reductions in production by the operators on ourproperties 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 EastTexas, where we own a concentrated, relatively high-interest royalty position; we expect that these operators will continue to conduct significant operationsin this area for the foreseeable future in accordance with contractual arrangements. Geographic and operator concentration heightens the effect of operationalrisks, 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 TroughIf any of these risks are realized and production is not replaced by another operator in this area or another area, production may decrease, reducing cashgenerated 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 notbe 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 paymentobligations under the lease. If we repossessed any of our properties, we would seek a replacement operator. However, we might not be able to find areplacement 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, theoutgoing 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 orterminate the lease for any defaults, including non-payment, may be substantially delayed or otherwise impaired. In general, in a proceeding under theBankruptcy Code, the bankrupt operator would have a substantial period of time to decide whether to ultimately reject or assume the lease, which couldprevent 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 tocollect 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 areable 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 thesame 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, andwe 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 theacquisition of mineral and royalty interests and participation in our non-operated working interests. To date, we have financed capital expenditures primarilywith funding from cash generated by operations, limited borrowings under our credit facility, executed farmout agreements, and the issuance of equitysecurities.In the future, we may restrict distributions to fund acquisitions and participation in our working interests but eventually we may need capital in excess ofthe 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 termsfavorable to us or at all. If we are unable to fund our capital requirements, we may be unable to complete acquisitions, take advantage of businessopportunities, or respond to competitive pressures, any of which could have a material adverse effect on our results of operation and cash distributions tounitholders.Most of our operators are also dependent on the availability of external debt and equity financing sources to maintain their drilling programs. If thosefinancing 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. Ifthe development of our properties is adversely affected, then revenues from our mineral and royalty interests and non-operated working interests may decline.26Unless we replace the oil and natural gas produced from our properties, our cash generated from operations and our ability to make distributions toour 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 arehighly dependent on the successful development and exploitation of our current reserves. The production decline rates of our properties may be significantlyhigher 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 additionalreserves to replace the current and future production of our properties at economically acceptable terms, which would adversely affect our business, financialcondition, 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 workinginterests.Our proved undeveloped reserves may not be developed or produced. Recovery of proved undeveloped reserves requires significant capital expendituresand successful drilling operations, and the decision to pursue development of a proved undeveloped drilling location will be made by the operator and notby us. The reserve data included in the reserve report of our engineer assume that substantial capital expenditures are required to develop the reserves. Wecannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled, or that the results ofthe development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop our reserves, or decreases incommodity 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 projectareas 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 aredrilled, 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 theirdrilling.The ability of our operators to drill and develop identified potential drilling locations depends on a number of uncertainties, including the availabilityof capital, construction of infrastructure, inclement weather, regulatory changes and approvals, oil and natural gas prices, costs, drilling results, and theavailability of water. Further, our operators’ identified potential drilling locations are in various stages of evaluation, ranging from locations that are ready todrill to locations that will require substantial additional interpretation. The use of technologies and the study of producing fields in the same area will notenable 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 insufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, our operators may damage the potentially productivehydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in productionfrom 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, theirdrilling 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, orproducing fields will be applicable to their drilling locations. Further, initial production rates reported by our or other operators in the areas in which ourreserves are located may not be indicative of future or long-term production rates. Because of these uncertainties, we do not know if the potential drillinglocations 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 potentialdrilling locations. As such, the actual drilling activities of our operators may materially differ from those presently identified, which could adversely affectour business, results of operation, and cash distributions to unitholders.27The unavailability, high cost, or shortages of rigs, equipment, raw materials, supplies, or personnel may restrict or result in increased costs foroperators 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 otherproppants), supplies, and personnel. When shortages occur, the costs and delivery times of rigs, equipment, and supplies increase and demand for, and wagerates of, qualified drilling rig crews also rise with increases in demand. In accordance with customary industry practice, our operators rely on independentthird-party service providers to provide many of the services and equipment necessary to drill new wells. If our operators are unable to secure a sufficientnumber 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 coulddelay or restrict our operators’ exploration and development operations, which in turn could have a material adverse effect on our financial condition, resultsof 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 ofour operators control. Any limitation in the availability of those facilities could interfere with our or our operators’ ability to market our or ouroperators’ 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 othertransportation methods, and processing and refining facilities owned by third parties. The amount of oil that can be produced and sold is subject tocurtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage, orlack of available capacity on these systems, tanker truck availability, and extreme weather conditions. Also, the shipment of our or our operators’ oil andnatural gas on third-party pipelines may be curtailed or delayed if it does not meet the quality specifications of the pipeline owners. The curtailments arisingfrom 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 ofoperations, and cash distributions to unitholders. Our or our operators’ access to transportation options and the prices we or our operators receive can also beaffected by federal and state regulation—including regulation of oil production, transportation, and pipeline safety—as well by general economic conditionsand 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 orunderlying 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 andassumptions concerning future oil and natural gas prices, production levels, ultimate recoveries, and operating and development costs. As a result, estimatedquantities of proved reserves, projections of future production rates, and the timing of development expenditures may be incorrect. Our estimates of provedreserves and related valuations as of December 31, 2018, 2017, and 2016 were prepared by NSAI, a third-party petroleum engineering firm, which conducteda 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 materialchanges to reserve estimates taking into account the results of actual drilling, testing, and production. Also, certain assumptions regarding future oil andnatural gas prices, production levels, and operating and development costs may prove incorrect. Any significant variance from these assumptions to actualfigures could greatly affect our estimates of reserves and future cash generated from operations. Numerous changes over time to the assumptions on which ourreserve estimates are based, as described above, often result in the actual quantities of oil and natural gas that are ultimately recovered being different fromour 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 ofhydrocarbon 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 possiblereserves that may exist, nor do they include any value for unproved undeveloped acreage.28Conservation measures, technological advances, and general concern about the environmental impact of the production and use of fossil fuels couldmaterially 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 infuel economy, and energy-generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gasservices and products may have a material adverse effect on our business, financial condition, results of operations, and cash distributions to unitholders. It isalso possible that the concerns about the production and use of fossil fuels will reduce the number of investors willing to own our common units, adverselyaffecting 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 ourbusiness. 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 “keyperson” 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 deathof 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 maynot 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 drillinghorizontal wells, operators risk not landing the well bore in the desired drilling zone and straying from the desired drilling zone. When drilling horizontallythrough 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 equipmentconsistently through the horizontal well bore. Risks that our operators face while completing wells include being unable to fracture stimulate the plannednumber 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 finalfracture stimulation stage. In addition, to the extent our operators engage in horizontal drilling, those activities may adversely affect their ability tosuccessfully drill in identified vertical drilling locations. Furthermore, certain of the new techniques that our operators may adopt, such as infill drilling andmulti-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 ofmulti-well pad drilling, the time required to drill and complete multiple wells before these wells begin producing. The results of drilling in new or emergingformations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer oremerging formations and areas often have limited or no production history and consequently our operators will be less able to predict future drilling results inthese areas.Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles areestablished over a sufficiently long time period. If our operators’ drilling results are weaker than anticipated or they are unable to execute their drillingprogram 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 developmentswe could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline, and our results ofoperations 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 beburdensome 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 changedfrom time to time in response to economic and political conditions. Matters subject to regulation include drilling operations, production and distributionactivities, discharges or releases of pollutants or wastes, plugging and abandonment of wells, maintenance and decommissioning of other facilities, thespacing of wells, unitization and pooling of properties, and taxation. From time to time, regulatory agencies have imposed price controls and limitations onproduction 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 underfederal, state, and local laws and regulations primarily relating to protection of worker health and safety, natural resources, and the environment. Failure tocomply 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 all29of the operations on our properties. Moreover, these laws and regulations have generally imposed increasingly strict requirements related to water use anddisposal, 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 lawsand 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 mayrequire increased capital costs for third-party oil and natural gas transporters. These transporters may attempt to pass on such costs to our operators, which inturn 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 ofour properties are shippers on interstate pipelines, they must comply with the tariffs of those pipelines and with federal policies related to the use of interstatecapacity.Our operators may be required to make significant expenditures to comply with the governmental laws and regulations described above. We believe thetrend 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 regulationscould 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 areseparated from the ownership of the surface, whether by sale or reservation. These mineral servitudes, once created, are subject to a ten-year prescription ofnonuse. During the ten-year period, the mineral-servitude owner has to conduct good-faith operations on the servitude for the discovery and production ofminerals, or the mineral servitude “prescribes,” and the mineral rights associated with that servitude revert to the surface owner. A good-faith operation for thediscovery and production of minerals, even one resulting in a dry hole, conducted within the ten-year period will interrupt the prescription of nonuse andrestart the running of the ten-year prescriptive period. If the operation results in production, prescription is interrupted as long as the production continues oroperations are conducted in good faith to secure or restore production. If any of our mineral servitudes are prescribed by operation of Louisiana law, ouroperating results may be adversely affected.Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs, additional operatingrestrictions 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 tightformations, including shales. The process involves the injection of water, sand, and chemicals under pressure into formations to fracture the surrounding rockand 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 andnatural gas commissions. The EPA however, has recently taken the position that hydraulic fracturing with fluids containing diesel fuel is subject toregulation under the UIC program and issued permitting guidance in February 2014 applicable to hydraulic fracturing involving the use of diesel fuel. TheEPA has also issued effluent limitation guidelines in June 2016 to prohibit the discharge of wastewater from hydraulic fracturing operations to publiclyowned 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 reportconcluded that “water cycle” associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that thefollowing hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severeimpacts: water withdrawals for30fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals, or produced water; injection offracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequatelytreated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. The EPA has not proposed to take any actionin 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 ofhydraulic-fracturing fluids. For example, in Texas, the Texas Railroad Commission ("RRC") published a final rule in October 2014 governing permitting orre-permitting of disposal wells that require, among other things, the submission of information on seismic events occurring within a specified radius of thedisposal 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 adisposal 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 likelyto be or determined to be contributing to seismic activity, then the RRC may deny, modify, suspend, or terminate the permit application or existing operatingpermit for that well. Similarly, Oklahoma has imposed strict limits on the operation of disposal wells in areas with increased instances of induced seismicevents. These existing or any new legal requirements establishing seismic permitting requirements or similar restrictions on the construction or operation ofdisposal 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 couldhave 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 havebeen various ballot initiatives to impose strict setback requirements on oil and gas activities from certain occupied structures and environmental sensitiveareas, which could have potentially prohibited future production in areas in which we own interests. We cannot predict what additional state or localrequirements 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 legalrestrictions are adopted in areas where our operators conduct operations, our operators may incur substantial costs to comply with these requirements, whichmay be significant in nature, experience delays, or curtailment in the pursuit of exploration, development, or production activities and perhaps even beprecluded 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 fracturingfluids, impacts on drinking water supplies, use of water, and the potential for impacts to surface water, groundwater, and the environment generally. A numberof lawsuits and enforcement actions have been initiated across the country implicating hydraulic-fracturing practices. If new laws or regulations are adoptedthat significantly restrict hydraulic fracturing, those laws could make it more difficult or costly for our operators to perform fracturing to stimulate productionfrom tight formations. In addition, if hydraulic fracturing is further regulated at the federal or state level, fracturing activities on our properties could becomesubject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting andrecordkeeping obligations, plugging and abandonment requirements, and also to attendant permitting delays and potential increases in costs. Legislativechanges 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 orpotential 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 paydistributions.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 theirvaluation of our proved reserves and their internal criteria. The borrowing base is redetermined at least semi-annually, and the available borrowing amountcould 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 basedetermined 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 inexcess 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 asadditional collateral, within 30 days following notice from the administrative agent of the new or adjusted borrowing base. If we do not have sufficient fundson 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. Wemay 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 couldresult in a default under our credit facility, which could materially adversely affect our business, financial condition, results of operations, and distributionsto our unitholders.31The operating and financial restrictions and covenants in our credit facility restrict, and any future financing agreements likely will restrict, our ability tofinance future operations or capital needs, engage in, expand, or pursue our business activities, or pay distributions. Our credit facility restricts, and any futurecredit 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 notrestricted 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 andcovenants 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, suchas 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 ourindebtedness may become immediately due and payable, our ability to make distributions will be inhibited, and our lenders’ commitment to make furtherloans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations underour 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 toforeclose 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 thatour operators produce.In response to findings that emissions of carbon dioxide, methane, and other greenhouse gases ("GHGs") present an endangerment to public health andthe environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, require preconstructionand operating permits for certain large stationary sources. Facilities required to obtain preconstruction permits for their GHG emissions also will be requiredto meet “best available control technology” standards that will be established on a case-by-case basis. These EPA rulemakings could adversely affectoperations 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 hasadopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in theUnited States on an annual basis, which include gathering and boosting facilities as well as GHG emissions from completions and workovers of hydraulicallyfractured wells. Also, in June 2016, the EPA finalized rules that establish new air emission controls for methane emissions from certain new, modified, orreconstructed 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 isongoing. As a result, we cannot predict the scope of any final methane regulatory requirements or the cost to comply with such requirements with anycertainty. Several states, including Colorado, where we hold interests, have also adopted rules to control and minimize methane emissions from theproduction of oil and natural gas. Moreover, in response to public concerns regarding methane emissions, many operators have recently voluntarily agreed toimplement methane controls with respect to their operations. State and federal methane rules have substantial similarities with respect to pollution controlequipment and leak detection and repair (“LDAR”) requirements. These rules could result in increased compliance costs for our operators and require them tomake expenditures to purchase pollution control equipment and hire additional personnel to assist with complying with LDAR requirements, such asincreased frequency of inspections and repairs for certain processes and equipment. Consequently, these and other regulations related to controlling GHGemissions 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 adoptedlegislation 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 andtrade programs have emerged. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return foremitting those GHGs. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissionswould32impact our business, any future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our operators’ equipment andoperations could require them to incur costs to reduce emissions of GHGs associated with their operations. In addition, substantial limitations on GHGemissions could adversely affect demand for the oil and natural gas produced from our properties and lower the value of our reserves. Restrictions onemissions of methane or carbon dioxide that may be imposed in various states, as well as state and local climate change initiatives, could adversely affect theoil and natural gas industry, and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissionswould impact our business. Moreover, activists concerned about the potential effects of climate change have directed their attention at sources of funding forenergy companies, which has resulted in certain financial institutions, funds, and other sources of capital restricting or eliminating their investment in oil andnatural 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 restrictmore carbon-intensive activities. While we cannot predict the outcomes of such proposals, they could ultimately make it more difficult for operators toengage in exploration and production activities. Notwithstanding potential risks related to climate change, the International Energy Agency estimates thatglobal 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 ofglobal energy use over that time. Exploration and production activities are capital intensive, and capital constraints of our operators could have a materialadverse impact on production from our properties. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs inthe 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 ofoperations 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 hazardsand 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 environmentalhazards such as oil spills, natural gas leaks and ruptures, or discharges of toxic gases. In addition, their operations will be subject to risks associated withhydraulic fracturing, including any mishandling, surface spillage, or potential underground migration of fracturing fluids, including chemical additives. Theoccurrence 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 ofoperations, 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. Ourinsurance 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 maybe at premium levels that do not justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limitsmaintained 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 normalbusiness operations and on our financial condition, results of operations, or cash distributions to unitholders. In addition, we may not be able to secureadditional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severelyimpact our financial position. We may also be liable for environmental damage caused by previous owners of properties purchased by us, which liabilitiesmay 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 providerswithin 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. Inaddition, these policies do not provide coverage for all liabilities, and we cannot assure our unitholders that the insurance coverage will be adequate to coverclaims 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 havea 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 oftitle 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, wewill suffer a financial loss.33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 andnatural gas mineral interests in the United States, we rely on electronic systems and networks to control and manage our business and have multiple layers ofsecurity to monitor, mitigate and manage these risks. However, these systems and networks, as well as our operators’ systems and networks and third-partyinfrastructure and operations, such as pipelines and transportation facilities, may be subject to sophisticated and deliberate security attacks and securitybreaches, which could lead to the corruption or loss of sensitive and valuable data, delays in production or delivery, difficulty in completing and settlingtransactions, challenges in maintaining our books and records, environmental damage, communication interruptions, material adverse effects on ourreputation or financial position and other operational disruptions and third-party liabilities, including the cost of remedial actions. Cyber attacks and databreaches in particular are becoming more sophisticated and include, but are not limited to, malicious software, ransomware, attempts to gain unauthorizedaccess 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 andsecurity measures failed, the potential consequences to our businesses and the communities in which we operate could be significant. In addition, our effortsto monitor, mitigate and manage these evolving risks may result in increased capital and operating costs, but there can be no assurance that such efforts willbe sufficient to prevent attacks or breaches from occurring. Risks Inherent in an Investment in UsWe expect to distribute a substantial majority of the cash we generate from operations each quarter, which could limit our ability to grow and makeacquisitions.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 fromoperations to reinvest in our business or to fund acquisitions, and we will rely primarily upon external financing sources, including commercial bankborrowings and the issuance of debt and equity securities, to fund our acquisitions and growth capital expenditures. If we are unable to finance growthexternally, 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 unitsmay 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 unitsranking senior or on parity with our Series B cumulative convertible preferred units, there are no limitations in our partnership agreement on our ability toissue additional units, including units ranking senior to the common units with respect to distributions. The incurrence of additional commercial borrowingsor other debt to finance our growth would result in increased interest expense and required principal repayments, which, in turn, may reduce the cash that wehave available to distribute to our unitholders. Please read Part II, Item 5. “Market for Registrant’s Common Equity, Related Unitholder Matters, and IssuerPurchases 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 partnershipagreement does not require us to pay any distributions at all on our common and subordinated units. If we make distributions, our Series B cumulativeconvertible unitholders have priority with respect to rights to share in those distributions over our common and subordinated unitholders for so longas 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 anydistributions each quarter as follows: (i) first, to the holders of Series B cumulative convertible preferred units equal to 7% per annum, subject to certainadjustments, (ii) second, to the holders of common units, until each common unit has received the applicable minimum quarterly distribution plus anyarrearages from prior quarters, and (iii) third, to the holders of subordinated units, until each subordinated unit has received the applicable minimum quarterlydistribution. If the distributions to our common and subordinated unitholders exceed the applicable minimum quarterly distribution per unit, then suchexcess amounts will be distributed pro rata on the common and subordinated units as if they were a single class. Our minimum quarterly distribution is $1.35per 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 andthereafter. We expect that we will distribute a substantial majority of the cash we generate from operations each quarter. However, the board of directors of ourgeneral 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 placeundue reliance on the permanence of any distribution policy in making an investment decision. Any34modification or revocation of our cash distribution policy could substantially reduce or eliminate the amounts of distributions to our unitholders. Theamount 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. Ifwe make distributions, our Series B cumulative convertible preferred unitholders have priority with respect to rights to share in those distributions over ourcommon and subordinated unitholders for so long as our Series B cumulative convertible preferred units are outstanding. Please read Part II, Item 5. “Marketfor Registrant’s Common Equity, Related Unitholder Matters, and Issuer Purchases of Equity Securities — Cash Distribution Policy — Series B CumulativeConvertible Preferred Units.”Our minimum quarterly distribution provides the common unitholders a specified priority right to distributions over the subordinated unitholders if wepay 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 minimumquarterly distribution merely provides the common unitholders with a specified priority right to distributions before the subordinated unitholders receivedistributions, 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 ofour 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 numberof outstanding common and subordinated units for a period of four consecutive, non-overlapping quarters ending on or after March 31, 2019, and there areno 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 testdescribed above, the subordinated units will convert into common units on a one-to-one basis. If holders of the common units resulting from conversionattempt 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 prioritywith 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 distributionfrom 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 minimumquarterly 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 maymodify 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 ourcommon and subordinated units. If we make distributions, our Series B cumulative convertible preferred unitholders have priority with respect to rights toshare in those distributions over our common and subordinated unitholders for so long as our Series B cumulative convertible preferred units areoutstanding."Our partnership agreement eliminates the fiduciary duties that might otherwise be owed to the partnership and its partners by our general partner andits 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 directorsand executive officers. For example, our partnership agreement provides that our general partner and its directors and executive officers have no duties to thepartnership or its partners except as expressly set forth in the partnership agreement. In place of default fiduciary duties, our partnership agreement imposes acontractual standard requiring our general partner and its directors and executive officers to act in good faith, meaning they cannot cause the general partnerto take an action that they subjectively believe is adverse to our interests. Such contractual standards allow our general partner and its directors and executiveofficers to manage and operate our business with greater flexibility and to subject the actions and determinations of our general partner and its directors andexecutive officers to lesser legal or judicial scrutiny than would be the case if state law fiduciary standards were applicable.35Our partnership agreement restricts the situations in which remedies may be available to our unitholders for actions taken that might constitutebreaches 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 ourlimited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determiningthat 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 theknowledge 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 classof units then outstanding, other than the limited partners in BSMC prior to the IPO, their transferees, persons who acquired such units with the prior approvalof the board of directors of our general partner, holders of Series B cumulative convertible preferred units in connection with any vote, consent or approval ofthe 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 orpurchase 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 inconnection 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 oraccelerate 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 suchmatters 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 thepurpose 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 fromoperations, in order to permit the payment of distributions on subordinated units. All these actions may affect the amount of cash distributed to ourunitholders 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 andour 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, wehave 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 closingprice 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 highestper-unit price paid by us or any of our36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 ofour 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 DelawareAct, 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 lawprovides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at thetime of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Liabilities to partners on account oftheir partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution ispermitted.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 equityinvestments such as our common units. Any such increase in interest rates or reduction in demand for our common units resulting from other investmentopportunities 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 holdersof common and subordinated units. However, subject to certain exceptions, our partnership agreement does not authorize us to issue units rankingsenior 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 theunitholders other than, in certain instances, approval of holders of our Series B cumulative convertible preferred units. Our issuance of additional commonunits 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 overor on a parity with the Series B cumulative convertible preferred units with respect to rights to share in distributions, redemption obligations, or redemptionrights 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 privatemarkets.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 convertiblepreferred 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 subordinationperiod. 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 thesecond anniversary of November 28, 2017. Under certain conditions, we may elect to convert all or any portion of the Series B cumulative convertiblepreferred units into common units at any time after the second anniversary of November 28, 2017. Sales by holders of a substantial number of our commonunits 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 ourability to obtain capital through an offering of equity securities.37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 inthese 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 theIPO. In addition, the Sarbanes-Oxley Act, as well as rules implemented by the SEC and the NYSE, require publicly traded entities to maintain variouscorporate governance practices that further increase our costs. Before we are able to make distributions to our unitholders, we must first pay or reserve for ourexpenses, 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 beaffected 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”). Theserequirements 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 ofour units.Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud, and operate successfully as a publicly tradedpartnership. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain thatour efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processesand 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 404requires us, among other things, to annually review and report on, and our independent registered public accounting firm to attest to, the effectiveness of ourinternal controls over financial reporting. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing orimproving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could alsocause 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 ofdirectors or to establish a compensation committee or a nominating and corporate governance committee. In addition, because we are a publicly tradedpartnership, the NYSE does not require us to obtain unitholder approval prior to certain unit issuances. Accordingly, unitholders will not have the sameprotections 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 isirrevocably consenting to these provisions regarding claims, suits, actions, or proceedings, and submitting to the exclusive jurisdiction of Delawarecourts.Our partnership agreement is governed by Delaware law. Our partnership agreement includes exclusive forum, venue, and jurisdiction provisionsdesignating Delaware courts as the exclusive venue for all claims, suits, actions, or proceedings arising out of or relating in any way to the partnershipagreement, 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 pursuantto any provision of the Delaware Act, or asserting a claim governed by the internal affairs doctrine. By purchasing a common unit, a limited partner isirrevocably consenting to these provisions regarding claims, suits, actions, or proceedings and submitting to the exclusive jurisdiction of Delaware courts. Ifa 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 legalremedies in Delaware, which may be an inconvenient or distant location and which is considered to be a more corporate-friendly environment. 38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 whoseowners’, 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 customersand (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 ofcounsel. If an investor is not an Eligible Holder, in certain circumstances as set forth in our partnership agreement, units held by such investor may beredeemed 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 generalpartner.Tax Risks to Common UnitholdersOur 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 becomesubject 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. federalincome 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 taxpurposes unless we satisfy a “qualifying income” requirement. Based upon our current operations and current Treasury Regulations, we believe that wesatisfy 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 matteraffecting 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. federalincome 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 taxrate. Distributions to our common unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, or deductions wouldflow through to our common unitholders. Because a tax would be imposed upon us as a corporation, cash distributions to our common unitholders would besubstantially reduced. In addition, changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespreadstate budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of stateincome, 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 theanticipated cash generated from operations and after-tax return to the common unitholders, likely causing a substantial reduction in the value of our commonunits.The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial, oradministrative 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 byadministrative, legislative, or judicial changes or differing interpretations at any time. From time to time, members of Congress propose and consider similarsubstantive changes to the existing U.S. federal income tax laws that would affect publicly traded partnerships, including a prior legislative proposal thatwould have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for ourtreatment 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 incometax 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 thefuture.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 theexception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any ofthese changes or other proposals will ultimately be enacted or adopted. Any such changes could negatively impact the value of an investment in our commonunits. You are urged to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals and theirpotential effect on your investment in our common units.39Future legislation may result in the elimination of certain U.S. federal income tax deductions currently available with respect to oil and natural gasexploration and production. Additionally, future federal or state legislation may impose new or increased taxes or fees on oil and natural gasextraction.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. federalincome tax provisions currently available to oil and gas companies. Such legislative changes have included, but not been limited to, (i) the repeal of thepercentage 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 orall 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 reformlegislation including changes to cost recovery rules and to the deductibility of interest expense may be developed that also would change the taxation of oiland 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 passageof 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 thatcurrently 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 adverseeffect 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 anysuch 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 matteraffecting 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 sustainsome 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 adverselyaffect 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 reductionin 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 andcollect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case cash availablefor distribution to our common unitholders might be substantially reduced and our current and former common unitholders may be required toindemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such commonunitholders' 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 taxreturn, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directlyfrom 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 anaudited and adjusted return. Although our general partner may elect to have our common unitholders and former common unitholders take such auditadjustment into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their interests in us during the tax yearunder audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current commonunitholders 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 usduring 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 availablefor distribution to our common unitholders might be substantially reduced and our current and former common unitholders may be required to indemnify usfor 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 taxableincome.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 ornot 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 beallocated taxable income and gain resulting from the sale and our cash available for distribution would not increase. Similarly, taking advantage ofopportunities 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 ourcommon unitholders as taxable income without any increase in our cash available for distribution. You may not receive cash distributions from us equal toyour 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 commonunits. 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, ofprior 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 pricegreater 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 realizedincludes 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 ofcash 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 toyou due to potential recapture items, including depreciation recapture. Thus, you may recognize both ordinary income and capital loss from the sale of yourcommon 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 offsetcapital 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 mayrecognize ordinary income from our allocations of income and gain to you occurring prior to the sale and from recapture items that generally cannot be offsetby 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 issuesunique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and otherretirement 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 morethan one unrelated trade or business (including by attribution from investment in a partnership such as ours) is required to compute the unrelated businesstaxable income of such tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating lossdeduction). 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 ourpartnership to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax-exempt entities should consult a taxadvisor 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 connectedwith a U.S. trade or business (“effectively connected income”). Income allocated to our common unitholders and any gain from the sale of our common unitswill 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 besubject 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 willalso 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 ofan interest in a partnership that is engaged in a U.S. trade or business. However, due to challenges of administering a withholding obligation applicable toopen market trading and other complications, the IRS has temporarily suspended the application of this withholding rule to open market transfers of interestsin publicly traded partnerships pending promulgation of regulations or other guidance that resolves the challenges. It is not clear if or when such regulationsor other guidance will be issued. Non-U.S. common unitholders should consult a tax advisor before investing in our common units.41We treat each purchaser of common units as having the same tax benefits without regard to the common units actually purchased. The IRS maychallenge 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 amortizationpositions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect theamount 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 couldhave 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 uponthe 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 IRSmay 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 theownership 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 istransferred. Similarly, we generally allocate certain deductions for depreciation of capital additions, gain or loss realized on a sale or other disposition of ourassets and, in the discretion of the general partner, any other extraordinary item of income, gain, loss, or deduction based upon ownership on the AllocationDate. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our prorationmethod. 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 amongour 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 thosecommon 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 whosecommon 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 mayno 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 commonunitholder may recognize gain or loss from this disposition. Moreover, during the period of the loan, any of our income, gain, loss, or deduction with respectto those common units may not be reportable by the common unitholder and any cash distributions received by the common unitholder as to those commonunits could be fully taxable as ordinary income. Common unitholders desiring to assure their status as partners and avoid the risk of gain recognition from asecurities 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 ofinvesting 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 andestate, inheritance, or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, evenif 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 alsoimpose 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 taxesin 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 toroyalty 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 adeduction 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 royaltyincome as qualifying for the deduction. Although our counsel has advised us that under current law our royalty income should qualify for the deduction, noassurances can be given that the IRS will not challenge our treatment of royalty income as qualifying for the deduction.42ITEM 1B. UNRESOLVED STAFF COMMENTSNone.ITEM 3. LEGAL PROCEEDINGSAlthough 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 believethat the resolution of these matters will have a material adverse impact on our financial condition or results of operations.ITEM 4. MINE SAFETY DISCLOSURESNot applicable.43PART IIITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITYSECURITIESOur 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 commonunits 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 Unit2017 First Quarter $19.55 $15.58 $0.2875 $0.18375Second Quarter $17.21 $15.12 $0.3125 $0.20875Third Quarter $17.92 $15.52 $0.3125 $0.20875Fourth Quarter $18.57 $16.71 $0.3125 $0.20875 2018 First Quarter $19.03 $16.36 $0.3125 $0.20875Second Quarter $19.01 $16.40 $0.3375 $0.33750Third Quarter $19.29 $17.02 $0.3700 $0.37000Fourth Quarter $18.59 $15.23 $0.3700 $0.370001 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 heldby brokers and other institutions on behalf of unitholders, we are unable to estimate the total number of unitholders represented by these holders of record. Asof February 19, 2019, we also had outstanding 96,328,836 subordinated units and 14,711,219 Series B cumulative convertible preferred units. There is noestablished public market in which the subordinated units or the Series B cumulative convertible preferred units are traded.44Common Unit Performance GraphThe 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 unitswas $100.00 on April 30, 2015. Cumulative return is computed assuming reinvestment of distributions. Comparison of Cumulative Total ReturnAssumes Initial Investment of $100 As of December 31, As of April 30, 2015 2015 2016 2017 2018Black Stone Minerals, L.P. $100.00 $78.22 $109.07 $110.89 $101.80S&P 500 Index 100.00 99.47 111.37 135.69 129.74Alerian MLP Index 100.00 66.99 79.25 74.08 64.88The information in this Annual Report appearing under the heading “Common Unit Performance Graph” is being furnished pursuant to Item 201(e) ofRegulation 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 providedin Item 201(e) of Regulation S-K, or to the liabilities of Section 18 of the Exchange Act.45Securities Authorized for Issuance under Equity Compensation PlansSee the information incorporated by reference under “Part III, Item 12. Security Ownership of Certain Beneficial Owners and Management and RelatedUnitholder Matters” regarding securities authorized for issuance under our equity compensation plans.Recent Sales of Unregistered SecuritiesOn 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 PurchasersThe following tables set forth our purchases of our common units for each month during the three months ended December 31, 2018:Purchases of Common UnitsPeriod Total Number of Common UnitsPurchased Average PricePaid Per Unit Total Number of Common UnitsPurchased as Part of PubliclyAnnounced Plans or Programs2 Maximum Dollar Value ofCommon Units That May YetBe Purchased Under the Plansor ProgramsDecember 1 – December 31, 2018 137,0851 $15.67 128,627 $72,992,5431 Includes units withheld to satisfy tax withholding obligations upon the vesting of certain restricted common units held by our executive officers andcertain 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 repurchaseprogram authorizes us to make repurchases on a discretionary basis as determined by management, subject to market conditions, applicable legalrequirements, available liquidity, and other appropriate factors. All or a portion of any repurchases may be made under a Rule 10b5-1 plan, which wouldpermit common units to be repurchased when we might otherwise be precluded from doing so under insider trading laws. The repurchase program does notobligate 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 PolicyOur 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 specifiedbelow 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.46If the distributions to our common and subordinated unitholders exceed the applicable minimum quarterly distribution per unit, then such excessamounts 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 andthereafter. The minimum quarterly distribution does not provide the common unitholders the right to require payment of any distributions. It merely reflectsthe 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 quarterafter 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 ouroperations each quarter. The cash generated from operations for each quarter will generally equal our Adjusted EBITDA for the quarter, less cash needed fordebt service, other contractual obligations, fixed charges, and reserves for future operating or capital needs that the board of directors may determine areappropriate. 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 fromoperations, borrowings under our credit facility, our executed farmout agreements, and, in certain circumstances, proceeds from future equity and debtissuances. We may also borrow to make distributions to our unitholders where, for example, we believe that the distribution level is sustainable over the longterm, but short-term factors may cause cash generated from operations to be insufficient to pay distributions at the applicable minimum quarterly distributionlevel 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 anytime 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 andsubordinated units. Please read Part I, Item 1A. “Risk Factors — Risks Inherent in an Investment in Us — The board of directors of our general partner maymodify 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 ourcommon and subordinated units. If we make distributions, our Series B cumulative convertible preferred unitholders have priority with respect to rights toshare in those distributions over our common and subordinated unitholders for so long as our Series B cumulative convertible preferred units areoutstanding.” For a description of the relative rights and privileges of our Series B cumulative convertible preferred units to distributions, please read "SeriesB 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 baseover 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 anamount equal to our estimated replacement capital requirements. We believe the level of our distribution rate will allow us to retain in our business sufficientcash generated from our operations to satisfy our replacement capital expenditure needs and to fund a portion of our growth capital expenditures. The boardof 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; therewas no established estimate of replacement capital prior to this period. On June 8, 2017, the board of directors established a replacement capital expenditureestimate 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 capitalexpenditure 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 PolicyThere 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 ofdirectors 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 exceedsdistributions 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 loansunder 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 acurrent 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 creditfacility 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, thosereserves could result in a reduction in cash distributions to our unitholders. Our47partnership agreement does not limit the amount of cash reserves that our general partner may establish. Any decision to establish cash reserves madeby 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 ourassets.•We may lack sufficient cash to pay distributions to our unitholders due to shortfalls in cash generated from operations attributable to a number ofoperational, commercial, or other factors as well as increases in our operating or general and administrative expenses, principal and interest paymentson 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 borrowunder 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 commonand subordinated units is that, for any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distributionuntil the holders of the common units have received the applicable minimum quarterly distribution for such quarter plus any arrearages in the payment of theminimum quarterly distribution from prior quarters. Subordinated units do not accrue arrearages. Our common unitholders are only entitled to arrearages inthe payment of the minimum quarterly distribution from prior quarters during the subordination period. To the extent we have cash generated from operationsavailable for distribution in any quarter during the subordination period in excess of the amount necessary to pay the applicable minimum quarterlydistribution to holders of our common units, we will use this excess cash to pay any distribution arrearages on the common units related to prior quartersbefore 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 annualizedminimum quarterly distribution applicable for quarterly periods ending March 31, 2019 and thereafter) multiplied by the total number of outstandingcommon and subordinated units for a period of four consecutive, non-overlapping quarters ending on or after March 31, 2019, and there are no outstandingarrearages on our common units. When the subordination period ends as a result of our having met the test described above, all subordinated units willconvert 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 thecommon 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 beless than one to one. If our general partner makes such election, all outstanding subordinated units will be converted into common units, and the conversionratio 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 ofdistributions required to pay the applicable minimum quarterly distribution in full with respect to the subordinated units over the previous four quarters. If atthe time our general partner elects to convert the subordinated units under this provision our forecasted distributions on our subordinated units (asdetermined by the conflicts committee of our general partner’s board of directors) for the next four quarters are lower than our actual distributions for theprevious four-quarter period referred to above, then the conversion ratio will be based on the forecasted distributions instead of the actual distributions.48Series A Redeemable Preferred UnitsUntil March 31, 2018, the holders of our outstanding Series A redeemable preferred units had the option to elect to have us redeem, effective as ofDecember 31, 2017, their Series A redeemable preferred units at face value, plus any accrued and unpaid distributions. All Series A redeemable preferred unitsnot redeemed by March 31, 2018 automatically converted to common and subordinated units effective as of January 1, 2018 or as soon as practicablethereafter. Therefore, there are currently no Series A redeemable preferred units outstanding.Series B Cumulative Convertible Preferred UnitsThe holders of our Series B cumulative convertible preferred units will receive cumulative quarterly distributions in an amount equal to 7.0% of the faceamount of the preferred units per annum (the “Distribution Rate”), provided that the Distribution Rate will be adjusted as follows: commencing on the sixthanniversary of November 28, 2017 and readjusting every two years thereafter (each, a “Readjustment Date”), the rate will equal the greater of (i) theDistribution 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 areaccrued but unpaid, the then-Distribution Rate shall be increased by 2.0% per annum for such quarter. We cannot pay any distributions on any juniorsecurities, including any of our common units and subordinated units, prior to paying the quarterly distribution payable to the Series B cumulativeconvertible preferred units, including any previously accrued and unpaid distributions.49ITEM 6. SELECTED FINANCIAL DATAThe financial information below should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Resultsof 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 $548,321Net income (loss)295,560 157,153 20,188 (101,305) 169,187Net income (loss) attributable to the general partner andcommon units and subordinated units274,511 152,145 14,437 (108,017) *Net income (loss) attributable to limited partners per commonand 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 commonand 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 $1,326,782Long-term debt410,000 388,000 316,000 66,000 394,000Total mezzanine equity298,361 322,422 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 endedDecember 31, 2016, 2015, and 2014, respectively. We did not have impairments of oil and natural gas properties for the years ended December 31, 2018and 2017.50ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSThe following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidatedfinancial statements and notes thereto presented elsewhere in this Annual Report. This discussion and analysis contains forward-looking statements thatinvolve risks, uncertainties, and assumptions. Actual results may differ materially from those anticipated in these forward-looking statements as a result of anumber of factors, including those set forth under “Cautionary Note Regarding Forward-Looking Statements” and “Part I, Item 1A. Risk Factors.”OverviewWe are one of the largest owners and managers of oil and natural gas mineral interests in the United States. Our principal business is maximizing thevalue of our existing portfolio of mineral and royalty assets through active management and expanding our asset base through acquisitions of additionalmineral and royalty interests. We maximize value through the marketing of our mineral assets for lease, creatively structuring the terms on those leases toencourage and accelerate drilling activity, and selectively participating alongside our lessees on a working interest basis. Our primary business objective is togrow our reserves, production, and cash generated from operations over the long term, while paying, to the extent practicable, a growing quarterlydistribution 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 onshoreproducing basins. These non-cost-bearing interests include ownership in over 60,000 producing wells. We also own non-operated working interests, asignificant portion of which are on our positions where we also have a mineral and royalty interest. We recognize oil and natural gas revenue from ourmineral and royalty and non-operated working interests in producing wells when control of the oil and natural gas produced is transferred to the customer andcollectability of the sales price is reasonably assured. Our other sources of revenue include mineral lease bonus and delay rentals, which are recognized asrevenue according to the terms of the lease agreements.Recent DevelopmentsAcquisitionsIn 2018 we acquired mineral and royalty interests primarily in the Permian Basin and in East Texas for aggregate consideration of $127.3 million in cashand $22.6 million in our common units. Additional information regarding acquisitions is contained in Note 4 – Oil and Natural Gas PropertiesAcquisitions to our consolidated financial statements included elsewhere in this Annual Report.PepperJack ProspectWe have cumulatively spent approximately $13.1 million to drill two wells within our PepperJack prospect in Hardin and Liberty counties, Texas. ThePepperJack 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#1well, 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. ThePepperJack 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 haverecorded $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 yearended 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 thePepperJack A#1 well and acreage in the associated unit to the Development Partners and transferred our status as the operator of record. We received proceedsof $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 anoption covering our minerals and leases in the PepperJack prospect area, and an overriding royalty interest in the PepperJack prospect area. The DevelopmentPartners began completion operations on the PepperJack A#1 well in the fourth quarter of 2018 and we are participating as a 25% non-operated workinginterest owner.51Common Unit Repurchase ProgramIn the fourth quarter of 2018, the board of directors of our general partner authorized a $75.0 million common unit repurchase program. The repurchaseprogram authorizes us to make repurchases on a discretionary basis as determined by management, subject to market conditions, applicable legalrequirements, available liquidity, and other appropriate factors. All or a portion of any repurchases may be made under a Rule 10b5-1 plan, which wouldpermit common units to be repurchased when we might otherwise be precluded from doing so under applicable laws. The repurchase program does notobligate 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 $2.0million. The program is funded from cash on hand or through borrowings under the credit facility. Any repurchased units are canceled.Business EnvironmentThe information below is designed to give a broad overview of the oil and natural gas business environment as it affects us.Commodity Prices and DemandOil and natural gas prices have been historically volatile based upon the dynamics of supply and demand. The EIA forecasts that WTI oil prices willaverage 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 highof $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 yearended 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 $2.49 per MMBtu onFebruary 16, 2018.To manage the variability in cash flows associated with the projected sale of our oil and natural gas production, we use various derivative instruments,which have recently consisted of fixed-price swap contracts and costless collar contracts.The following table reflects commodity prices at the end of each quarter presented: 2018Benchmark Prices Fourth Quarter Third Quarter Second Quarter First QuarterWTI spot crude oil ($/Bbl)1 $45.15 $73.16 $74.13 $64.87Henry Hub spot natural gas ($/MMBtu)1 $3.25 $3.01 $2.96 $2.811 Source: EIARig CountAs we are not the operator of record on any producing properties, drilling on our acreage is dependent upon the exploration and production companiesthat 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 futureleasing and drilling activity on our acreage.52The following table shows the rig count at the end of each quarter presented: 2018U.S. Rotary Rig Count1 Fourth Quarter Third Quarter Second Quarter First QuarterOil 885 863 858 797Natural gas 198 189 187 194Other — 2 2 2Total 1,083 1,054 1,047 993 1 Source: Baker Hughes IncorporatedNatural Gas StorageA substantial portion of our revenue is derived from sales of oil production attributable to our interests; however, the majority of our production isnatural gas. Natural gas prices are significantly influenced by storage levels throughout the year. Accordingly, we monitor the natural gas storage reportsregularly 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 islower, natural gas storage levels generally increase. From November to March, storage levels typically decline as utility companies draw natural gas fromstorage to meet increased heating demand due to colder weather. In order to maintain sufficient storage levels for increased seasonal demand, a portion ofnatural gas production during the summer months must be used for storage injection. The portion of production used for storage varies from year to yeardepending on the demand from the previous winter and the demand for electricity used for cooling during the summer months. The EIA forecasts thatinventories 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 expectsinventories 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: 2018Region1 Fourth Quarter Third Quarter Second Quarter First Quarter (Bcf)East 661 763 460 229Midwest 798 836 455 266Mountain 147 177 139 87Pacific 220 262 257 166South Central 878 829 841 606Total 2,704 2,867 2,152 1,3541 Source: EIA53How We Evaluate Our OperationsWe 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 ProducedIn order to track and assess the performance of our assets, we monitor and analyze our production volumes from the various basins and plays thatconstitute our extensive asset base. We also regularly compare projected volumes to actual reported volumes and investigate unexpected variances.Commodity PricesFactors Affecting the Sales Price of Oil and Natural GasThe prices we receive for oil, natural gas, and NGLs vary by geographical area. The relative prices of these products are determined by the factorsaffecting 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 betweenrealized 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 ofour control. NYMEX light sweet crude oil, commonly referred to as WTI, is the prevailing domestic oil pricing index. The majority of our oilproduction 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 inchemical 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 thepresence 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 majortrading 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 actualvolumetric 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, carbondioxide, and nitrogen. Natural gas containing ethane and heavier hydrocarbons has a higher Btu value and will realize a higher volumetric pricethan natural gas which is predominantly methane, which has a lower Btu value. Natural gas with a higher concentration of impurities will realize alower 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 pipelinequality specifications.Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply and demand conditionsand the cost to transport natural gas to end user markets.54HedgingWe enter into derivative instruments to partially mitigate the impact of commodity price volatility on our cash generated from operations. From time totime, such instruments may include variable-to-fixed-price swaps, fixed-price contracts, costless collars, and other contractual arrangements. The impact ofthese 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 isrequired 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 counterpartyif 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 priceexceeds 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 fixedfloor 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 aredue from either party. If we have multiple contracts outstanding with a single counterparty, unless restricted by our agreement, we will net settle the contractpayments.We may employ contractual arrangements other than fixed-price swap contracts and costless collar contracts in the future to mitigate the impact of pricefluctuations. If commodity prices decline in the future, our hedging contracts will partially mitigate the effect of lower prices on our future revenue. Our openoil and natural gas derivative contracts as of December 31, 2018 are detailed in Note 5 – Commodity Derivative Financial Instruments to our consolidatedfinancial statements included elsewhere in this Annual Report.Prior to amending and restating our credit agreement on November 1, 2017, we were allowed to hedge all of our estimated production from our proveddeveloped producing reserves based on the most recent reserve information provided to our lenders. Pursuant to our Fourth Amended and Restated CreditAgreement, we are allowed to hedge certain percentages of expected future monthly production volumes equal to the lesser of (i) internally forecastedproduction and (ii) the average of reported production for the most recent three months.We are allowed to hedge up to 90% of such volumes for the first 24 months, 70% for months 25 through 36, and 50% for months 37 through 48. Pursuantto our updated hedge provisions, as of December 31, 2018 we have hedged, 70.2%, and 20.9% of our available oil and condensate hedge volumes for 2019and 2020, respectively. Also, as of December 31, 2018 we have hedged 93.2% of our available natural gas hedge volumes for 2019.We intend to continuously monitor the production from our assets and the commodity price environment, and will, from time to time, add additionalhedges within the percentages described above related to such production for the following 12 to 30 months. We do not enter into derivative instruments forspeculative purposes.Non-GAAP Financial MeasuresAdjusted EBITDA and distributable cash flow are supplemental non-GAAP financial measures used by our management and external users of ourfinancial statements such as investors, research analysts, and others, to assess the financial performance of our assets and our ability to sustain distributionsover the long term without regard to financing methods, capital structure, or historical cost basis.We define Adjusted EBITDA as net income (loss) before interest expense, income taxes, and depreciation, depletion, and amortization adjusted forimpairment of oil and natural gas properties, accretion of asset retirement obligations, unrealized gains and losses on commodity derivative instruments, andnon-cash equity-based compensation. We define distributable cash flow as Adjusted EBITDA plus or minus amounts for certain non-cash operating activities,estimated replacement capital expenditures, cash interest expense, and distributions to noncontrolling interests and preferred unitholders.Adjusted EBITDA and distributable cash flow should not be considered an alternative to, or more meaningful than, net income (loss), income (loss) fromoperations, cash flows from operating activities, or any other measure of financial performance presented in accordance with generally accepted accountingprinciples in the United States (“U.S. GAAP”) as measures of our financial performance.Adjusted EBITDA and distributable cash flow have important limitations as analytical tools because they exclude some but not all items that affect netincome (loss), the most directly comparable U.S. GAAP financial measure. Our computation of Adjusted EBITDA and distributable cash flow may differ fromcomputations of similarly titled measures of other companies.55The following table presents a reconciliation of net income (loss), the most directly comparable U.S. GAAP financial measure, to Adjusted EBITDA anddistributable cash flow for the periods indicated: Year Ended December 31, 2018 2017 2016 (in thousands)Net income (loss) $295,560 $157,153 $20,188Adjustments to reconcile to Adjusted EBITDA: Depreciation, depletion and amortization 122,653 114,534 102,487Interest expense 20,756 15,694 7,547Income tax expense 2,309— —Impairment of oil and natural gas properties — — 6,775Accretion of asset retirement obligations 1,103 1,026 892Equity-based compensation1 30,134 33,045 43,138Unrealized (gain) loss on commodity derivative instruments (53,066) (11,691) 81,253Adjusted EBITDA 419,449 309,761 262,280Adjustments to distributable cash flow: Change in deferred revenue 1,260 (2,086) (870)Cash interest expense (19,757) (14,817) (6,676)(Gain) loss on sales of assets, net (3) (931) (4,793)Estimated replacement capital expenditures2 (11,500) (13,500) (11,250)Cash paid to noncontrolling interests (211) (120) (111)Preferred unit distributions (21,025) (5,042) (5,763)Distributable cash flow $368,213 $273,265 $232,8171 On April 25, 2016, the Compensation Committee of the board of directors of our general partner approved a resolution to change the settlement feature ofcertain employee long-term incentive compensation plans from cash to equity. As a result of the modification, $10.1 million of cash-settled liabilities werereclassified to equity-settled liabilities during the second quarter of 2016.2 On August 3, 2016, the board of directors of our general partner established a replacement capital expenditures estimate of $15.0 million for the period ofApril 1, 2016 to March 31, 2017; there was no established estimate of replacement capital expenditures prior to this period. On June 8, 2017, the board ofdirectors of our general partner established a replacement capital expenditure estimate of $13.0 million for the period of April 1, 2017 to March 31, 2018.On April 27, 2018, the Board approved a replacement capital expenditure estimate of $11.0 million for the period of April 1, 2018 to March 31, 2019.56Results of OperationsYear Ended December 31, 2018 Compared to Year Ended December 31, 2017The following table shows our production, revenue, and operating expenses for the periods presented: Year Ended December 31, 2018 2017 Variance (dollars in thousands, except for realized prices and per BOE data)Production: Oil and condensate (MBbls) 4,962 3,552 1,410 39.7 %Natural gas (MMcf)1 71,622 59,779 11,843 19.8 %Equivalents (MBoe) 16,899 13,515 3,384 25.0 %Revenue: Oil and condensate sales $310,278 $169,728 $140,550 82.8 %Natural gas and natural gas liquids sales1 248,243 190,967 $57,276 30.0 %Lease bonus and other income 36,216 42,062 $(5,846) (13.9)%Revenue from contracts with customers 594,737 402,757 $191,980 47.7 %Gain (loss) on commodity derivative instruments 14,831 26,902 $(12,071) (44.9)%Total revenue 609,568 429,659 179,909 41.9 %Realized prices, without derivatives: Oil and condensate ($/Bbl) $62.53 $47.78 $14.75 30.9 %Natural gas ($/Mcf)1 $3.47 3.19 0.28 8.8 %Equivalents ($/Boe) $33.05 $26.69 $6.36 23.8 %Operating expenses: Lease operating expense $18,415 $17,280 $1,135 6.6 %Production costs and ad valorem taxes 64,364 47,474 16,890 35.6 %Exploration expense 7,943 618 7,325 NM2Depreciation, depletion, and amortization 122,653 114,534 8,119 7.1 %General and administrative 76,712 77,574 (862) (1.1)%1 As a mineral and royalty interest owner, we are often provided insufficient and inconsistent data on NGL volumes by our operators. As a result, we areunable to reliably determine the total volumes of NGLs associated with the production of natural gas on our acreage. Accordingly, no NGL volumes areincluded in our reported production; however, revenue attributable to NGLs is included in our natural gas revenue and our calculation of realized prices fornatural gas.2 Not meaningfulRevenueTotal revenue for the year ended December 31, 2018 increased compared to the year ended December 31, 2017. The increase in total revenue from thecorresponding period is primarily due to increased oil and condensate sales and natural gas and NGL sales as a result of increased production volumes andhigher realized commodity prices, partially offset by a decreased gain from our commodity derivative instruments and lower lease bonus and other income.Production for 2018 averaged 46.3 MBoe per day, an increase of 9.3 MBoe per day, compared to the corresponding period in 2017.Oil and condensate sales. Oil and condensate sales for the year ended December 31, 2018 were higher than the corresponding period in 2017 due toincreased production volumes and higher realized commodity prices. Our mineral and royalty interest oil and condensate volumes increased 52% in 2018relative to 2017, primarily driven by production increases in the Permian-Midland, Permian-Delaware, and Bakken/Three Forks plays. Our mineral androyalty interest oil and condensate volumes accounted for 90% and 83% of total oil and condensate volumes for the years ended December 31, 2018 and2017, respectively.57Natural gas and natural gas liquids sales. Natural gas and NGL sales for the year ended December 31, 2018 were higher than the corresponding periodin 2017 primarily due to increased production volumes, largely in the Haynesville/Bossier play, as well as the Permian-Midland, Permian-Delaware, andBakken/Three Forks plays. Mineral and royalty interest production accounted for 60% and 51% of our natural gas and NGL volumes for the years endedDecember 31, 2018 and 2017, respectively. There was also an increase in commodity prices between the comparative periods.Gain (loss) on commodity derivative instruments. In 2018, we recognized a decreased gain from our commodity derivative instruments compared to thesame period of 2017. Cash settlements we receive represent realized gains, while cash settlements we pay represent realized losses related to our commodityderivative instruments. In addition to cash settlements, we also recognize fair value changes on our commodity derivative instruments in each reportingperiod. The changes in fair value result from new positions and settlements that may occur during each reporting period, as well as the relationships betweencontract prices and the associated forward curves. In 2018, we recognized $24.3 million of net gains from oil commodity contracts, which included cashpayments of $34.9 million, compared to $5.1 million of recognized net losses in 2017. In 2018, we recognized $9.5 million of net losses from natural gascommodity contracts, which included cash payments of $3.3 million, compared to $32.0 million of net gains in 2017.Lease bonus and other income. When we lease our mineral interests, we generally receive an upfront cash payment, or a lease bonus. Lease bonus incomecan vary substantively between periods because it is derived from individual transactions with operators, some of which may be significant. Lease bonus andother income was lower for the year ended December 31, 2018, as compared to the same period 2017, though we successfully closed several significant leasetransactions in the Bakken/Three Forks, Haynesville/Bossier, Permian-Midland, Permian-Delaware, and Austin Chalk plays.Operating ExpensesLease operating expense. Lease operating expense includes recurring expenses associated with our non-operated working interests necessary to producehydrocarbons from our oil and natural gas wells, as well as certain nonrecurring expenses, such as well repairs. Lease operating expense increased for the yearended December 31, 2018 as compared to 2017, primarily due to higher workover and other service-related expenses on wells in which we own a non-operating working interest.Production costs and ad valorem taxes. Production taxes include statutory amounts deducted from our production revenues by various state taxingentities. Depending on the regulations of the states where the production originates, these taxes may be based on a percentage of the realized value or a fixedamount per production unit. This category also includes the costs to process and transport our production to applicable sales points. Ad valorem taxes arejurisdictional taxes levied on the value of oil and natural gas minerals and reserves. Rates, methods of calculating property values, and timing of paymentsvary between taxing authorities. For the year ended December 31, 2018, production and ad valorem taxes increased over the year ended December 31, 2017,generally as a result of higher production volumes and commodity prices.Exploration expense. Exploration expense typically consists of dry-hole expenses, delay rentals, and geological and geophysical costs, includingseismic costs, and is expensed as incurred under the successful efforts method of accounting. Exploration expense for 2018 primarily related to thePepperJack B#1 well. Exploration expense for 2017 consisted of costs incurred to acquire 3-D seismic information, related to our mineral and royaltyinterests, from a third-party service provider.Depreciation, depletion, and amortization. Depletion is the amount of cost basis of oil and natural gas properties attributable to the volume ofhydrocarbons extracted during such period, calculated on a units-of-production basis. Estimates of proved developed producing reserves are a majorcomponent of the calculation of depletion. We adjust our depletion rates semi-annually based upon the mid-year and year-end reserve reports, except whencircumstances indicate that there has been a significant change in reserves or costs. Depreciation, depletion, and amortization expense increased for the yearended December 31, 2018 as compared to 2017, primarily due to higher production volumes partially offset by lower depletion rates.General and administrative. General and administrative expenses are costs not directly associated with the production of oil and natural gas and includethe cost of employee salaries and related benefits, office expenses, and fees for professional services. For the year ended December 31, 2018, general andadministrative expenses remained relatively flat compared to 2017 due to lower brokerage and legal fees associated with our acquisition activity, partiallyoffset by increased costs attributable to our incentive compensation plans.Interest expense. Interest expense increased due to higher average outstanding borrowings and higher interest rates under our credit facility. The increasein average outstanding borrowings was primarily due to funding of acquisitions during 2018.58Year Ended December 31, 2017 Compared to Year Ended December 31, 2016The following table shows our production, revenue, and operating expenses for the periods presented: Year Ended December 31, 2017 2016 Variance (dollars in thousands, except for realized prices and per BOE data)Production: Oil and condensate (MBbls) 3,552 3,680 (128) (3.5)%Natural gas (MMcf)1 59,779 47,498 12,281 25.9 %Equivalents (MBoe) 13,515 11,596 $1,919 16.5 %Revenue: Oil and condensate sales $169,728 $142,382 $27,346 19.2 %Natural gas and natural gas liquids sales1 190,967 122,836 68,131 55.5 %Lease bonus and other income 42,062 32,079 9,983 31.1 %Revenue from contracts with customers 402,757 297,297 105,460 35.5 %Gain (loss) on commodity derivative instruments 26,902 (36,464) 63,366 (173.8)%Total revenue $429,659 $260,833 168,826 64.7 %Realized prices: Oil and condensate ($/Bbl) $47.78 $38.69 $9.09 23.5 %Natural gas ($/Mcf)1 3.19 2.59 0.60 23.2 %Equivalents ($/Boe) $26.69 $22.87 $3.82 16.7 %Operating expenses: Lease operating expense $17,280 $18,755 $(1,475) (7.9)%Production costs and ad valorem taxes 47,474 35,464 12,010 33.9 %Exploration expense 618 645 (27) (4.2)%Depreciation, depletion, and amortization 114,534 102,487 12,047 11.8 %Impairment of oil and natural gas properties — 6,775 (6,775) (100.0)%General and administrative 77,574 73,139 4,435 6.1 %1As a mineral and royalty interest owner, we are often provided insufficient and inconsistent data on NGL volumes by our operators. As a result, we areunable to reliably determine the total volumes of NGLs associated with the production of natural gas on our acreage. Accordingly, no NGL volumes areincluded in our reported production; however, revenue attributable to NGLs is included in our natural gas revenue and our calculation of realized prices fornatural gas.RevenueTotal revenue for the year ended December 31, 2017 increased compared to the year ended December 31, 2016. Production for 2017 averaged 37.0MBoe per day, an increase of 5.3 MBoe per day, compared to the corresponding period in 2016. The increase in total revenue from the corresponding periodis primarily due to higher realized commodity prices and production volumes, an increase in revenue from our commodity derivative instruments, and higherlease bonus and other income.Oil and condensate sales. Oil and condensate sales during 2017 were higher than the corresponding period in 2016 due to a significant increase inrealized prices. Our mineral and royalty interest oil and condensate volumes accounted for 83% and 77% of total oil and condensate volumes for the yearsended December 31, 2017 and 2016, respectively. Our oil and condensate volumes decreased slightly in 2017.Natural gas and natural gas liquids sales. Natural gas and NGL sales increased for the year ended December 31, 2017 as compared to 2016. During2017, production from new wells in Haynesville/Bossier and Wilcox plays combined with higher natural gas and NGL prices drove the increase in natural gasand NGL sales. Mineral and royalty interest production accounted for 51% and 59% of our natural gas and NGL volumes for the years ended December 31,2017 and 2016, respectively. 59Gain (loss) on commodity derivative instruments. In 2017, we recognized $5.1 million of net losses from oil commodity contracts, which included cashreceived of $10.9 million, compared to $16.0 million of recognized net losses in 2016. In 2017, we recognized $32.0 million of net gains from natural gascommodity contracts, which included cash received of $4.3 million, compared to $20.5 million of net losses in 2016.Lease bonus and other income. When we lease our mineral interests, we generally receive an upfront cash payment, or a lease bonus. Lease bonus anddelay rental revenue increased for the year ended December 31, 2017, as compared to 2016. In 2017, we successfully closed several significant leasetransactions in the Austin Chalk, Bakken/Three Forks, Haynesville/Bossier and Canyon Lime plays as well as the Anadarko and Permian Basins, compared tothe majority of 2016 activity which came from the Wolfcamp, Austin Chalk, and Marcellus plays.Operating ExpensesLease operating expense. Lease operating expense includes normally recurring expenses associated with our non-operated working interests necessary toproduce hydrocarbons from our oil and natural gas wells, as well as certain nonrecurring expenses, such as well repairs. Lease operating expense decreased forthe year ended December 31, 2017 as compared to 2016, primarily due to fewer remedial projects initiated by our operators.Production costs and ad valorem taxes. Production taxes include statutory amounts deducted from our production revenues by various state taxingentities. Depending on the regulations of the states where the production originates, these taxes may be based on a percentage of the realized value or a fixedamount per production unit. This category also includes the costs to process and transport our production to applicable sales points. Ad valorem taxes arejurisdictional taxes levied on the value of oil and natural gas minerals and reserves. Rates, methods of calculating property values, and timing of paymentsvary between taxing authorities. For the year ended December 31, 2017, production and ad valorem taxes increased over the year ended December 31, 2016,generally as a result of higher production volumes and commodity prices.Exploration expense. Exploration expense typically consists of dry-hole expenses, delay rentals, and geological and geophysical costs, includingseismic costs, and is expensed as incurred under the successful efforts method of accounting. Exploration expense for 2017 represents costs incurred toacquire 3-D seismic information, related to our mineral and royalty interests, from a third-party service provider.Depreciation, depletion, and amortization. Depletion is the amount of cost basis of oil and natural gas properties attributable to the volume ofhydrocarbons extracted during such period, calculated on a units-of-production basis. Estimates of proved developed producing reserves are a majorcomponent of the calculation of depletion. We adjust our depletion rates semi-annually based upon the mid-year and year-end reserve reports, except whencircumstances indicate that there has been a significant change in reserves or costs. Depreciation, depletion, and amortization expense increased for the yearended December 31, 2017 as compared to 2016, primarily due to higher production volumes partially offset by lower depletion rates.Impairment of oil and natural gas properties. Individual categories of oil and natural gas properties are assessed periodically to determine if the netbook value for these properties has been impaired. Management periodically conducts an in-depth evaluation of the cost of property acquisitions, successfulexploratory wells, development activities, unproved leasehold, and mineral interests to identify impairments. We did not incur any impairment in 2017,while impairments for 2016 were $6.8 million.General and administrative. General and administrative expenses are costs not directly associated with the production of oil and natural gas and includethe cost of employee salaries and related benefits, office expenses, and fees for professional services. For the year ended December 31, 2017, general andadministrative expenses increased compared to 2016. In 2017, costs attributable to our long-term incentive plans were higher due to the achievement ofcertain performance targets; we also incurred higher broker fees associated with increased acquisition activities.Interest expense. Interest expense increased due to higher average outstanding borrowings and higher interest rates under our credit facility, which werepredominantly driven by increased acquisition of oil and natural gas properties in 2017 as compared to 2016.60Liquidity and Capital ResourcesOverviewOur primary sources of liquidity are cash generated from operations, borrowings under our credit facility, and proceeds from the issuance of equity anddebt. Our primary uses of cash are for distributions to our unitholders and for investing in our business, specifically the acquisition of mineral and royaltyinterests and our selective participation on a non-operated working interest basis in the development of our oil and natural gas properties. The board of directors of our general partner has adopted a policy pursuant to which, at a minimum, distributions will be paid on each common andsubordinated unit for each quarter to the extent we have sufficient cash generated from our operations after establishment of cash reserves, if any, and after wehave made the required distributions to the holders of our outstanding preferred units. However, we do not have a legal or contractual obligation to paydistributions on our common and subordinated units quarterly or on any other basis, and there is no guarantee that we will pay distributions to our commonand subordinated unitholders in any quarter. Our minimum quarterly distribution provides the common unitholders a specified priority right to distributionsover the subordinated unitholders. The priority right will cease to exist upon full conversion of the subordinated units to common units, which may occur asearly as May of 2019. The board of directors of our general partner may change the foregoing distribution policy at any time and from time to time.We intend to finance our future acquisitions with cash generated from operations, borrowings from our credit facility, and proceeds from any futureissuances of equity and debt. Over the long-term, we intend to finance our working interest capital needs with our executed farmout agreements andinternally-generated cash flows, although at times we may fund a portion of these expenditures through other financing sources such as borrowings under ourcredit facility. Replacement capital expenditures are expenditures necessary to replace our existing oil and natural gas reserves or otherwise maintain ourasset base over the long-term. Like a number of other master limited partnerships, we are required by our partnership agreement to retain cash from ouroperations in an amount equal to our estimated replacement capital requirements. The board of directors of our general partner established a replacementcapital expenditure estimate of $15.0 million for the period of April 1, 2016 to March 31, 2017, $13.0 million for the period of April 1, 2017 to March 31,2018, and $11.0 million for the period of April 1, 2018 to March 31, 2019.Cash FlowsYear Ended December 31, 2018 Compared to Year Ended December 31, 2017The following table shows our cash flows for the periods presented: Year Ended December 31, 2018 2017 Change (in thousands)Cash flows provided by operating activities $385,378 $281,852 $103,526Cash flows used in investing activities (163,804) (454,249) 290,445Cash flows provided by (used in) financing activities (221,802) 168,267 (390,069)61Operating Activities. Our operating cash flows are dependent, in large part, on our production, realized commodity prices, derivative settlements, leasebonus revenue, and operating expenses. The increase in cash flows from operations in 2018 as compared to 2017 was primarily due to higher commodityrevenue driven by increased oil and natural gas production and higher realized commodity prices period over period, partially offset by the net cash paid onsettlement of commodity derivative instruments for 2018 compared to cash received for the same period of 2017.Investing Activities. Net cash used in investing activities decreased in 2018 as compared to 2017. The decrease was primarily due to less cash spent onacquisitions and higher proceeds received from our farmout agreements, partially offset by an increase in cash spent on additions to oil and natural gasproperties.Financing Activities. For the year ended December 31, 2018, cash flows were used in financing activities and was a result of increased distributions tocommon and subordinated unitholders, distributions to holders of Series B cumulative convertible preferred units, and a decrease in net borrowings under ourcredit facility as compared to 2017. During 2017, cash flows were primarily provided by proceeds from the issuance of the Series B cumulative convertiblepreferred units and the issuance of common units under our ATM program.Year Ended December 31, 2017 Compared to Year Ended December 31, 2016The following table shows our cash flows for the periods presented: Year Ended December 31, 2017 2016 Change (in thousands)Cash flows provided by operating activities $281,852 $196,656 $85,196Cash flows used in investing activities (454,249) (221,542) (232,707)Cash flows provided by (used in) financing activities 168,267 21,425 146,842Operating Activities. Our operating cash flow is dependent, in large part, on our production, realized commodity prices, leasing revenues, and operatingexpenses. The increase in cash flows from operations in 2017 as compared to 2016 was primarily due to increased oil and natural gas revenue driven byhigher oil and natural gas sales, an increase in lease bonus and other income, as well as changes in working capital, which was partially offset by increasedproduction costs and ad valorem taxes and general and administrative expenses, as well as a decrease in net cash received on the settlement of commodityderivative financial instruments.Investing Activities. Net cash used in investing activities increased in 2017 as compared to 2016. The increase was primarily due to the cash portion ofoil and natural gas properties acquisitions in 2017 being higher than the cash portion of oil and natural gas properties acquisitions in 2016, which waspartially offset by increased proceeds from the sale of oil and natural gas properties and proceeds from farmouts of oil and natural gas properties.Financing Activities. Cash flows provided by financing activities increased in 2017 as compared to 2016. The increase was primarily due to proceedsfrom the issuance of common units under our ATM Program and proceeds from the issuance of the Series B cumulative convertible preferred units. Decreaseddistributions to holders of the Series A redeemable preferred units and decreased repurchases of common and subordinated units also contributed to the netincrease in financing cash flows. These 2017 increases were partially offset by increased distributions to common and subordinated unitholders and adecrease in net borrowings under our credit facility compared to 2016.Development Capital ExpendituresIn the first quarter of each calendar year, we establish a capital budget and then monitor it throughout the year. Our capital budget is created based uponour estimate of internally-generated cash flows and the ability to borrow and raise additional capital. Actual capital expenditure levels will vary, in part,based on actual cash generated, the economics of wells proposed by our operators for our participation, and the successful closing of acquisitions. Thetiming, size, and nature of acquisitions are unpredictable.Our 2019 capital expenditure budget associated with our non-operated working interests is expected to be approximately $10.0 million. The majority ofthis capital will be spent for workovers on existing wells in which we own a working interest, or for acquiring new leasehold acreage for subsequent farmoutin the Haynesville/Bossier play.62During 2018, we spent approximately $36.3 million associated with our non-operated working interests in certain Haynesville/Bossier wells in theShelby Trough area of East Texas, net of farmout reimbursements, related to completions in wells which were spud prior to the farmouts. In the PepperJackprospect area, we spent approximately $11.9 million during 2018 to drill and log two wells targeting the Lower Wilcox formation. We spent an additional$0.5 million related to the completion costs for the PepperJack A#1 well in the fourth quarter of 2018.We spent approximately $58.6 million and $73.3 million related to drilling and completion costs for the years ended December 31, 2017 and 2016,respectively. During 2017, our capital expenditures were offset by proceeds from farmout reimbursements of approximately $19.2 million.AcquisitionsDuring 2018, we spent approximately $127.3 million and issued common units valued at $22.6 million related to acquisitions of mineral and royaltyinterests, which also included proved oil and natural gas properties.During 2017, we spent approximately $425.7 million and issued common units valued at $71.7 million related to acquisitions of mineral and royaltyinterests, which also included proved oil and natural gas properties.During 2016, we spent approximately $141.1 million related to four mineral acquisitions as well as a final holdback payment from an acquisition in2015.See Note 4 – Oil and Natural Gas Properties Acquisitions to the consolidated financial statements included elsewhere in this Annual Report foradditional information.Credit FacilityPursuant to our $1.0 billion secured revolving credit agreement, the commitment of the lenders equals the lesser of the aggregate maximum creditamounts of the lenders and the borrowing base, which is determined based on the lenders’ estimated value of our oil and natural gas properties. Borrowingsunder the credit facility may be used for the acquisition of properties, cash distributions, and other general corporate purposes. On November 1, 2017, weentered into the fourth amended and restated credit agreement to extend the maturity date thereof for a term of five years, create a swingline facility thatpermits short-term borrowings on same-day notice, and make other changes to the hedging and restrictive covenants. The borrowing base was reconfirmed at$550.0 million with our fall 2017 redetermination. Effective May 4, 2018, the borrowing base was increased to $600.0 million with our spring 2018redetermination, and effective October 31, 2018, the borrowing base was further increased to $675.0 million with our fall 2018 redetermination. Our creditfacility terminates on November 1, 2022. As of December 31, 2018, we had outstanding borrowings of $410.0 million at a weighted-average interest rate of4.76%.The borrowing base is redetermined semi-annually, typically in April and October of each year, by the administrative agent, taking into considerationthe estimated loan value of our oil and natural gas properties consistent with the administrative agent’s normal lending criteria. The administrative agent’sproposed redetermined borrowing base must be approved by all lenders to increase our existing borrowing base, and by two-thirds of the lenders to maintainor decrease our existing borrowing base. In addition, we and the lenders (at the election of two-thirds of the lenders) each have discretion to have theborrowing base redetermined once between scheduled redeterminations. Under the fourth amended and restated credit agreement, we also have the right torequest a redetermination following acquisition of oil and natural gas properties in excess of 10% of the value of the borrowing base immediately prior tosuch acquisition.Outstanding borrowings under the credit agreement bear interest at a floating rate elected by us equal to an alternative base rate (which is equal to thegreatest of the Prime Rate, the Federal Funds effective rate plus 0.50%, or 1-month LIBOR plus 1.00%) or LIBOR, in each case, plus the applicable margin.Through October 2016, the applicable margin ranged from 0.50% to 1.50% in the case of the alternative base rate and from 1.50% to 2.50% in the case ofLIBOR, in each case depending on the amount of borrowings outstanding in relation to the borrowing base. Subsequent to the closing of our fallredetermination on October 31, 2016, the applicable margin ranges from 1.00% to 2.00% in the case of the alternative base rate and from 2.00% to 3.00% inthe case of LIBOR, depending on the borrowings outstanding in relation to the borrowing base. Effective October 31, 2018, the LIBOR margin was reducedto between 1.75% and 2.75% and the Prime Rate margin was reduced to between 0.75% and 1.75%.We are obligated to pay a quarterly commitment fee ranging from a 0.375% to 0.500% annualized rate on the unused portion of the borrowing base,depending on the amount of the borrowings outstanding in relation to the borrowing base. Principal may be optionally repaid from time to time withoutpremium or penalty, other than customary LIBOR breakage, and is required to be paid (a) if the amount outstanding exceeds the borrowing base, whether dueto a borrowing base63redetermination or otherwise, in some cases subject to a cure period, or (b) at the maturity date. Our credit facility is secured by liens on substantially all ofour producing properties.Our credit agreement contains various affirmative, negative, and financial maintenance covenants. These covenants, among other things, limit additionalindebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates, and entering into certainswap agreements, as well as require the maintenance of certain financial ratios. The credit agreement contains two financial covenants: total debt toEBITDAX of 3.5:1.0 or less and a modified current ratio of 1.0:1.0 or greater as defined in the credit agreement. Distributions are not permitted if there is adefault under the credit agreement (including due to a failure to satisfy one of the financial covenants) or during any time that our borrowing base is lowerthan the loans outstanding under the credit agreement. The lenders have the right to accelerate all of the indebtedness under the credit agreement upon theoccurrence and during the continuance of any event of default, and the credit agreement contains customary events of default, including non-payment,breach of covenants, materially incorrect representations, cross-default, bankruptcy, and change of control. There are no cure periods for events of default dueto non-payment of principal and breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants aresubject to customary cure periods. As of December 31, 2018, we were in compliance with all debt covenants.Contractual ObligationsThe following table summarizes our minimum payments as of December 31, 2018 (in thousands): Payments due by period Total Less Than 1Year 1-3 Years 3-5 Years More Than 5 YearsCredit facility $410,000 $— $— $410,000 $—Operating lease obligations 6,992 1,3862,756 2,850 —Purchase commitments 886 813 73 — —Total $417,878 $2,199 $2,829 $412,850 $—Off-Balance Sheet ArrangementsAt December 31, 2018, we did not have any material off-balance sheet arrangements.Critical Accounting Policies and Related EstimatesThe discussion and analysis of our financial condition and results of operations are based upon the consolidated financial statements, which have beenprepared in accordance with U.S. GAAP. Certain of our accounting policies involve judgments and uncertainties to such an extent that there is a reasonablelikelihood that materially different amounts would have been reported under different conditions, or if different assumptions had been used. The followingdiscussions of critical accounting estimates, including any related discussion of contingencies, address all important accounting areas where the nature ofaccounting estimates or assumptions could be material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or thesusceptibility of such matters to change. We have provided expanded discussion of our more significant accounting estimates below.Please read the notes to the consolidated financial statements included elsewhere in this Annual Report for additional information regarding ouraccounting policies.Use of EstimatesThe preparation of consolidated financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reportedamounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, as well as reportedamounts of revenues and expenses for the periods herein. Actual results could differ from those estimates.Our consolidated financial statements are based on a number of significant estimates including oil and natural gas reserve quantities that are the basis forthe calculations of depreciation, depletion, and amortization (“DD&A”) and impairment of oil and natural gas properties. Reservoir engineering is asubjective process of estimating underground accumulations of oil and64natural gas. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. The accuracy of any reserve estimates isa function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may differ from thequantities of oil and natural gas that are ultimately recovered. Our reserve estimates are determined by an independent petroleum engineering firm. Otheritems subject to significant estimates and assumptions include the carrying amount of oil and natural gas properties, valuation of commodity derivativefinancial instruments, valuation of future asset retirement obligations (“ARO”), determination of revenue accruals, and the determination of the fair value ofequity-based awards.We evaluate estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic andcommodity price environment. The volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions. A significantdecline in oil or natural gas prices could result in a reduction in our fair value estimates and cause us to perform analyses to determine if our oil and naturalgas properties are impaired. As future commodity prices cannot be predicted accurately, actual results could differ significantly from estimates.Oil and Natural Gas PropertiesWe follow the successful efforts method of accounting for oil and natural gas operations. Under this method, costs to acquire mineral and royaltyinterests and working interests in oil and natural gas properties, property acquisitions, successful exploratory wells, development costs, and supportequipment and facilities are capitalized when incurred. Acquisitions of proved oil and natural gas properties and working interests are considered businesscombinations and are recorded at their estimated fair value as of the acquisition date. Acquisitions of unproved oil and natural gas properties are consideredasset acquisitions and are recorded at cost.The costs of unproved leaseholds and non-producing mineral interests are capitalized as unproved properties pending the results of exploration andleasing efforts. As unproved properties are determined to be productive, the related costs are transferred to proved oil and natural gas properties. The costsrelated to exploratory wells are capitalized pending determination of whether proved commercial reserves exist. If proved commercial reserves are notdiscovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether proved commercial reserves have been discovered whendrilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify completion as aproducing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is ongoing. Other exploratory costs,including annual delay rentals and geological and geophysical costs, are expensed when incurred.Oil and natural gas properties are grouped in accordance with the Extractive Industries – Oil and Gas Topic of the Financial Accounting Standards BoardAccounting Standards Codification. The basis for grouping is a reasonable aggregation of properties with a common geological structural feature orstratigraphic condition, such as a reservoir or field, which we may also refer to as a depletable unit.As exploration and development work progresses and the reserves associated with our oil and natural gas properties become proved, capitalized costsattributed to the properties are charged as an operating expense through DD&A. DD&A of producing oil and natural gas properties is recorded based on theunits-of-production method. Capitalized development costs are amortized on the basis of proved developed reserves while leasehold acquisition costs andthe costs to acquire proved properties are amortized on the basis of all proved reserves, both developed and undeveloped. Proved reserves are estimatedquantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future yearsfrom known reservoirs under existing economic and operating conditions. DD&A expense related to our producing oil and natural gas properties was $122.5million, $114.3 million, and $102.4 million for the years ended December 31, 2018, 2017, and 2016, respectively.We evaluate impairment of producing properties whenever events or changes in circumstances indicate that the carrying amount of an asset may not berecoverable. This evaluation is performed on a depletable unit basis. We compare the undiscounted projected future cash flows expected in connection with adepletable unit to its unamortized carrying amount to determine recoverability. When the carrying amount of a depletable unit exceeds its estimatedundiscounted future cash flows, the carrying amount is written down to its fair value, which is measured as the present value of the projected future cash flowsof such properties. The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, futurecapital expenditures, and a risk-adjusted discount rate.There was no impairment of proved oil and natural gas properties for the years ended December 31, 2018 and 2017. Impairment of proved oil and naturalgas properties was $4.9 million for the year ended December 31, 2016. The impairment primarily resulted from declines in future expected realizable net cashflows. The charge is included in impairment of oil and65natural gas properties on the consolidated statements of operations and reflected in the net book value of oil and natural gas properties.Unproved properties are also assessed for impairment periodically on a depletable unit basis when facts and circumstances indicate that the carryingvalue may not be recoverable, at which point an impairment loss is recognized to the extent the carrying value exceeds the estimated recoverable value. Thecarrying value of unproved properties, including unleased mineral rights, is determined based on management’s assessment of fair value using factors similarto those previously noted for proved properties, as well as geographic and geologic data. There was no impairment of unproved properties for the years endedDecember 31, 2018 and 2017. Impairment of unproved properties was $1.9 million for the year ended December 31, 2016. The charge is included inimpairment of oil and natural gas properties on the consolidated statements of operations and reflected in the net book value of oil and natural gas properties.Upon the sale of a complete depletable unit, the book value thereof, less proceeds or salvage value, is charged to income. Upon the sale or retirement ofan individual well, or an aggregation of interests which make up less than a complete depletable unit, the proceeds are credited to accumulated DD&A, unlessdoing so would significantly alter the DD&A rate of the depletable unit, in which case a gain or loss is recorded.We are unable to predict future commodity prices with any greater precision than the futures market. To estimate the effect lower prices would have onour reserves, we applied a 10% discount to the commodity prices used in our December 31, 2018 reserve report. Applying this discount results in anapproximate 1.7% reduction of estimated proved reserve volumes as compared to the undiscounted pricing scenario used in our December 31, 2018 reservereport prepared by NSAI.Asset Retirement ObligationsUnder various contracts, permits, and regulations, we have legal obligations to restore the land at the end of operations at certain properties where weown non-operated working interests. Estimating the future restoration costs necessary for this accounting calculation is difficult. Most of these restorationobligations are many years, or decades, in the future and the contracts and regulations often have vague descriptions of what practices and criteria must bemet when the event actually occurs. Asset-restoration technologies and costs, regulatory and other compliance considerations, expenditure timing, and otherinputs into the valuation of the obligation, including discount and inflation rates, are also subject to change.Fair values of legal obligations to retire and remove long-lived assets are recorded when the obligation is incurred and becomes determinable. When theliability is initially recorded, we capitalize this cost by increasing the carrying amount of the related property. Over time, the liability is accreted for thechange in its present value, and the capitalized cost in oil and natural gas properties is depleted based on units-of-production consistent with the relatedasset.Revenues from Contracts with CustomersAccounting Standards Codification ("ASC") 606, Revenue from Contracts with Customers, requires us to identify the distinct promised goods andservices within a contract which represent separate performance obligations and determine the transaction price to allocate to the performance obligationsidentified. We adopted ASC 606 using the modified retrospective method, which was applied to all existing contracts for which all (or substantially all) ofthe revenue had not been recognized under legacy revenue guidance as of the date of adoption, January 1, 2018.Oil and natural gas salesSales of oil and natural gas are recognized at the point control of the product is transferred to the customer and collectability of the sales price isreasonably assured. Oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality andphysical location. The price we receive for natural gas is tied to a market index, with certain adjustments based on, among other factors, whether a welldelivers to a gathering or transmission line, quality and heat content of natural gas, and prevailing supply and demand conditions, so that the price of naturalgas fluctuates to remain competitive with other available natural gas supplies. As each unit of product represents a separate performance obligation and theconsideration is variable as it relates to oil and natural gas prices, we recognize revenue from oil and natural gas sales using the practical expedient forvariable consideration in ASC 606.Lease bonus and other incomeWe also earn revenue from lease bonuses and delay rentals. We generate lease bonus revenue by leasing mineral interests to exploration and productioncompanies. A lease agreement represents our contract with a customer and generally transfers the66rights to any oil or natural gas discovered, grants us a right to a specified royalty interest, and requires that drilling and completion operations commencewithin a specified time period. Control is transferred to the lessee and we have satisfied our performance obligation when the lease agreement is executed,such that revenue is recognized when the lease bonus payment is received. At the time we execute the lease agreement, we expect to receive the lease bonuspayment within a reasonable time, though in no case more than one year, such that we have not adjusted the expected amount of consideration for the effectsof any significant financing component per the practical expedient in ASC 606. We also recognize revenue from delay rentals to the extent drilling has notstarted within the specified period, payment has been received, and we have no further obligation to refund the payment.Allocation of transaction price to remaining performance obligationsOil and natural gas salesWe have utilized the practical expedient in ASC 606 which states we are not required to disclose the transaction price allocated to remainingperformance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. As we have determined that eachunit of product generally represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocatedto remaining performance obligations is not required.Lease bonus and other incomeGiven that we do not recognize lease bonus or other income until a lease agreement has been executed, at which point its performance obligation hasbeen satisfied, and payment is received, we do not record revenue for unsatisfied or partially unsatisfied performance obligations as of the end of thereporting period. Overall, there were no material changes in the timing of the satisfaction of our performance obligations or the allocation of the transactionprice to our performance obligations in applying the guidance in ASC 606 as compared to legacy U.S. GAAP.Prior-period performance obligationsWe record oil and natural gas revenue in the month production is delivered to the purchaser. As a non-operator, we have limited visibility into the timingof when new wells start producing and production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result,we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The expectedsales volumes and prices for these properties are estimated and recorded within the Accounts receivable line item in the accompanying consolidated balancesheets. The difference between our estimates and the actual amounts received for oil and natural gas sales is recorded in the month that payment is receivedfrom the third party. For the years ended December 31, 2018 and 2017, revenue recognized in the reporting periods related to performance obligationssatisfied in prior reporting periods was immaterial.Commodity Derivative Financial InstrumentsOur ongoing operations expose us to changes in the market price for oil and natural gas. To mitigate the given price risk associated with its operations,we use commodity derivative financial instruments. From time to time, such instruments may include variable-to-fixed price swaps, costless collars, fixed-price contracts, and other contractual arrangements. We do not enter into derivative instruments for speculative purposes. The impact of these derivativeinstruments could affect the amount of revenue we ultimately record.Derivative instruments are recognized at fair value. If a right of offset exists under master netting arrangements and certain other criteria are met,derivative assets and liabilities with the same counterparty are netted on the consolidated balance sheet. Gains and losses arising from changes in the fairvalue of derivatives are recognized on a net basis in the accompanying consolidated statements of operations within gain (loss) on commodity derivativeinstruments. Although these derivative instruments may expose us to credit risk, we monitor the creditworthiness of our counterparties.Equity-Based CompensationWe recognize equity-based compensation expense for unit-based awards granted to our employees and the board of directors of our general partner. Totalcompensation expense for unit-based awards is calculated based on the number of units expected to vest multiplied by the grant-date fair value per unit.Compensation expense for time-based restricted unit awards with graded vesting requirements are recognized using straight-line attribution over the requisiteservice period. Compensation expense related to the restricted performance unit awards is determined by multiplying the number of common unitsunderlying67such awards that, based on our estimates, are likely to vest, by the grant-date fair value and recognized using the accelerated attribution method. Equity-based compensation expense related to unit-based awards is included in general and administrative expense within the consolidated statements of operations.Distribution equivalent rights for the restricted performance unit awards that are expected to vest are charged to partners’ capital. Please read Note 9 –Incentive Compensation within the consolidated financial statements included elsewhere in this Annual Report for additional information.New and Revised Financial Accounting StandardsThe effects of new accounting pronouncements are discussed in Note 2 – Summary of Significant Accounting Policies within the consolidated financialstatements included elsewhere in this Annual Report.ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKCommodity Price RiskOur major market risk exposure is the pricing of oil, natural gas, and NGLs produced by our operators. Realized prices are primarily driven by theprevailing global prices for oil and prices for natural gas and NGLs in the United States. Prices for oil, natural gas, and NGLs have been volatile for severalyears, and we expect this unpredictability to continue in the future. The prices that our operators receive for production depend on many factors outside ofour or their control. To reduce the impact of fluctuations in oil and natural gas prices on our revenues, we use commodity derivative financial instruments toreduce our exposure to price volatility of oil and natural gas. The counterparties to the contracts are unrelated third parties. The contracts settle monthly incash based on a designated floating price. The designated floating price is based on the NYMEX benchmark for oil and natural gas. We have not designatedany of our contracts as fair value or cash flow hedges. Accordingly, the changes in fair value of the contracts are included in net income in the period of thechange. See Note 5 – Commodity Derivative Financial Instruments and Note 6 – Fair Value Measurements to the consolidated financial statements includedelsewhere in this Annual Report for additional information.Commodity prices have declined in recent years. To estimate the effect lower prices would have on our reserves, we applied a 10% discount to the SECcommodity pricing for the twelve months ended December 31, 2018. Applying this discount results in an approximate 1.7% reduction of proved reservevolumes as compared to the undiscounted December 31, 2018 SEC pricing scenario.Counterparty and Customer Credit RiskOur derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require our counterparties to ourderivative contracts to post collateral, we do evaluate the credit standing of such counterparties as we deem appropriate. This evaluation includes reviewing acounterparty’s credit rating and latest financial information. As of December 31, 2018, we had ten counterparties, all of which are rated Baa1 or better byMoody’s. Nine of our counterparties are lenders under our credit facility.Our principal exposure to credit risk results from receivables generated by the production activities of our operators. The inability or failure of oursignificant operators to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. However, we believe thecredit risk associated with our operators and customers is acceptable.Interest Rate RiskWe have exposure to changes in interest rates on our indebtedness. As of December 31, 2018, we had $410.0 million of outstanding borrowings underour credit facility, bearing interest at a weighted-average interest rate of 4.76%. The impact of a 1% increase in the interest rate on this amount of debt wouldhave resulted in an increase in interest expense, and a corresponding decrease in our results of operations, of $4.1 million for the year ended December 31,2018, assuming that our indebtedness remained constant throughout the period. We may use certain derivative instruments to hedge our exposure to variableinterest rates in the future, but we do not currently have any interest rate hedges in place.ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATAThe information required here is included in this Annual Report beginning on page F-1. 68ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURENone.ITEM 9A. CONTROLS AND PROCEDURESEvaluation of Disclosure Controls and ProceduresAs required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of management of ourgeneral partner, including our general partner’s principal executive officer and principal financial officer, the effectiveness of the design and operation of ourdisclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this AnnualReport. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reportsthat we file or submit under the Exchange Act is accumulated and communicated to management, including our general partner’s principal executive officerand principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized, and reportedwithin the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our general partner’s principal executive officer and principalfinancial officer concluded that our disclosure controls and procedures were effective as of December 31, 2018 to provide such reasonable assurance. Management’s Annual Report on Internal Control over Financial ReportingOur general partner’s management, including our general partner’s principal executive officer and principal financial officer, is responsible forestablishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Exchange Act. Our internal controlover financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financialstatements for external purposes in accordance with U.S. GAAP.There are inherent limitations in the effectiveness of internal control over financial reporting, including the possibility that misstatements may not beprevented or detected. Accordingly, even effective internal controls over financial reporting can provide only reasonable assurance with respect to financialstatement preparation.Under the supervision and with the participation of our general partner's principal executive officer and principal financial officer, our general partner’smanagement assessed the effectiveness of our internal control over financial reporting as of December 31, 2018, using the criteria in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, ourgeneral partner’s management believes that our internal control over financial reporting was effective as of December 31, 2018.This Annual Report includes an attestation report of Ernst & Young LLP, our independent registered public accounting firm, on our internal control overfinancial reporting as of December 31, 2018, which is included in the Annual Report on page F-3.Changes in Internal Control over Financial ReportingThere were no changes in our system of internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the ExchangeAct) during the quarter ended December 31, 2018, that have materially affected, or are reasonably likely to materially affect, our internal control overfinancial reporting. ITEM 9B. OTHER INFORMATIONNone.69PART III ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCEInformation required by this item is incorporated by reference to the material appearing in our Proxy Statement for the 2019 Annual Meeting of LimitedPartners (“2019 Proxy Statement”), which will be filed with the SEC not later than 120 days after December 31, 2018.We have a Code of Business Conduct and Ethics that applies to our directors, officers, and employees as well as a Financial Code of Ethics that appliesto our Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer, and the other senior financial officers, each as required by SEC and NYSErules. Each of the foregoing is available on our website at www.blackstoneminerals.com in the “Corporate Governance” section. We will provide copies, freeof charge, of any of the foregoing upon receipt of a written request to Black Stone Minerals, L.P., 1001 Fannin Street, Suite 2020, Houston, Texas 77002,Attn: Investor Relations. We intend to disclose amendments to and waivers from our Financial Code of Ethics, if any, on our website,www.blackstoneminerals.com, promptly following the date of any such amendment or waiver.ITEM 11. EXECUTIVE COMPENSATIONInformation required by this item is incorporated by reference to the 2019 Proxy Statement, which will be filed with the SEC not later than 120 days afterDecember 31, 2018.ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERSInformation required by this item is incorporated by reference to the 2019 Proxy Statement, which will be filed with the SEC not later than 120 days afterDecember 31, 2018.ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCEInformation required by this item is incorporated by reference to the 2019 Proxy Statement, which will be filed with the SEC not later than 120 days afterDecember 31, 2018.ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICESInformation required by this item is incorporated by reference to the 2019 Proxy Statement, which will be filed with the SEC not later than 120 days afterDecember 31, 2018.70PART IV ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES(a)(1) Financial StatementsOur Consolidated Financial Statements are included under Part II, Item 8 of this Annual Report. For a listing of these statements and accompanyingnotes, please read “Index to Financial Statements” on page F-1 of this Annual Report.(a)(2) Financial Statement SchedulesAll schedules have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidatedfinancial statements or notes thereto.(a)(3) ExhibitsThe following documents are filed as a part of this Annual Report or incorporated by reference:Exhibit Number Description 2.1** Purchase and Sale Agreement, dated as of November 22, 2017, by and among Noble Energy Inc., Noble Energy Wyco, LLC, NobleEnergy US Holdings, LLC, Rosetta Resources Operating LP, and Black Stone Minerals Company, L.P. (incorporated herein by referenceto Exhibit 2.1 of Black Stone Minerals, L.P.'s Current Report on Form 8-K filed on November 29, 2017 (SEC File No. 001-37362)) 3.1 Certificate of Limited Partnership of Black Stone Minerals, L.P. (incorporated herein by reference to Exhibit 3.1 to Black Stone Minerals,L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)). 3.2 Certificate of Amendment to Certificate of Limited Partnership of Black Stone Minerals, L.P. (incorporated herein by reference to Exhibit3.2 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)). 3.3 First Amended and Restated Agreement of Limited Partnership of Black Stone Minerals, L.P., dated May 6, 2015, by and among BlackStone Minerals GP, L.L.C. and Black Stone Minerals Company, L.P., (incorporated herein by reference to Exhibit 3.1 of Black StoneMinerals, L.P.’s Current Report on Form 8-K filed on May 6, 2015 (SEC File No. 001-37362)). 3.4 Amendment No. 1 to First Amended and Restated Agreement of Limited Partnership of Black Stone Minerals, L.P., dated as of April 15,2016 (incorporated herein by reference to Exhibit 3.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on April 19, 2016(SEC File No. 001-37362)). 3.5 Amendment No. 2 to First Amended and Restated Agreement of Limited Partnership of Black Stone Minerals, L.P., dated as ofNovember 28, 2017 (incorporated herein by reference to Exhibit 3.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed onNovember 29, 2017 (SEC File No. 001-37362)). 3.6 Amendment No. 3 to First Amended and Restated Agreement of Limited Partnership of Black Stone Minerals, L.P., dated as of December11, 2017 (incorporated herein by reference to Exhibit 3.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on December12, 2017 (SEC File No. 001-37362)). 4.1 Registration Rights Agreement, dated as of November 28, 2017, by and between Black Stone Minerals, L.P. and Minerals Royalties One,L.L.C. (incorporated herein by reference to Exhibit 4.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on December 12,2017 (SEC File No. 001-37362)). 10.1^ Black Stone Minerals, L.P. Long-Term Incentive Plan, dated May 6, 2015, by Black Stone Minerals GP, L.L.C. (incorporated herein byreference to Exhibit 10.1 Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on May 6, 2015 (SEC File No. 001-37362)). 7110.2 Fourth Amended and Restated Credit Agreement, among Black Stone Minerals Company, L.P., as Borrower, Black Stone Minerals, L.P.,as Parent MLP, Wells Fargo Bank, National Association, as Administrative Agent, Bank of America, N.A. and Compass Bank, as Co-Syndication Agents, ZB Bank, N.A. DBA and Amegy Bank National Association, as Documentation Agent, and the lenders signatorythereto, dated as of November 1, 2017 (incorporated herein by reference to Exhibit 10.1 to Black Stone Minerals, L.P.’s Current Report onForm 8-K filed on November 7, 2017 (SEC File No. 001-37362)). 10.3 First Amendment to Fourth Amended and Restated Credit Agreement among Black Stone Minerals Company, L.P., as Borrower, WellsFargo Bank, National Association, as Administrative Agent and Swingline Lender, Bank of America, N.A. and Compass Bank, as Co-Syndication Agents, ZB Bank, N.A., DBA Amegy Bank, National Association, as Documentation Agent, and a syndicate of lenders datedas of February 7, 2018. 10.4 Second Amendment to Fourth Amended and Restated Credit Agreement among Black Stone Minerals Company, L.P., as Borrower, BlackStone Minerals, L.P., as Parent MLP, Wells Fargo Bank, National Association, as Administrative Agent, and a syndicate of lenders datedas of October 31, 2018 (incorporated herein by reference to Exhibit 10.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filedon November 5, 2018 (SEC File No. 001-37362)). 10.5^ Employment Agreement by and between Black Stone Minerals Company, L.P. and Thomas L. Carter, Jr. effective as of April 1, 2009(incorporated herein by reference to Exhibit 10.3 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19,2015 (SEC File No. 333-202875)). 10.6^ First Amendment to Employment Agreement by and between Black Stone Minerals Company, L.P. and Thomas L. Carter, Jr. effective asof June 25, 2014 (incorporated herein by reference to Exhibit 10.4 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1filed on March 19, 2015 (SEC File No. 333-202875)). 10.7^ Form of IPO Award Grant Notice and Award Agreement for Senior Management (Restricted Units) (incorporated herein by reference toExhibit 10.9 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on April 13, 2015 (SEC File No. 333-202875)). 10.8^ Form of IPO Award Grant Notice and Award Agreement for Senior Management (Performance Units) (incorporated herein by reference toExhibit 10.10 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on April 13, 2015 (SEC File No. 333-202875)). 10.9^ Form of Non-Employee Director Unit Grant Notice and Award Agreement (incorporated herein by reference to Exhibit 10.11 to BlackStone Minerals, L.P.’s Registration Statement on Form S-1 filed on April 13, 2015 (SEC File No. 333-202875)). 10.10^ Form of Severance Agreement for Thomas L. Carter, Jr. (incorporated herein by reference to Exhibit 10.12 to Black Stone Minerals, L.P.’sRegistration Statement on Form S-1 filed on April 13, 2015 (SEC File No. 333-202875)). 10.11^ Form of Severance Agreement for Senior Vice Presidents (incorporated herein by reference to Exhibit 10.13 to Black Stone Minerals,L.P.’s Registration Statement on Form S-1 filed on April 13, 2015 (SEC File No. 333-202875)). 10.12^ Form of LTI Award Grant Notice and LTI Award Agreement (Leadership) under the Black Stone Minerals, L.P. Long-Term Incentive Plan(incorporated herein by reference to Exhibit 10.2 to Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on February 19, 2016(SEC File No. 001-37362). 10.13^ Form of STI Award Letter (Leadership) under the Black Stone Minerals, L.P. Long-Term Incentive Plan (incorporated herein by referenceto Exhibit 10.17 of Black Stone Minerals, L.P.'s Annual Report on Form 10-K filed on February 28, 2018 (SEC File No. 001-37362)). 10.14 Series B Preferred Unit Purchase Agreement, dated as of November 22, 2017, by and between Black Stone Minerals, L.P. and MineralRoyalties One, L.L.C. (incorporated herein by reference to Exhibit 10.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filedon December 12, 2017 (SEC File No. 001-37362)). 21.1* List of Subsidiaries of Black Stone Minerals, L.P. 23.1* Consent of Ernst & Young LLP 23.2* Consent of Netherland, Sewell & Associates, Inc. 31.1* Certification of Chief Executive Officer of Black Stone Minerals, L.P. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 31.2* Certification of Chief Financial Officer of Black Stone Minerals, L.P. pursuant to Section 302 of the Sarbanes-Oxley Act of 200272 32.1* Certification of Chief Executive Officer and Chief Financial Officer of Black Stone Minerals, L.P. pursuant to 18 U.S.C. Section 1350, asadopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 99.1* Report of Netherland, Sewell & Associates, Inc. 101.INS* XBRL Instance Document. 101.SCH* XBRL Taxonomy Schema Document. 101.CAL* XBRL Taxonomy Calculation Linkbase Document. 101.DEF* XBRL Taxonomy Definition Linkbase Document. 101.LAB* XBRL Taxonomy Label Linkbase Document. 101.PRE* XBRL Taxonomy Presentation Linkbase Document.*Filed herewith.**Schedules and exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The Partnership agrees to furnish supplementally a copy of theomitted schedules and exhibits to the SEC upon request.^Management contract or compensatory plan or arrangement.73SIGNATURESPursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned,thereunto duly authorized. BLACK STONE MINERALS, L.P. By: Black Stone Minerals GP, L.L.C.,its general partner Date: February 26, 2019 By: /s/ Thomas L. Carter, Jr. Thomas L. Carter, Jr. Chief Executive Officer and Chairman 74Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report has been signed below by the following persons on behalf of theregistrant and in the capacities and on the dates indicated.Signature Title Date /s/ Thomas L. Carter, Jr. Chief Executive Officer and Chairman February 26, 2019Thomas L. Carter, Jr. (Principal Executive Officer) /s/ Jeffrey P. Wood President and Chief Financial Officer February 26, 2019Jeffrey P. Wood (Principal Financial Officer) /s/ Dawn K. Smajstrla Vice President and Chief Accounting Officer February 26, 2019Dawn K. Smajstrla (Principal Accounting Officer) /s/ William G. Bardel Director February 26, 2019William G. Bardel /s/ Carin M. Barth Director February 26, 2019Carin M. Barth /s/ D. Mark DeWalch Director February 26, 2019D. Mark DeWalch /s/ Ricky J. Haeflinger Director February 26, 2019Ricky J. Haeflinger /s/ Jerry V. Kyle, Jr. Director February 26, 2019Jerry V. Kyle, Jr. /s/ Michael C. Linn Director February 26, 2019Michael C. Linn /s/ John H. Longmaid Director February 26, 2019John H. Longmaid /s/ William N. Mathis Director February 26, 2019William N. Mathis /s/ William E. Randall Director February 26, 2019William E. Randall /s/ Alexander D. Stuart Director February 26, 2019Alexander D. Stuart /s/ Allison K. Thacker Director February 26, 2019Allison K. Thacker 75INDEX TO CONSOLIDATED FINANCIAL STATEMENTSBLACK STONE MINERALS, L.P. Reports of Independent Registered Public Accounting Firm F-2 Consolidated Balance Sheets as of December 31, 2018 and December 31, 2017 F-4 Consolidated Statements of Operations for the Years Ended December 31, 2018, 2017 and 2016 F-5 Consolidated Statements of Equity for the Years Ended December 31, 2018, 2017 and 2016 F-6 Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 2017 and 2016 F-7 Notes to Consolidated Financial Statements F-8F-1REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMTo the Audit Committee of the Board of Directors and Unitholders ofBlack Stone Minerals, L.P. and subsidiariesOpinion on the Financial StatementsWe have audited the accompanying consolidated balance sheets of Black Stone Minerals, L.P. and subsidiaries (the “Partnership”) as of December 31, 2018and 2017, the related consolidated statements of operations, equity and cash flows for each of the three years in the period ended December 31, 2018, and therelated notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in allmaterial respects, the financial position of the Partnership at December 31, 2018 and 2017, and the results of its operations and its cash flows for each of thethree years in the period ended December 31, 2018, in conformity with U.S. generally accepted accounting principles.We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Partnership’sinternal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control-Integrated Framework issued by theCommittee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 26, 2019 expressed an unqualifiedopinion thereon.Basis for OpinionThese financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financialstatements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnershipin accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonableassurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing proceduresto assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks.Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also includedevaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financialstatements. We believe that our audits provide a reasonable basis for our opinion./s/ Ernst & Young LLPWe have served as the Partnership’s auditor since 2016.Houston, TexasFebruary 26, 2019F-2REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMTo the Audit Committee of the Board of Directors and Unitholders ofBlack Stone Minerals, L.P. and subsidiariesOpinion on Internal Control over Financial ReportingWe have audited Black Stone Minerals, L.P. and subsidiaries’ internal control over financial reporting as of December 31, 2018, based on criteria establishedin Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the “COSOcriteria”). In our opinion, Black Stone Minerals, L.P. and subsidiaries (the “Partnership”) maintained, in all material respects, effective internal control overfinancial reporting as of December 31, 2018, based on the COSO criteria.We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidatedbalance sheets of the Partnership as of December 31, 2018 and 2017, the related consolidated statements of operations, equity and cash flows for each of thethree years in the period ended December 31, 2018, and the related notes and our report dated February 26, 2019 expressed an unqualified opinion thereon.Basis for OpinionThe Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness ofinternal control over financial reporting included in the accompanying “Management’s Annual Report on Internal Control over Financial Reporting.” Ourresponsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firmregistered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and theapplicable rules and regulations of the Securities and Exchange Commission and the PCAOB.We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonableassurance about whether effective internal control over financial reporting was maintained in all material respects.Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing andevaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considerednecessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.Definition and Limitations of Internal Control Over Financial ReportingA partnership’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reportingand the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A partnership’s internalcontrol over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately andfairly reflect the transactions and dispositions of the assets of the partnership; (2) provide reasonable assurance that transactions are recorded as necessary topermit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the partnershipare being made only in accordance with authorizations of management and directors of the partnership; and (3) provide reasonable assurance regardingprevention or timely detection of unauthorized acquisition, use, or disposition of the partnership’s assets that could have a material effect on the financialstatements.Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation ofeffectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliancewith the policies or procedures may deteriorate./s/ Ernst & Young LLPHouston, TexasFebruary 26, 2019F-3BLACK STONE MINERALS, L.P. AND SUBSIDIARIESCONSOLIDATED BALANCE SHEETS(in thousands) As of December 31, 2018 2017ASSETS CURRENT ASSETS Cash and cash equivalents$5,414 $5,642Accounts receivable113,148 80,695Commodity derivative assets37,970 94Prepaid expenses and other current assets1,001 1,212TOTAL CURRENT ASSETS157,533 87,643PROPERTY AND EQUIPMENT Oil and natural gas properties, at cost, using the successful efforts method of accounting, includes unproved properties of $1,063,883 and$988,720 at December 31, 2018 and 2017, respectively3,441,188 3,247,613Accumulated depreciation, depletion, amortization, and impairment(1,865,692) (1,766,842)Oil and natural gas properties, net1,575,496 1,480,771Other property and equipment, net of accumulated depreciation of $11,048 and $14,433 at December 31, 2018 and 2017, respectively385 559NET PROPERTY AND EQUIPMENT1,575,881 1,481,330DEFERRED CHARGES AND OTHER LONG-TERM ASSETS16,710 7,478TOTAL ASSETS$1,750,124 $1,576,451LIABILITIES, MEZZANINE EQUITY, AND EQUITY CURRENT LIABILITIES Accounts payable$4,149 $2,464Accrued liabilities60,089 52,631Commodity derivative liabilities— 4,222Other current liabilities528 417TOTAL CURRENT LIABILITIES64,766 59,734LONG-TERM LIABILITIES Credit facility410,000 388,000Accrued incentive compensation1,813 3,648Commodity derivative liabilities— 1,263Asset retirement obligations14,948 14,092Other long-term liabilities55,973 19,171TOTAL LIABILITIES547,500 485,908COMMITMENTS AND CONTINGENCIES (Note 11) MEZZANINE EQUITY Partners' equity — Series A redeemable preferred units, zero and 26 units outstanding at December 31, 2018 and 2017, respectively— 27,028Partners' equity — Series B cumulative convertible preferred units, 14,711 and 14,711 units outstanding at December 31, 2018 and 2017,respectively298,361 295,394EQUITY Partners' equity — general partner interest— —Partners' equity — common units, 108,363 and 103,456 units outstanding at December 31, 2018 and 2017, respectively714,823 603,116Partners' equity — subordinated units, 96,329 and 95,388 units outstanding at December 31, 2018 and 2017, respectively189,440 164,138Noncontrolling interests— 867TOTAL EQUITY904,263 768,121TOTAL LIABILITIES, MEZZANINE EQUITY, AND EQUITY$1,750,124 $1,576,451 The accompanying notes to consolidated financial statements are an integral part of these financial statements.F-4BLACK STONE MINERALS, L.P. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF OPERATIONS(in thousands, except per unit amounts) Year Ended December 31, 2018 2017 2016REVENUE Oil and condensate sales$310,278 $169,728 $142,382Natural gas and natural gas liquids sales248,243 190,967 122,836Lease bonus and other income36,216 42,062 32,079Revenue from contracts with customers594,737 402,757 297,297Gain (loss) on commodity derivative instruments14,831 26,902 (36,464)TOTAL REVENUE609,568 429,659 260,833OPERATING (INCOME) EXPENSE Lease operating expense18,415 17,280 18,755Production costs and ad valorem taxes64,364 47,474 35,464Exploration expense7,943 618 645Depreciation, depletion and amortization122,653114,534102,487Impairment of oil and natural gas properties——6,775General and administrative76,712 77,574 73,139Accretion of asset retirement obligations1,1031,026892(Gain) loss on sale of assets, net(3) (931) (4,793)TOTAL OPERATING EXPENSE291,187 257,575 233,364INCOME (LOSS) FROM OPERATIONS318,381 172,084 27,469OTHER INCOME (EXPENSE) Interest and investment income183 49 656Interest expense(20,756) (15,694) (7,547)Other income (expense)(2,248) 714 (390)TOTAL OTHER EXPENSE(22,821) (14,931) (7,281)NET INCOME (LOSS)295,560 157,153 20,188Net (income) loss attributable to noncontrolling interests(24) 34 12Distributions on Series A redeemable preferred units(25) (3,117) (5,763)Distributions on Series B cumulative convertible preferred units(21,000) (1,925) —NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATEDUNITS$274,511 $152,145 $14,437ALLOCATION OF NET INCOME (LOSS): General partner interest$— $— $—Common units154,662 98,389 24,669Subordinated units119,849 53,756 (10,232) $274,511 $152,145 $14,437NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT: Per common unit (basic)$1.46 $1.01 $0.26Weighted average common units outstanding (basic)106,064 97,400 96,073Per subordinated unit (basic)$1.25 $0.56 $(0.11)Weighted average subordinated units outstanding (basic)96,099 95,149 95,138Per common unit (diluted)$1.45 $1.01 $0.26Weighted average common units outstanding (diluted)121,264 97,400 96,243Per subordinated unit (diluted)$1.25 $0.56 $(0.11)Weighted average subordinated units outstanding (diluted)96,346 95,149 95,138The accompanying notes to consolidated financial statements are an integral part of these financial statements.F-5BLACK STONE MINERALS, L.P. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF EQUITY(in thousands) Commonunits Subordinatedunits Partners'equity—commonunits Partners'equity—subordinatedunits Noncontrollinginterests TotalequityBALANCE AT DECEMBER 31, 201596,162 95,057 $574,648 $255,699 $1,144 $831,491Conversion of Series A redeemable preferred units184 241 2,625 3,439 — 6,064Repurchases of common and subordinated units(1,618) (78) (27,436) — — (27,436)Restricted common and subordinated units granted, net offorfeitures993 (56) — — — —Equity-based compensation— — 21,022 2,823 — 23,845Distributions— — (105,817) (70,127) (111) (176,055)Charges to partners' equity for accrued distributionequivalent rights— — (688) — — (688)Net income (loss)— — 27,565 (7,365) (12) 20,188Distributions on Series A redeemable preferred units— — (2,896) (2,867) — (5,763)BALANCE AT DECEMBER 31, 201695,721 95,164 $489,023 $181,602 $1,021 $671,646Conversion of Series A redeemable preferred units201 263 2,868 3,756 — 6,624Repurchases of common and subordinated units(446) (39) (7,893) (292) — (8,185)Issuance of common units, net of offering costs2,002 — 32,458 — — 32,458Issuance of common units for property acquisitions4,348 — 71,723 — — 71,723Restricted units granted, net of forfeitures1,630 — — — — —Equity-based compensation— — 39,205 152 — 39,357Distributions— — (119,963) (74,836) (120) (194,919)Charges to partners' equity for accrued distributionequivalent rights— — (2,694) — — (2,694)Net income (loss)— — 101,891 55,296 (34) 157,153Distributions on Series A redeemable preferred units— — (1,577) (1,540) — (3,117)Distributions on Series B cumulative convertible preferredunits— — (1,925) — — (1,925)BALANCE AT DECEMBER 31, 2017103,456 95,388 $603,116 $164,138 $867 $768,121Conversion of Series A redeemable preferred units736 964 10,498 13,750 — 24,248Repurchases of common and subordinated units(623) (23) (10,879) (342) — (11,221)Purchase of noncontrolling interests— — (1,026) — (680) (1,706)Issuance of common units, net of offering costs2,244 — 40,537 — — 40,537Issuance of common units for property acquisitions1,234 — 22,657 — — 22,657Restricted units granted, net of forfeitures1,316 — — — — —Equity-based compensation— — 40,733 219 — 40,952Distributions— — (141,777) (108,174) (211) (250,162)Charges to partners' equity for accrued distributionequivalent rights— — (3,698) — — (3,698)Distributions on Series A redeemable preferred units— — (13) (12) — (25)Distributions on Series B cumulative convertible preferredunits— — (21,000) — — (21,000)Net income (loss)— — 175,675 119,861 24 295,560BALANCE AT DECEMBER 31, 2018108,363 96,329 $714,823 $189,440 $— $904,263The accompanying notes to consolidated financial statements are an integral part of these financial statements.F-6BLACK STONE MINERALS, L.P. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF CASH FLOWS(in thousands) Year Ended December 31, 2018 2017 2016CASH FLOWS FROM OPERATING ACTIVITIES Net income (loss)295,560 $157,153 $20,188Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation, depletion, and amortization122,653 114,534 102,487Impairment of oil and natural gas properties— — 6,775Accretion of asset retirement obligations1,103 1,026 892Amortization of deferred charges905 877 871(Gain) loss on commodity derivative instruments(14,831) (26,902) 36,464Net cash (paid) received on settlement of commodity derivative instruments(38,235) 15,211 44,789Equity-based compensation30,134 33,044 43,138Exploratory dry hole expense6,785 — —Deferred rent1,283 — —(Gain) loss on sale of assets, net(3) (931) (4,793)Changes in operating assets and liabilities: Accounts receivable(31,531) (6,084) (29,759)Prepaid expenses and other current assets210 (177) (180)Accounts payable, accrued liabilities, and other11,474 (5,671) (23,899)Settlement of asset retirement obligations(129) (228) (317)NET CASH PROVIDED BY OPERATING ACTIVITIES385,378 281,852 196,656CASH FLOWS FROM INVESTING ACTIVITIES Acquisitions of oil and natural gas properties(124,081) (425,667) (141,136)Additions to oil and natural gas properties(166,970) (55,842) (79,003)Additions to oil and natural gas properties leasehold costs(6,263) (2,806) (1,176)Purchases of other property and equipment(21) (207) (425)Proceeds from the sale of oil and natural gas properties9,009 11,102 198Proceeds from farmouts of oil and natural gas properties124,522 19,171 —NET CASH USED IN INVESTING ACTIVITIES(163,804) (454,249) (221,542)CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from issuance of common units, net of offering costs40,537 32,458 —Proceeds from issuance of Series B cumulative convertible preferred units, net of offering costs— 293,469 —Distributions to common and subordinated unitholders(250,121) (194,799) (175,943)Distributions to Series A redeemable preferred unitholders(690) (3,777) (6,385)Distributions to Series B cumulative convertible preferred unitholders(17,675) — —Distributions to noncontrolling interests(211) (120) (111)Redemption of Series A redeemable preferred units(2,115) (19,704) (18,461)Repurchases of common and subordinated units(10,579) (8,185) (27,436)Purchase of noncontrolling interests(1,706) — —Borrowings under credit facility373,500 292,500 349,000Repayments under credit facility(351,500) (220,500) (99,000)Debt issuance costs and other(1,242) (3,075) (239)NET CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES(221,802) 168,267 21,425NET CHANGE IN CASH AND CASH EQUIVALENTS(228) (4,130) (3,461)Cash and cash equivalents — beginning of the year5,642 9,772 13,233Cash and cash equivalents — end of the year$5,414 $5,642 $9,772SUPPLEMENTAL DISCLOSURE Interest paid$19,761 $14,761 $6,535 The accompanying notes to consolidated financial statements are an integral part of these financial statements.F-7BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSNOTE 1 — BUSINESS AND BASIS OF PRESENTATIONDescription of the BusinessBlack Stone Minerals, L.P. (“BSM” or the “Partnership”) is a publicly traded Delaware limited partnership that owns oil and natural gas mineral interests,which make up the vast majority of the asset base. The Partnership's assets also include nonparticipating royalty interests and overriding royalty interests.These interests, which are substantially non-cost-bearing, are collectively referred to as “mineral and royalty interests.” The Partnership’s mineral and royaltyinterests are located in 41 states in the continental U.S., including all of the major onshore producing basins. The Partnership also owns non-operatedworking interests in certain oil and natural gas properties. On May 6, 2015, we completed our initial public offering (the "IPO") of 22,500,000 common unitsrepresenting limited partner interests. The Partnership's common units trade on the New York Stock Exchange under the symbol "BSM."Basis of PresentationThe accompanying audited consolidated financial statements of the Partnership have been prepared in accordance with generally accepted accountingprinciples (“GAAP”) in the U.S. and pursuant to the rules and regulations of the U.S. Securities and Exchange Commission ("SEC").The consolidated financial statements include the consolidated results of the Partnership, which also includes the results of the Noble Acquisition (asdefined below) for the period from November 28, 2017 through December 31, 2018, as discussed in Note 4 – Oil and Natural Gas Properties Acquisitions.In the opinion of management, all adjustments, which are of a normal and recurring nature, necessary for the fair presentation of the financial results forall periods presented have been reflected. All intercompany balances and transactions have been eliminated. Certain reclassifications have been made to theprior periods presented to conform to the current period financial statement presentation. The reclassifications have no effect on the consolidated financialposition, results of operations, or cash flows of the Partnership.The Partnership evaluates the significant terms of its investments to determine the method of accounting to be applied to each respective investment.Investments in which the Partnership has less than a 20% ownership interest and does not have control or exercise significant influence are accounted forusing fair value or cost minus impairment if fair value is not readily determinable. Investments in which the Partnership exercises control are consolidated,and the noncontrolling interests of such investments, which are not attributable directly or indirectly to the Partnership, are presented as a separatecomponent of net income and equity in the accompanying consolidated financial statements.The consolidated financial statements include undivided interests in oil and natural gas property rights. The Partnership accounts for its share of oil andnatural gas property rights by reporting its proportionate share of assets, liabilities, revenues, costs, and cash flows within the relevant lines on theaccompanying consolidated balance sheets, statements of operations, and statements of cash flows.Segment ReportingThe Partnership operates in a single operating and reportable segment. Operating segments are defined as components of an enterprise for which separatefinancial information is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assess performance. ThePartnership’s chief executive officer has been determined to be the chief operating decision maker and allocates resources and assesses performance basedupon financial information at the consolidated level. F-8BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSNOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIESUse of EstimatesThe preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect thereported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, as well asreported amounts of revenues and expenses for the periods herein. Actual results could differ from those estimates.The Partnership’s consolidated financial statements are based on a number of significant estimates including oil and natural gas reserve quantities thatare the basis for the calculations of depreciation, depletion, and amortization (“DD&A”) and impairment of oil and natural gas properties. Reservoirengineering is a subjective process of estimating underground accumulations of oil and natural gas. There are numerous uncertainties inherent in estimatingquantities of proved oil and natural gas reserves. The accuracy of any reserve estimates is a function of the quality of available data and of engineering andgeological interpretation and judgment. As a result, reserve estimates may differ from the quantities of oil and natural gas that are ultimately recovered. ThePartnership’s reserve estimates are determined by an independent petroleum engineering firm. Other items subject to significant estimates and assumptionsinclude the carrying amount of oil and natural gas properties, valuation of commodity derivative financial instruments, valuation of future asset retirementobligations (“ARO”), determination of revenue accruals, and the determination of the fair value of equity-based awards.The Partnership evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economicand commodity price environment. The volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions. Asignificant decline in oil or natural gas prices could result in a reduction in the Partnership’s fair value estimates and cause the Partnership to performanalyses to determine if its oil and natural gas properties are impaired. As future commodity prices cannot be predicted accurately, actual results could differsignificantly from estimates.Cash and Cash EquivalentsThe Partnership considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.Accounts ReceivableThe Partnership’s accounts receivable balance results primarily from operators’ sales of oil and natural gas to their customers. Accounts receivable arerecorded at the contractual amounts and do not bear interest. Any concentration of customers may impact the Partnership’s overall credit risk, eitherpositively or negatively, in that these entities may be similarly affected by changes in economic or other conditions impacting the oil and natural gasindustry.The following table presents information about the Partnership's accounts receivable: December 31, 2018 December 31, 2017 (in thousands)Accounts receivable: Revenues from contracts with customers $107,804 $77,544Other 5,344 3,151Total accounts receivable $113,148 $80,695Commodity Derivative Financial InstrumentsThe Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To mitigate the given price risk associated with itsoperations, the Partnership uses commodity derivative financial instruments. From time to time, such instruments may include variable-to-fixed-price swaps,costless collars, fixed-price contracts, and other contractual arrangements. The Partnership does not enter into derivative instruments for speculative purposes.F-9BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSDerivative instruments are recognized at fair value. If a right of offset exists under master netting arrangements and certain other criteria are met,derivative assets and liabilities with the same counterparty are netted on the consolidated balance sheets. The Partnership does not specifically designatederivative instruments as cash flow hedges, even though they reduce its exposure to changes in oil and natural gas prices; therefore, gains and losses arisingfrom changes in the fair value of derivative instruments are recognized on a net basis in the accompanying consolidated statements of operations within gain(loss) on commodity derivative instruments.Concentration of Credit RiskFinancial instruments that potentially subject the Partnership to credit risk consist principally of cash and cash equivalents, accounts receivable, andcommodity derivative financial instruments.The Partnership maintains cash and cash equivalent balances with major financial institutions. At times, those balances exceed federally insured limits;however, no losses have been incurred.The Partnership’s customer base is made up of its lessees, which consist of integrated oil and gas companies to independent producers and operators. ThePartnership’s credit risk may also include the purchasers of oil and natural gas produced from the Partnership’s properties. The Partnership attempts to limitthe amount of credit exposure to any one company through procedures that include credit approvals, credit limits and terms, and prepayments. ThePartnership believes the credit quality of its customer base is high and has not experienced significant write-offs in its accounts receivable balances. See Note7 – Significant Customers for further discussion.Commodity derivative financial instruments may expose the Partnership to credit risk; however, the Partnership monitors the creditworthiness of itscounterparties. See Note 5 – Commodity Derivative Financial Instruments for further discussion.Oil and Natural Gas PropertiesThe Partnership follows the successful efforts method of accounting for oil and natural gas operations. Under this method, costs to acquire mineral androyalty interests and working interests in oil and natural gas properties, property acquisitions, successful exploratory wells, development costs, and supportequipment and facilities are capitalized when incurred. Acquisitions of proved oil and natural gas properties and working interests are considered businesscombinations and are recorded at their estimated fair value as of the acquisition date. Acquisitions of unproved oil and natural gas properties are consideredasset acquisitions and are recorded at cost.The costs of unproved leasehold and non-producing mineral interests are capitalized as unproved properties pending the results of exploration andleasing efforts. As unproved properties are determined to be productive, the related costs are transferred to proved oil and natural gas properties. The costsrelated to exploratory wells are capitalized pending determination of whether proved commercial reserves exist. If proved commercial reserves are notdiscovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether proved commercial reserves have been discovered whendrilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify completion as aproducing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is ongoing. Other exploratory costs,including annual delay rentals and geological and geophysical costs, are expensed when incurred.Oil and natural gas properties are grouped in accordance with the Extractive Industries – Oil and Gas Topic of the Financial Accounting Standards Board("FASB") Accounting Standards Codification ("ASC"). The basis for grouping is a reasonable aggregation of properties with a common geological structuralfeature or stratigraphic condition, such as a reservoir or field, which we may also refer to as a depletable unit.As exploration and development work progresses and the reserves associated with the Partnership’s oil and natural gas properties become proved,capitalized costs attributed to the properties are charged as an operating expense through DD&A. DD&A of producing oil and natural gas properties isrecorded based on the units-of-production method. Capitalized development costs are amortized on the basis of proved developed reserves while leaseholdacquisition costs and the costs to acquire proved properties are amortized on the basis of all proved reserves, both developed and undeveloped. Provedreserves are quantities of oil and natural gas that can be estimated with reasonable certainty to be economically producible from a given date forward, fromknown reservoirs, under existing economic conditions, operating methods, and government regulations. DD&A expense related to the Partnership’sproducing oil and natural gas properties was $122.5 million, $114.3 million, and $102.4 million for the years ended December 31, 2018, 2017, and 2016,respectively.F-10BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSThe Partnership evaluates impairment of producing properties whenever events or changes in circumstances indicate that the carrying amount of an assetmay not be recoverable. This evaluation is performed on a depletable unit basis. The Partnership compares the undiscounted projected future cash flowsexpected in connection with a depletable unit to its unamortized carrying amount to determine recoverability. When the carrying amount of a depletable unitexceeds its estimated undiscounted future cash flows, the carrying amount is written down to its fair value, which is measured as the present value of theprojected future cash flows of such properties. The factors used to determine fair value include estimates of proved developed and proved undevelopedreserves, future commodity prices, timing of future production, future capital expenditures, and a risk-adjusted discount rate.There was no impairment of proved oil and natural gas properties for the years ended December 31, 2018 and 2017. Impairment of proved oil and naturalgas properties was $4.9 million for the year ended December 31, 2016. The impairment primarily resulted from declines in future expected realizable net cashflows. The charge is included in impairment of oil and natural gas properties on the consolidated statements of operations and reflected in the net book valueof oil and natural gas properties.Unproved properties are also assessed for impairment periodically on a depletable unit basis when facts and circumstances indicate that the carryingvalue may not be recoverable, at which point an impairment loss is recognized to the extent the carrying value exceeds the estimated recoverable value. Thecarrying value of unproved properties, including unleased mineral rights, is determined based on management’s assessment of fair value using factors similarto those previously noted for proved properties, as well as geographic and geologic data. There was no impairment of unproved properties for the years endedDecember 31, 2018 and 2017. Impairment of unproved properties was $1.9 million for the year ended December 31, 2016, as included in impairment of oiland natural gas properties on the consolidated statements of operations and reflected in the net book value of oil and natural gas properties.Upon the sale of a complete depletable unit, the book value thereof, less proceeds or salvage value, is charged to income. Upon the sale or retirement ofan individual well, or an aggregation of interests which make up less than a complete depletable unit, the proceeds are credited to accumulated DD&A, unlessdoing so would significantly alter the DD&A rate of the depletable unit, in which case a gain or loss would be recorded.Other Property and EquipmentOther property and equipment includes furniture, fixtures, office equipment, leasehold improvements, and computer software and is stated at historicalcost. Depreciation and amortization are calculated using the straight-line method over expected useful lives ranging from three to seven years. Depreciationand amortization expense totaled $0.2 million, $0.2 million, and $0.1 million for the years ended December 31, 2018, 2017, and 2016, respectively.Repairs and MaintenanceThe cost of normal maintenance and repairs is charged to expense as incurred. Material expenditures that increase the life of an asset are capitalized anddepreciated over the shorter of the estimated remaining useful life of the asset or the term of the lease, if applicable.Accrued LiabilitiesAccrued liabilities consisted of the following: December 31, 2018 2017Accrued liabilities: (in thousands)Accrued capital expenditures $32,945 $28,711Accrued incentive compensation 16,109 16,503Accrued property taxes 5,822 4,090Accrued other 5,213 3,327Total accrued liabilities $60,089 $52,631F-11BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSDebt Issuance CostsDebt issuance costs consist of costs directly associated with obtaining credit with financial institutions. These costs are capitalized and are amortized ona straight-line basis over the life of the credit agreement, which approximates the effective-interest method. Any unamortized debt issuance costs areexpensed in the year when the associated debt instrument is terminated. Amortization expense for debt issuance costs was $0.9 million, $0.9 million, and$0.9 million for the years ended December 31, 2018, 2017, and 2016, respectively, and is included in interest expense in the consolidated statements ofoperations.Asset Retirement ObligationsFair values of legal obligations to retire and remove long-lived assets are recorded when the obligation is incurred and becomes determinable. When theliability is initially recorded, the Partnership capitalizes this cost by increasing the carrying amount of the related property. Over time, the liability is accretedfor the change in its present value, and the capitalized cost in oil and natural gas properties is depleted based on units-of-production consistent with therelated asset.Revenues from Contracts with CustomersASC 606, Revenue from Contracts with Customers, requires the Partnership to identify the distinct promised goods and services within a contract whichrepresent separate performance obligations and determine the transaction price to allocate to the performance obligations identified. The Partnership adoptedASC 606 using the modified retrospective method, which was applied to all existing contracts for which all (or substantially all) of the revenue had not beenrecognized under legacy revenue guidance as of the date of adoption, January 1, 2018.Oil and natural gas salesSales of oil and natural gas are recognized at the point control of the product is transferred to the customer and collectability of the sales price isreasonably assured. Oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality andphysical location. The price the Partnership receives for natural gas is tied to a market index, with certain adjustments based on, among other factors, whethera well delivers to a gathering or transmission line, quality and heat content of natural gas, and prevailing supply and demand conditions, so that the price ofnatural gas fluctuates to remain competitive with other available natural gas supplies. As each unit of product represents a separate performance obligationand the consideration is variable as it relates to oil and natural gas prices, we recognize revenue from oil and natural gas sales using the practical expedientfor variable consideration in ASC 606.Lease bonus and other incomeThe Partnership also earns revenue from lease bonuses and delay rentals. The Partnership generates lease bonus revenue by leasing its mineral interests toexploration and production companies. A lease agreement represents the Partnership's contract with a customer and generally transfers the rights to any oil ornatural gas discovered, grants the Partnership a right to a specified royalty interest, and requires that drilling and completion operations commence within aspecified time period. Control is transferred to the lessee and the Partnership has satisfied its performance obligation when the lease agreement is executed,such that revenue is recognized when the lease bonus payment is received. At the time the Partnership executes the lease agreement, the Partnership expectsto receive the lease bonus payment within a reasonable time, though in no case more than one year, such that the Partnership has not adjusted the expectedamount of consideration for the effects of any significant financing component per the practical expedient in ASC 606. The Partnership also recognizesrevenue from delay rentals to the extent drilling has not started within the specified period, payment has been received, and the Partnership has no furtherobligation to refund the payment.Production imbalancesThe Partnership previously elected to utilize the entitlements method to account for natural gas production imbalances, which is no longer permittedunder ASC 606. As of January 1, 2018, these amounts were de minimis. As such, upon adoption of ASC 606, there was no material impact to the financialstatements due to this change in accounting for the Partnership's production imbalances.F-12BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSAllocation of transaction price to remaining performance obligationsOil and natural gas salesThe Partnership has utilized the practical expedient in ASC 606 which states the Partnership is not required to disclose the transaction price allocated toremaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. As the Partnership hasdetermined that each unit of product generally represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of thetransaction price allocated to remaining performance obligations is not required.Lease bonus and other incomeGiven that the Partnership does not recognize lease bonus or other income until a lease agreement has been executed, at which point its performanceobligation has been satisfied, and payment is received, the Partnership does not record revenue for unsatisfied or partially unsatisfied performanceobligations as of the end of the reporting period. Overall, there were no material changes in the timing of the satisfaction of the Partnership's performanceobligations or the allocation of the transaction price to its performance obligations in applying the guidance in ASC 606 as compared to legacy U.S. GAAP.Prior-period performance obligationsThe Partnership records revenue in the month production is delivered to the purchaser. As a non-operator, the Partnership has limited visibility into thetiming of when new wells start producing and production statements may not be received for 30 to 90 days or more after the date production is delivered. As aresult, the Partnership is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of theproduct. The expected sales volumes and prices for these properties are estimated and recorded within the Accounts receivable line item in the accompanyingconsolidated balance sheets. The difference between the Partnership's estimates and the actual amounts received for oil and natural gas sales is recorded in themonth that payment is received from the third party. For the year ended December 31, 2018, revenue recognized in the reporting periods related toperformance obligations satisfied in prior reporting periods was immaterial.Income TaxesThe Partnership is organized as a pass-through entity for income tax purposes. As a result, the Partnership’s unitholders are responsible for federal andstate income taxes attributable to their share of the Partnership’s taxable income. The Partnership is subject to other state-based taxes; however, those taxesare not material. Limited partnerships that receive at least 90% of their gross income from designated passive sources, including royalties from mineralproperties and other non-operated mineral interest income, and do not receive more than 10% of their income from operating an active trade or business, areclassified as “passive entities” and are generally exempt from the Texas margin tax. The Partnership believes that it meets the requirements for beingconsidered a “passive entity” for Texas margin tax purposes. As a result, each unitholder that is considered a taxable entity under the Texas margin tax wouldgenerally be required to include its portion of the Partnership’s revenues in its own Texas margin tax computation. The Texas Administrative Code providessuch income is sourced according to the principal place of business of the Partnership, which would be the state of Texas.Fair Value of Financial InstrumentsThe carrying values of the Partnership’s current financial instruments, which include cash and cash equivalents, accounts receivable, commodityderivative financial instruments, and accounts payable, approximate their fair value at December 31, 2018 and 2017 due to the short-term maturity of theseinstruments. See Note 6 – Fair Value Measurements for further discussion.Incentive CompensationIncentive compensation includes both liability awards and equity-based awards. The Partnership recognizes compensation expense associated with itsincentive compensation awards using either straight-line or accelerated attribution over the requisite service period (generally the vesting period of theawards) depending on the given terms of the award, based on their grant date fair values. Liability awards are awards that are expected to be settled in cash oran unknown number of common or subordinated units on their vesting dates. Liability awards are recorded as accrued liabilities based on the vested portionof the estimated fair value of the awards as of the grant date, which is subject to revision based on the impact of certain performance conditions associatedwith the incentive plans.F-13BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSIncentive compensation expense is charged to general and administrative expense on the consolidated statements of operations. See Note 9 – IncentiveCompensation for additional discussion.Recent Accounting PronouncementsIn February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which supersedes the lease requirements in Topic 840, Leases by requiring lesseesto recognize lease assets and lease liabilities classified as operating leases on the balance sheet. The new lease standard is effective for fiscal years beginningafter December 15, 2018, including interim periods within those fiscal years, and early adoption was permitted.In July 2018, the FASB issued ASU 2018-11, Leases (Topic 842), Targeted Improvements, which allows entities to apply the transition provisions of thenew standard at the adoption date instead of at the earliest comparative period presented in the consolidated financial statements, and also allows entities tocontinue to apply the legacy guidance in Topic 840, including disclosure requirements, in the comparative period presented in the year the new leasesstandard is adopted. Entities that elect this option would still adopt the new leases standard using a modified retrospective transition method, but wouldrecognize a cumulative catch-up adjustment in the period of adoption rather than in the earliest period presented. The Partnership plans to use a modifiedretrospective transition method to apply the new standard to leases that exist as of the adoption date of January 1, 2019. The Partnership did not early adopt.Based on evaluations to-date, the new guidance will not have a material impact on the Partnership's consolidated financial statements and relateddisclosures as this guidance does not apply to leases to explore for or use minerals, oil, natural gas, and similar resources.In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820), which will remove, modify, and add certain required disclosureson fair value measurements. As amended, Topic 820 will no longer require the disclosure of the amount of and reasons for transfers between Level 1 andLevel 2 of the fair value hierarchy, the policy of timing of transfers between levels, and the valuation processes for Level 3 fair value measurements. Inaddition, certain modifications to current disclosure requirements will be made, including clarifying that the measurement uncertainty disclosure is tocommunicate information about the uncertainty in measurement as of the reporting date. Certain disclosure requirements will also be added, including therange and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. For certain unobservable inputs, an entitymay disclose other quantitative information in place of the weighted average if the entity determines that other quantitative information would be a morereasonable and rational method to reflect the distribution of unobservable inputs used to develop Level 3 fair value measurements. The new standard will beeffective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, and early adoption is permitted. ThePartnership does not plan to early adopt and is evaluating the impact that the new accounting guidance will have on its consolidated financial statements andrelated disclosures.NOTE 3 — ASSET RETIREMENT OBLIGATIONSThe ARO liability reflects the present value of estimated costs of dismantlement, removal, site reclamation, and similar activities associated with thePartnership’s working interest oil and natural gas properties. The Partnership utilizes current retirement costs to estimate the expected cash outflows forretirement obligations. The Partnership estimates the ultimate productive life of the properties, a credit-adjusted risk-free rate, and an inflation factor in orderto determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing AROliability, a corresponding adjustment is made to the oil and natural gas property balance.F-14BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSThe following table describes changes to the Partnership’s ARO liability for the periods presented: For the year ended December 31, 2018 2017 (in thousands)Beginning asset retirement obligations$14,509 $13,350Liabilities incurred245 308Liabilities settled(129) (228)Accretion expense1,103 1,026Revisions in estimated costs(16) 83Dispositions(237) (30)Ending asset retirement obligations$15,475 $14,509Current asset retirement obligations$527 $417Non-current asset retirement obligations$14,948 $14,092NOTE 4 — OIL AND NATURAL GAS PROPERTIES ACQUISITIONSAcquisitions of proved oil and natural gas properties and working interests are considered business combinations and are recorded at their estimated fairvalue as of the acquisition date. Acquisitions of unproved oil and natural gas properties are considered asset acquisitions and are recorded at cost.2018 AcquisitionsDuring the year ended December 31, 2018, the Partnership closed on multiple acquisitions of mineral and royalty interests for total consideration of$149.9 million.Acquisitions that included proved oil and natural gas properties were considered business combinations and were primarily located in the Permian Basin.The cash portion of the consideration paid for these acquisitions was funded with borrowings under the Partnership's Credit Facility (as defined below) andfunds from operating activities. Acquisition related costs of $0.2 million were expensed and included in the General and administrative expense line item ofthe consolidated statement of operations for the year ended December 31, 2018. The following table summarizes these acquisitions which were consideredbusiness combinations: Assets Acquired Consideration Paid Proved Unproved Net Working Capital Total Fair Value Cash Fair Value ofCommon UnitsIssued (in thousands) March$984 $21,452 $133 $22,569 $22,569 $—June883 13,688 8 14,579 14,579 —July4,349 7,944 215 12,508 3,764 8,744August5,000 34,673 74 39,747 26,461 13,286September1,176 — — 1,176 1,176 —November1,166 — — 1,166 1,166 —Total fairvalue$13,558 $77,757 $430 $91,745 $69,715 $22,030In addition, during 2018, the Partnership acquired mineral and royalty interests in unproved oil and natural gas properties from various sellers for anaggregate of $58.2 million. These acquisitions were considered asset acquisitions and were primarily located in East Texas and the Permian Basin. The cashportion of the consideration paid for these acquisitions of $57.6 million was funded with borrowings under the Partnership's Credit Facility and funds fromoperating activities, and $0.6 million wasF-15BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSfunded through the issuance of common units of the Partnership based on the fair values of the common units issued on the acquisition dates.During 2018, the Partnership acquired the remaining noncontrolling interest in certain subsidiaries for $1.7 million and merged the subsidiaries into itsexisting structure.Noble AcquisitionOn November 28, 2017 (the "Close Date"), Black Stone Minerals Company, L.P. ("BSMC"), a wholly owned subsidiary of BSM, closed on theacquisition of (i) certain mineral interests and other non-cost bearing royalty interests from Noble Energy Inc., Noble Energy Wyco, LLC, and RosettaResources Operating LP and (ii) one hundred percent (100%) of the issued and outstanding securities of Samedan Royalty, LLC ("Samedan") from NobleEnergy US Holdings, LLC, collectively, the "Noble Acquisition."The mineral interests and other non-cost bearing royalty interests acquired in the Noble Acquisition, including interests owned by Samedan (the "NobleAssets") include approximately 1.1 million gross (140,000 net) mineral acres, 380,000 gross acres of non-participating royalty interests, and 600,000 grossacres of overriding royalty interests collectively spread over 20 states with significant concentrations in Texas, Oklahoma, and North Dakota.The Partnership funded the $335 million purchase price (before customary post-closing adjustments) using (i) approximately $300 million in proceedsfrom its issuance of 14,711,219 Series B cumulative convertible preferred units to Mineral Royalties One, L.L.C., an affiliate of The Carlyle Group ("thePurchaser"), in a private placement which also closed on November 28, 2017, and (ii) approximately $35 million from borrowings under its Credit Facility.See additional discussion of the Series B cumulative convertible preferred units in Note 12 – Preferred Units.The transaction was accounted for as a business combination using the acquisition method of accounting which requires, among other things, that theassets acquired and liabilities assumed be recognized at their fair values as of the acquisition date. The final determination of fair value was completed in2018 after post-closing purchase price adjustments were finalized. Since December 31, 2017, the Partnership has recorded an adjustment to the purchase priceto reduce the amount allocated to unproved properties by $3.2 million, which reduces the Acquisitions of oil and natural gas properties line item of theconsolidated statement of cash flows for the year ended December 31, 2018.The following table summarizes the final allocation of the fair value of the assets acquired and the acquisition-related costs. Assets Acquired Cash ConsiderationPaid1 Acquisition-Related Costs2 Proved Unproved Net Working Capital Total Fair Value (in thousands)Noble Assets$68,877 $256,542 $5,917 $331,336 $331,336 $2471Represents cash consideration paid on the Close Date, as adjusted for the $3.2 million purchase price adjustment recorded during the year endedDecember 31, 2018.2 Acquisition-related costs were expensed and included in the general and administrative expense line item of the consolidated statement of operations forthe year ended December 31, 2017.The fair value of the Noble Assets was measured using valuation techniques that convert future cash flows to a single discounted amount. Significantinputs to the valuation of oil and natural gas properties include estimates of: (i) oil and natural gas reserves; (ii) future commodity prices; (iii) estimatedfuture cash flows; and (iv) market-based weighted average cost of capital. These inputs require significant judgments and estimates by the Partnership'smanagement at the time of the valuation and are the most sensitive and subject to change.Actual and Pro Forma Impact of Noble Acquisition (Unaudited)Revenue attributable to the Noble Acquisition included in the Partnership's consolidated statement of operations for the year ended December 31, 2017was $2.8 million. The following table presents unaudited pro forma information for the Partnership as if the Noble Acquisition occurred on January 1, 2016.F-16BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the Year Ended December 31, 2017 2016 (in thousands, except per unit amounts)Revenue and other income$468,103 $288,772Net income (loss)$178,970 $33,264Net income (loss) attributable to noncontrolling interests34 12Distributions on Series A redeemable preferred units(3,117) (5,763)Distributions on Series B cumulative convertible preferred units(21,000) (21,000)Net income (loss) attributable to the general partner and common and subordinated units$154,887 $6,513Allocation of net income (loss): General partner interest— —Common units99,776 20,696Subordinated units55,111 (14,183) $154,887 $6,513Net income (loss) attributable to limited partners per common and subordinated unit: Per common unit (basic)$1.02 $0.22Per subordinated unit (basic)$0.58 $(0.15)Per common unit (diluted)$1.02 $0.22Per subordinated unit (diluted)$0.58 $(0.15)The historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the Noble Acquisition and arefactually supportable. The unaudited pro forma consolidated results are not necessarily indicative of what the Partnership's consolidated results of operationswould have been had the acquisition been completed on January 1, 2016. In addition, the unaudited pro forma consolidated results do not purport to projectthe future results of operations for the combined company. The unaudited pro forma consolidated results reflect the following pro forma adjustments:•Adjustments to recognize incremental revenue, production costs and ad valorem taxes, and DD&A expense attributable to the Noble Assets.•Adjustment to recognize additional interest expense associated with the incremental borrowings under the Partnership's Credit Facility.•Adjustment to recognize the quarterly distribution associated with the issuance of 14,711,219 Series B cumulative convertible preferred units.•The Series B cumulative convertible preferred units were excluded from the calculation of pro forma diluted earnings per common unit for theperiods presented above due to their antidilutive effect under the if-converted method.•The Series B cumulative convertible preferred units do not have any impact to earnings per subordinated unit.F-17BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS2017 AcquisitionsIn addition to the Noble Acquisition, the Partnership closed on multiple acquisitions of mineral and royalty interests, which also included producingproperties, during the year ended December 31, 2017, as reflected in the table below. These acquisitions were primarily focused in the Delaware Basin andEast Texas. The cash portion of all acquisitions below was funded via borrowings under the Partnership's Credit Facility. Assets Acquired Consideration Paid Proved Unproved Net WorkingCapital Total FairValue Cash Fair Value ofCommon UnitsIssued Acquisition-Related Costs1 (in thousands)January$5,135 $34,008 $263 $39,406 $27,380 $12,026 $1,162June5,006 45,477 — 50,483 4,802 45,681 1,481August3,277 9,984 — 13,261 4,289 8,972 107September3,120 — — 3,120 3,120 — —Total fair value$16,538 $89,469 $263 $106,270 $39,591 $66,679 $2,7501Acquisition-related costs were expensed and included in the general and administrative expense line item of the 2017 consolidated statement ofoperations.In addition, the Partnership acquired mineral and royalty interests from various sellers in East Texas as reflected in the table below. The cash portion ofall acquisitions below was funded via borrowings under the Partnership's Credit Facility. Assets Acquired Consideration Paid Unproved Cash Fair Value ofCommon Units Issued (in thousands)Q1 2017$21,189 $21,017 $172Q2 201713,329 13,329 —Q3 201719,946 15,205 4,741Q4 20172,267 2,137 130Total acquired$56,731 $51,688 $5,043Farmout AgreementsOn February 21, 2017, the Partnership announced that it had entered into a farmout agreement with Canaan Resource Partners ("Canaan") which coverscertain Haynesville and Bossier shale acreage in San Augustine County, Texas operated by XTO Energy Inc., a subsidiary of Exxon Mobil Corporation. ThePartnership has an approximate 50% working interest in the acreage and is the largest mineral owner. 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 with each phase continuing for the lesser of 2 yearsor 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 firstthree phases of the agreement, Canaan commits on a phase-by-phase basis and funds 80% of the Partnership's drilling and completion costs and is assigned80% of the Partnership's working interests in such wells (40% working interest on an 8/8ths basis) as the wells are drilled. After the third phase, Canaan canearn 40% of the Partnership’s working interest (20% working interest on an 8/8ths basis) in additional wells drilled in the area by continuing to fund 40% ofthe Partnership's costs for those wells on a well-by-well basis. The Partnership will receive an overriding royalty interest (“ORRI”) before payout and anincreased ORRI after payout on all wells drilled under the agreement. From the inception of the agreement through December 31, 2018, the Partnership hasreceived $80.7 million from Canaan under the agreement. As of December 31, 2018, the Partnership had assigned to Canaan working interests in certain wellsdrilled and completed, and as such, only $11.6 million is included in the Other long-term liabilities line item of the consolidated balance sheet.On November 21, 2017, the Partnership entered into a farmout agreement with Pivotal Petroleum Partners (“Pivotal”), a portfolio company of TailwaterCapital, LLC. The farmout agreement covers substantially all of the Partnership's remaining working interests under active development in the ShelbyTrough area of East Texas targeting the Haynesville and Bossier shale acreage (after giving effect to the Canaan Farmout) until November 2025. In wellsoperated by XTO Energy Inc. in SanF-18BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSAugustine County, Texas, Pivotal will earn the Partnership's remaining working interest not covered by the Canaan Farmout (10% working interest on an8/8th basis), as well as 100% of the Partnership's working interests (ranging from approximately 12.5% to 25% on an 8/8ths basis) in wells operated by itsother major operator in San Augustine and Angelina counties, Texas. Initially, Pivotal is obligated to fund the development of up to 80 wells across severaldevelopment areas and then has options to continue funding the Partnership's 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, the Partnership will obtain a majority ofthe original working interest in such well group. From the inception of the agreement through December 31, 2018, the Partnership received $63.0 millionfrom Pivotal under the agreement. As of December 31, 2018, the Partnership had assigned to Pivotal working interests in certain wells drilled and completed,and as such, only $41.2 million is included in the Other long-term liabilities line item of the consolidated balance sheet.As of December 31, 2017, all amounts received from Canaan and Pivotal under the agreements were included in the Other long-term liabilities line itemof the consolidated balance sheet, as no working interest had been assigned to Canaan or Pivotal as of that date.NOTE 5 — COMMODITY DERIVATIVE FINANCIAL INSTRUMENTSThe Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To mitigate the inherent commodity price riskassociated with its operations, the Partnership uses oil and natural gas commodity derivative financial instruments. From time to time, such instruments mayinclude variable-to-fixed-price swaps, costless collars, fixed-price contracts, and other contractual arrangements. The Partnership enters into oil and naturalgas derivative contracts that contain netting arrangements with each counterparty. The Partnership does not enter into derivative instruments for speculativepurposes.As of December 31, 2018, the Partnership's open derivatives contracts consisted of fixed-price-swap contracts and costless collar contracts. A fixed-price-swap contract between the Partnership and the counterparty specifies a fixed commodity price and a future settlement date. A costless collar contract betweenthe Partnership and the counterparty specifies a floor and a ceiling commodity price and a future settlement date. The Partnership has not designated any ofits contracts as fair value or cash flow hedges. Accordingly, the changes in fair value of the contracts are included in the consolidated statement of operationsin the period of the change. All derivative gains and losses from the Partnership's derivative contracts have been recognized in revenue in the Partnership'saccompanying consolidated statements of operations. Derivative instruments that have not yet been settled in cash are reflected as either derivative assets orliabilities in the Partnership’s accompanying consolidated balance sheets as of December 31, 2018 and 2017. See Note 6 – Fair Value Measurements forfurther discussion.The Partnership's derivative contracts expose it to credit risk in the event of nonperformance by counterparties. While the Partnership does not require itsderivative contract counterparties to post collateral, the Partnership does evaluate the credit standing of such counterparties as deemed appropriate. Thisevaluation includes reviewing a counterparty’s credit rating and latest financial information. As of December 31, 2018, the Partnershiphad ten counterparties, all of which are rated Baa1 or better by Moody’s. Nine of the Partnership's counterparties are lenders under the Partnership's CreditFacility. The Partnership would have been at risk of losing a fair value amount of $50.3 million had the Partnership's counterparties as a group been unable tofulfill their obligations as of December 31, 2018. F-19BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSThe tables below summarize the fair value and classification of the Partnership’s derivative instruments, as well as the gross recognized derivative assets,liabilities, and amounts offset in the consolidated balance sheets at December 31, 2018 and 2017: As of December 31, 2018Classification Balance Sheet Location Gross FairValue Effect ofCounterparty Netting Net CarryingValue onBalance Sheet (in thousands)Assets: Current asset Commodity derivative assets $38,746 $(776) $37,970Long-term asset Deferred charges and other long-term assets 11,518 (1,450) 10,068Total assets $50,264 $(2,226) $48,038Liabilities: Current liability Commodity derivative liabilities $776 $(776) $—Long-term liability Commodity derivative liabilities 1,450 (1,450) —Total liabilities $2,226 $(2,226) $— As of December 31, 2017Classification Balance Sheet Location Gross FairValue Effect ofCounterparty Netting Net CarryingValue onBalance Sheet (in thousands)Assets: Current asset Commodity derivative assets $10,713 $(10,619) $94Long-term asset Deferred charges and other long-term assets 1,392 (1,029) 363Total assets $12,105 $(11,648) $457Liabilities: Current liability Commodity derivative liabilities $14,841 $(10,619) $4,222Long-term liability Commodity derivative liabilities 2,292 (1,029) 1,263Total liabilities $17,133 $(11,648) $5,485 Changes in the fair values of the Partnership’s derivative instruments (both assets and liabilities) are presented on a net basis in the accompanyingconsolidated statements of operations and consolidated statements of cash flows and consisted of the following for the periods presented: For the year ended December 31,Derivatives not designated as hedging instruments 2018 2017 2016 (in thousands)Beginning fair value of commodity derivative instruments $(5,028) $(16,719) $64,534Gain (loss) on oil derivative instruments 24,300 (5,091) (15,998)Gain (loss) on natural gas derivative instruments (9,469) 31,993 (20,466)Net cash paid (received) on settlements of oil derivative instruments 34,905 (10,901) (27,450)Net cash paid (received) on settlements of natural gas derivative instruments 3,330 (4,310) (17,339)Net change in fair value of commodity derivative instruments 53,066 11,691 (81,253)Ending fair value of commodity derivative instruments $48,038 $(5,028) $(16,719)F-20BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSThe Partnership had the following open derivative contracts for oil as of December 31, 2018: Volume (Bbl) Weighted Average Price(per Bbl) Range (per Bbl)Period and Type of Contract Low HighOil Swap Contracts: 2018 Fourth quarter 285,000 $55.18 $52.09 $61.882019 First quarter 645,000 $58.66 $52.82 $65.58Second quarter 645,000 58.66 52.82 65.58Third quarter 645,000 58.20 52.82 63.75Fourth quarter 645,000 58.20 52.82 63.75 Volume (Bbl) Weighted Average Floor Price (Per Bbl) Weighted Average Ceiling Price (Per Bbl)Period and Type of Contract Oil Collar Contracts: 2019 First quarter 60,000 $65.00 $74.00Second quarter 60,000 65.00 74.00Third quarter 60,000 65.00 74.00Fourth quarter 60,000 65.00 74.002020 First quarter 210,000 $56.43 $67.14Second quarter 210,000 56.43 67.14Third quarter 210,000 56.43 67.14Fourth quarter 210,000 56.43 67.14The Partnership had the following open derivative contracts for natural gas as of December 31, 2018: Volume (MMBtu) Weighted Average Price(per MMBtu) Range (per MMBtu)Period and Type of Contract Low HighNatural Gas Swap Contracts: 2019 First quarter 14,400,000 $2.96 $2.81 $3.20Second quarter 14,520,000 2.96 2.81 3.20Third quarter 14,640,000 2.96 2.81 3.20Fourth quarter 14,640,000 2.96 2.81 3.20 F-21BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSThe Partnership entered into the following derivative contracts for oil subsequent to December 31, 2018: Volume (Bbl) Weighted Average (PerBbl) Range (Per Bbl)Period and Type of Contract Low HighOil Swap Contracts: 2019 First quarter 40,000 $57.88 $57.88 $57.88Second quarter 120,000 57.88 57.88 57.88Third quarter 120,000 57.88 57.88 57.88Fourth quarter 120,000 57.88 57.88 57.882020 First quarter 180,000 $57.48 $57.46 $57.50Second quarter 180,000 57.48 57.46 57.50Third quarter 180,000 57.48 57.46 57.50Fourth quarter 180,000 57.48 57.46 57.50The Partnership entered into the following derivative contracts for natural gas subsequent to December 31, 2018: Volume (MMbtu) Weighted Average (PerMMBtu) Range (Per MMBtu)Period and Type of Contract Low HighNatural Gas Swap Contracts: 2020 First quarter 6,370,000 $2.72 $2.72 $2.73Second quarter 6,370,000 2.72 2.72 2.73Third quarter 6,440,000 2.72 2.72 2.73Fourth quarter 6,440,000 2.72 2.72 2.73NOTE 6 — FAIR VALUE MEASUREMENTSFair value is defined as the amount at which an asset (or liability) could be bought (or incurred) or sold (or settled) in an orderly transaction betweenmarket participants at the measurement date. Further, ASC 820, Fair Value Measurement, establishes a framework for measuring fair value, establishes a fairvalue hierarchy based on the quality of inputs used to measure fair value, and includes certain disclosure requirements. Fair value estimates are based oneither (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk.ASC 820 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilitiesmeasured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels aredefined as follows:Level 1 — Unadjusted quoted prices for identical assets or liabilities in active markets.Level 2 — Quoted prices for similar assets or liabilities in non-active markets, and inputs that are observable for the asset or liability, either directly orindirectly, for substantially the full term of the financial instrument.Level 3 — Inputs that are unobservable and significant to the fair value measurement (including the Partnership’s own assumptions in determining fairvalue).A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair valuemeasurement. The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment andconsiders factors specific to the asset or liability. There were no transfers into, or out of, the three levels of the fair value hierarchy for the years endedDecember 31, 2018 and 2017.The carrying value of our cash and cash equivalents, receivables and payables approximate fair value due to the short-term nature of the instruments. Theestimated carrying value of all debt as of December 31, 2018 and 2017 approximated the fairF-22BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSvalue due to variable market rates of interest. These debt fair values, which are Level 3 measurements, were estimated based on the Partnership’s incrementalborrowing rates for similar types of borrowing arrangements, when quoted market prices were not available. The estimated fair values of the Partnership’sfinancial instruments are not necessarily indicative of the amounts that would be realized in a current market exchange.Assets and Liabilities Measured at Fair Value on a Recurring BasisThe Partnership estimated the fair value of commodity derivative financial instruments using the market approach via a model that uses inputs that areobservable in the market or can be derived from, or corroborated by, observable data. See Note 5 – Commodity Derivative Financial Instruments for furtherdiscussion.The following table presents information about the Partnership’s assets and liabilities measured at fair value on a recurring basis: Fair Value Measurements Using Effect ofCounterparty Level 1 Level 2 Level 3 Netting Total (In thousands)As of December 31, 2018 Financial Assets Commodity derivative instruments $— $50,264 $— $(2,226) $48,038Financial Liabilities Commodity derivative instruments — 2,226 — (2,226) —As of December 31, 2017 Financial Assets Commodity derivative instruments $— $12,105 $— $(11,648) $457Financial Liabilities Commodity derivative instruments — 17,133 — (11,648) 5,485Assets and Liabilities Measured at Fair Value on a Non-Recurring BasisNonfinancial assets and liabilities measured at fair value on a non-recurring basis include certain nonfinancial assets and liabilities as may be acquired ina business combination and measurements of oil and natural gas property values for assessment of impairment.The determination of the fair values of proved and unproved properties acquired in business combinations are estimated bydiscounting projected future cash flows. The factors used to determine fair value include estimates of economic reserves, future operating and developmentcosts, future commodity prices, and a risk-adjusted discount rate. The Partnership has designated these measurements as Level 3. The Partnership's fair valueassessments for recent acquisitions are included in Note 4 — Oil and Natural Gas Properties Acquisitions.F-23BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSOil and natural gas properties are measured at fair value on a nonrecurring basis using the income approach when assessing for impairment. Proved andunproved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of thecarrying value of those properties. When assessing producing properties for impairment, the Partnership compares the expected undiscounted projected futurecash flows of the producing properties to the carrying amount of the producing properties to determine recoverability. When the carrying amount exceeds itsestimated undiscounted future cash flows, the carrying amount is written down to its fair value, which is measured as the present value of the projected futurecash flows of such properties. The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of futureproduction, future capital expenditures, and a risk-adjusted discount rate.The Partnership’s estimates of fair value have been determined at discrete points in time based on relevant market data. These estimates involveuncertainty and cannot be determined with precision. There were no significant changes in valuation techniques or related inputs for the years endedDecember 31, 2018 and 2017.The following table presents information about the Partnership’s assets measured at fair value on a non-recurring basis: Fair Value Measurements Using Net Book Level 1 Level 2 Level 31 Value1 Impairment (In thousands)Year Ended December 31, 2018 Impaired oil and natural gas properties $— $— $— $— $—Year Ended December 31, 2017 Impaired oil and natural gas properties $— $— $— $— $—Year Ended December 31, 2016 Impaired oil and natural gas properties $— $— $3,042 $9,817 $6,775 1 Amounts represent fair value and net book value at the date of assessment.NOTE 7 — SIGNIFICANT CUSTOMERSThe Partnership leases mineral interests to exploration and production companies and participates in non-operated working interests when economicconditions are favorable. XTO Energy Inc. represented approximately 15%, 21%, and 11% of total revenue for the years ended December 31, 2018, 2017, and2016.If the Partnership lost a significant customer, such loss could impact revenue derived from its mineral and royalty interests and working interests. Theloss of any single customer is mitigated by the Partnership’s diversified customer base. NOTE 8 — CREDIT FACILITYThe Partnership maintains a senior secured revolving credit agreement, as amended, (the “Credit Facility”). The Credit Facility has a maximum creditamount of $1.0 billion. The amount of the borrowing base is derived from the value of the Partnership’s oil and natural gas properties determined by thelender syndicate using pricing assumptions that often differ from the current market for future prices.Drawings on the Credit Facility are used for the acquisition of oil and natural gas properties and for other general business purposes. Effective October31, 2016 the borrowing base was $500.0 million and, effective April 25, 2017, the borrowing base redetermination resulted in an increase to $550.0 million.On November 1, 2017, the Partnership amended and restated the credit agreement to extend the maturity thereof for a term of five years, create a swinglinefacility that permits short-term borrowings on same-day notice, and make other changes to the hedging and restrictive covenants. There was no change to theborrowing base. The Credit Facility now terminates on November 1, 2022. Effective May 4, 2018, the borrowing base redetermination resulted in an increaseto $600.0 million and, effective October 31, 2018, the borrowing base was further increased to $675.0 million.Effective October 31, 2016, borrowings under the Credit Facility bore interest at LIBOR plus a margin between 2.00% and 3.00%, or the Prime Rate plusa margin between 1.00% and 2.00%, with the margin depending on the borrowing base utilization of the loan. Effective October 31, 2018, the LIBORmargin was reduced to between 1.75% and 2.75% and the Prime Rate margin was reduced to between 0.75% and 1.75%.F-24BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSThe weighted-average interest rate of the Credit Facility was 4.76% and 4.06% as of December 31, 2018 and 2017, respectively. Accrued interest ispayable at the end of each calendar quarter or at the end of each interest period, unless the interest period is longer than 90 days in which case interest ispayable at the end of every 90-day period. In addition, a commitment fee is payable at the end of each calendar quarter based on either a rate of 0.375% if theborrowing base utilization percentage is less than 50%, or 0.500% per annum if the borrowing base utilization percentage is equal to or greater than50%. The Credit Facility is secured by substantially all of the Partnership’s oil and natural gas production and assets.The Credit Facility contains various limitations on future borrowings, leases, hedging, and sales of assets. Additionally, the Credit Facility requires thePartnership to maintain a current ratio of not less than 1.0:1.0 and a ratio of total debt to EBITDAX (Earnings before Interest, Taxes, Depreciation,Amortization, and Exploration) of not more than 3.5:1.0. As of December 31, 2018, the Partnership was in compliance with all financial covenants in theCredit Facility.The aggregate principal balance outstanding was $410.0 million and $388.0 million at December 31, 2018 and 2017, respectively. The unused portionof the available borrowings under the Credit Facility were $265.0 million and $162.0 million at December 31, 2018 and 2017, respectively.NOTE 9 — INCENTIVE COMPENSATIONOverviewThe Board of the Partnership’s general partner established a long-term incentive plan (the “2015 LTIP”), pursuant to which non-employee directors ofthe Partnership’s general partner and certain employees and consultants of the Partnership and its affiliates are eligible to receive awards with respect to thePartnership’s common and subordinated units. The 2015 LTIP permits the grant of unit options, unit appreciation rights, restricted units, unit awards,phantom units, distribution equivalent rights either in tandem with an award or as a separate award, cash awards, and other unit-based awards. Any vestingterms associated with incentive awards are based on a predetermined schedule as approved by the Board or a committee thereof.Incentive compensation expense is included in general and administrative expense on the consolidated statements of operations. The total compensationexpense related to the common and subordinated unit grants is measured as the number of units granted that are expected to vest multiplied by the grant-datefair value per unit. Incentive compensation expense is recognized using straight-line or accelerated attribution depending on the specific terms of the awardagreements over the requisite service periods (generally equivalent to the vesting period).Cash AwardsThe Partnership may also provide from time to time short-term and long-term cash incentive and retention awards annually for its directors, executiveofficers, and certain other employees. Certain employees are entitled to receive cash bonuses based on service criteria over a four-year requisite service periodending in 2019. Payments are disbursed as vesting is attained on a graded annual basis. The last grant of such cash awards with graded vesting requirementswas made in 2016 and extends through December 31, 2019.Restricted Unit AwardsRestricted units awarded are subject to restrictions on transferability, customary forfeiture provisions, and time vesting provisions. Award recipients haveall the rights of a unitholder in the Partnership, including the right to receive distributions thereon, if and when made by the Partnership. In January of eachyear, non-employee directors of the Partnership’s general partner receive compensation under the 2015 LTIP in the form of fully vested common unitsgranted after each year of service.F-25BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSIn conjunction with the adoption of the 2015 LTIP, the Board approved a grant of awards to each of the executive officers of the Partnership's generalpartner, certain other employees, and each of the non-employee directors of the Partnership’s general partner. The grants included restricted common unitssubject to limitations on transferability, customary forfeiture provisions, and service based graded vesting requirements through March 15, 2019. The holdersof restricted common unit awards have all the rights of a common unitholder, including non-forfeitable distribution rights with respect to their restrictedcommon units. The grant-date fair value of these awards, net of estimated forfeitures, is recognized ratably using the straight-line attribution method.The Compensation Committee of the Board (the "Compensation Committee") annually approves a grant of awards to each of the executive officers of thePartnership's general partner and certain other employees. Consistent with previous awards the 2018 grant includes restricted common units subject tolimitations on transferability, customary forfeiture provisions, and service-based graded vesting requirements through January 7, 2021. Holders of restrictedcommon unit awards have all the rights of a common unitholder, including non-forfeitable distribution rights with respect to their restricted common units.The grant-date fair value of these awards, net of estimated forfeitures, is recognized ratably using the straight-line attribution method.The following table summarizes information about restricted units for the year ended December 31, 2018. Units Weighted-Average Grant-Date Fair Value per Unit Common Subordinated Common SubordinatedUnvested at December 31, 2017 1,542,058 59,129 $16.72 $18.30Granted 462,512 — 17.95 —Vested (669,728) (59,129) 16.43 18.30Converted — — — —Forfeited (826) — 17.87 —Unvested at December 31, 2018 1,334,016 — 17.29 —The weighted-average grant-date fair value per unit for unit-based awards was $17.95, $18.48, and $10.09 for the years ended December 31, 2018, 2017,and 2016, respectively. As of December 31, 2018, unrecognized compensation cost associated with restricted common unit awards was $11.0 million, whichthe Partnership expects to recognize over a weighted-average period of 1.47 years. As of December 31, 2018, there was no unrecognized compensation costassociated with restricted subordinated unit awards. The fair value of units vested for the years ended December 31, 2018, 2017, and 2016 was $12.9 million,$25.1 million, and $11.9 million, respectively. There were no cash payments made for vested units during the years ended December 31, 2018, 2017 and2016.Performance Unit AwardsThe Compensation Committee also approves grants of restricted performance units that are subject to both performance-based and service-based vestingprovisions. The number of common units issued to a recipient upon vesting of a restricted performance unit will be calculated based on performance againstcertain metrics that relate to the Partnership’s performance over each of the three calendar year performance periods commencing January 1 of the firstcalendar period. The target number of common units subject to each restricted performance unit is one; however, based on the achievement of performancecriteria, the number of common units that may be received in settlement of each restricted performance unit can range from zero to two times the targetnumber. The restricted performance units are eligible to become earned at the end of the required service period assuming the minimum performance metricsare achieved. Compensation expense related to the restricted performance unit awards is determined by multiplying the number of common units underlyingsuch awards that, based on the Partnership’s estimate, are probable to vest, by the measurement-date (i.e., the last day of each reporting period date) fair valueand recognized using the accelerated or straight-line attribution methods, depending on the terms of the award. Distribution equivalent rights for therestricted performance unit awards that are expected to vest are charged to partners’ capital.F-26BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSThe following table summarizes information about performance units for the year ended December 31, 2018. Performance units Number of Units Weighted-Average Grant-DateFair Value per UnitUnvested at December 31, 2017 1,457,356 $15.51Granted 463,251 17.94Vested (91,757) 18.78Forfeited (17,040) 18.94Unvested at December 31, 2018 1,811,810 15.94 The weighted-average grant-date fair value per unit for performance unit awards awards was $17.94, $17.99, and $11.36 for the years endedDecember 31, 2018, 2017, and 2016, respectively. Unrecognized compensation cost associated with performance unit awards was $8.4 million as ofDecember 31, 2018, which the Partnership expects to recognize over a weighted-average period of 1.55 years. The fair value of performance units vested forthe years ended December 31, 2018, and 2016 was $1.5 million, and $3.2 million, respectively. No performance units vested for the year ended December 31,2017.Incentive CompensationThe table below summarizes incentive compensation expense recorded in general and administrative expenses in the consolidated statements ofoperations for the years ended December 31, 2018, 2017, and 2016. Year Ended December 31,Incentive compensation expense 2018 2017 2016 (In thousands)Cash — short and long-term incentive plan $9,301 $4,373 $7,414Equity-based compensation — restricted common and subordinated units 13,624 13,476 13,408Equity-based compensation — restricted performance units 14,188 17,367 18,518Board of Directors incentive plan 2,322 2,202 2,012Total incentive compensation expense $39,435 $37,418 $41,352NOTE 10 — EMPLOYEE BENEFIT PLANSBlack Stone Natural Resources Management Company, a subsidiary of the Partnership, sponsors a defined contribution 401(k) Profit Sharing Plan (the“401(k) Plan”) for the benefit of substantially all employees of the Partnership. The 401(k) Plan became effective on January 1, 2001 and allows eligibleemployees to make tax-deferred contributions up to 90% of their annual compensation, not to exceed annual limits established by the Internal RevenueService. The Partnership makes matching contributions of 100% of employee contributions, up to 5% of compensation. These matching contributions aresubject to a graded vesting schedule, with 33% vested after one year, 66% vested after two years and 100% vested after three years of service with thePartnership. Following three years of service, future Partnership matching contributions vest immediately. The Partnership’s contributions were $0.7 million,$0.6 million, and $0.5 million for the years ended December 31, 2018, 2017, and 2016, respectively.NOTE 11 — COMMITMENTS AND CONTINGENCIESLeasesThe Partnership leases certain office space and equipment under cancelable and non-cancelable operating leases that end at various dates through 2023.The Partnership recognizes rent expense on a straight-line basis over the lease term. Rent expense under such arrangements was $2.2 million, $2.5 million,and $1.9 million for the years ended December 31, 2018, 2017, and 2016, respectively. Such amounts are included in general and administrative expense onthe consolidated statements of operations.F-27BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSFuture minimum lease commitments under non-cancelable leases are as follows as of December 31, 2018:Year Ending December 31,(in thousands)2019$1,38620201,37120211,38520221,41120231,439Total$6,992Environmental MattersThe Partnership’s business includes activities that are subject to U.S. federal, state, and local environmental regulations with regard to air, land, and waterquality and other environmental matters.The Partnership does not consider the potential remediation costs that could result from issues identified in any environmental site assessments to besignificant to the consolidated financial statements and no provision for potential remediation costs has been recorded.Put Option Related to Noble AcquisitionBy acquiring 100% of the issued and outstanding securities of Samedan, now NAMP Holdings, LLC, on November 28,2017 as part of the Noble Acquisition, the Partnership acquired a 100% interest in Comin-Termin, LLC, now NAMP GP, LLC ("Holdings"), Comin 1989Partnership LLLP, now NAMP 1, LP ("Comin"), and Temin 1987 Partnership LLLP, now NAMP 2, LP ("Temin"). Pursuant to certain co-ownershipagreements, various co-owners hold undivided beneficial ownership interests in 54.67% and 57.37% of the mineral interests held of record by Holdings andTemin, respectively. Based on the terms of the co-ownership agreements, the co-owners each have an unconditional option to require Comin or Temin, asapplicable, to purchase their beneficial ownership interest in the mineral interests held of record by Holdings or Temin, as applicable, at any time within 30days of receiving such repurchase notice. The purchase price of the beneficial ownership interest shall be based on an evaluation performed by Comin orTemin, as applicable, in good faith. As of December 31, 2018, the Partnership had not received notice from any co-owner to exercise their repurchase option,and as such, no liability was recorded.Pipeline Extension AgreementOn May 30, 2018, the Partnership and a development partner entered into an agreement authorizing the Partnership's pipeline transportation serviceprovider, in the development area, to construct an extension to its existing gathering system ("Pipeline Extension") for an estimated cost of $8.7 million. ThePartnership and its development partner will each have 50% of the firm capacity to flow natural gas through the Pipeline Extension. Once the facilities areready for service, the cost of the project will be recovered through an incremental gathering fee that will be charged on a per Mcf basis of natural gas thatflows through the Pipeline Extension. When the service provider has been fully reimbursed for the project, the incremental gathering fees will no longer becharged. If the cost of the Pipeline Extension is not recovered through these fees within four years of the initial flow, the Partnership will be required to payits share (50%) of the costs that were not recovered. As of December 31, 2018, the Partnership expects the cost of the Pipeline Extension to be recoveredthrough incremental gathering fees, and as such, no liability was recorded.LitigationFrom time to time, the Partnership is involved in legal actions and claims arising in the ordinary course of business. The Partnership believes existingclaims as of December 31, 2018 will be resolved without material adverse effect on the Partnership’s financial condition or results of operations. F-28BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSNOTE 12 — PREFERRED UNITSSeries A Redeemable Preferred UnitsAs of December 31, 2018, there were no Series A redeemable preferred units outstanding, while as of December 31, 2017 there were 26,363 Series Aredeemable preferred units outstanding with a carrying value of $27.0 million. The carrying value included accrued distributions of $0.7 million. The SeriesA redeemable preferred units are classified as mezzanine equity on the consolidated balance sheets since redemption was outside the control of thePartnership. The Series A redeemable preferred units were entitled to an annual distribution of 10%, payable on a quarterly basis in arrears.Prior to liquidation of the Partnership, and while any of the Series A redeemable preferred units remained outstanding, cash or other property of thePartnership were distributed 100% to the Series A redeemable preferred unitholders until the aggregate Unpaid Preferred Yield (as defined below) of eachSeries A redeemable preferred unit accrued through the last day of the immediately preceding calendar quarter had been reduced to zero. Distributions inexcess of the aggregate Unpaid Preferred Yield were distributed 100% to common and subordinated unitholders, until there had been distributed anaggregate amount in respect of such calendar year equal to 10% of the aggregate Interest Fair Market Value of the outstanding common and subordinatedunits as of the first day of such calendar year. Any additional distributions were distributed to the common and subordinated unitholders, on the one hand,and the Series A redeemable preferred unitholders, on the other hand, pro rata on an as-is-converted basis.The terms “Interest Fair Market Value,” “Preferred Yield,” and “Unpaid Preferred Yield” have the following meanings:“Interest Fair Market Value” means, as of any date, the amount which would be received by the holder of a common unit or subordinated unit, asapplicable, if (a) all of the Series A redeemable preferred units were converted into or exchanged or exercised for common units and, during the subordinationperiod, subordinated units, (b) the fair market value of the assets of the Partnership in excess of its liabilities as of the date of determination of Interest FairMarket Value equaled the Value (as defined in the partnership agreement) as of such date, adjusted to reflect any increases in equity value resulting from thedeemed conversion, exchange or exercise of convertible securities, and (c) an amount equal to such Value (as defined in the partnership agreement), as soadjusted, were distributed to the unitholders in accordance with the liquidation distribution provisions of the partnership agreement.“Preferred Yield” means a yield on the outstanding Series A redeemable preferred units equivalent to a 10% per annum interest rate (subject toadjustment following certain events of default by the Partnership) on an initial investment of $1,000, calculated based on a 365-day year and compoundedquarterly.“Unpaid Preferred Yield” means, with respect to each Series A redeemable preferred unit and as of any date of determination, an amount equal to theexcess, if any, of (a) the cumulative Preferred Yield from the closing of the IPO through the date established, over (b) the cumulative amount of distributionsmade as of the date established in respect of the Series A redeemable preferred unit.The Series A redeemable preferred units were convertible into common and subordinated units at the option of the Series A redeemable preferredunitholders. The Series A redeemable preferred units had an adjusted conversion price of $14.2683 and an adjusted conversion rate of 30.3431 common unitsand 39.7427 subordinated units per redeemable preferred unit.The Partnership had the right, at its sole option, to redeem an amount of Series A redeemable preferred units equal to the units being redeemed by anowner of Series A redeemable preferred units on each December 31. Any amount of a given year’s Series A redeemable preferred units eligible for redemptionnot redeemed on December 31 were automatically converted to common and subordinated units on January 1 in the following year. All Series A redeemablepreferred units not redeemed by March 31, 2018 automatically converted to common and subordinated units effective as of January 1, 2018 or as soon aspracticable thereafter.For the year ended December 31, 2018, 2,115 Series A redeemable preferred units were redeemed for $2.1 million, including accrued unpaid yield. Forthe year ended December 31, 2018, 24,248 Series A redeemable preferred units totaling $24.2 million were converted into 735,758 common units and963,681 subordinated units as a result of the mandatory conversion subsequent to December 31, 2017.For the year ended December 31, 2017, 19,704 Series A redeemable preferred units were redeemed for $20.2 million, including accrued unpaid yield.For the year ended December 31, 2017, 6,624 Series A redeemable preferred units totaling $6.6F-29BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSmillion were converted into 200,996 common units and 263,247 subordinated units as a result of the mandatory conversion subsequent to December 31,2016.For the year ended December 31, 2016, 18,461 Series A redeemable preferred units were redeemed for $19.0 million, including accrued unpaid yield.For the year ended December 31, 2016, 6,064 Series A redeemable preferred units totaling $6.1 million were converted into the equivalent of 184,006common units and 240,986 subordinated units on an adjusted basis as a result of the mandatory conversion subsequent to December 31, 2015.Series B Cumulative Convertible Preferred UnitsOn November 28, 2017, the Partnership issued and sold in a private placement 14,711,219 Series B cumulative convertible preferred units representinglimited partner interests in the Partnership to the "Purchaser" for a cash purchase price of $20.3926 per Series B cumulative convertible preferred unit,resulting in total proceeds of approximately $300 million.The Series B cumulative convertible preferred units are entitled to an annual distribution of 7%, payable on a quarterly basis in arrears. For the eightquarters consisting of the quarter in respect of which the initial distribution is paid and the seven full quarters thereafter, the quarterly distribution may bepaid, at the sole option of the Partnership, (i) in-kind in the form of additional Series B cumulative convertible preferred units (the "Series B PIK Units"), (ii)in cash, or (iii) in a combination of Series B PIK Units and cash. Beginning with the ninth quarter, all Series B cumulative convertible preferred unitdistributions shall be paid in cash. The number of Series B PIK Units to be issued, if any, shall equal the quotient of the Series B cumulative convertiblepreferred unit distribution amount (or portion thereof) divided by the Series B cumulative convertible preferred unit purchase price of $20.3926.The Series B cumulative convertible preferred units are convertible into common units of the Partnership on November 29, 2019 and once per quarterthereafter. At such time, the Series B cumulative convertible preferred units may be converted by each holder at its option, in whole or in part, into commonunits on a one-for-one basis at the purchase price of $20.3926, adjusted to give effect to any accrued but unpaid accumulated distributions on the applicableSeries B cumulative convertible preferred units through the most recent declaration date. However, the Partnership shall not be obligated to honor anyrequest for such conversion if such request does not involve an underlying value of common units of at least $10 million based on the closing trading priceof common units on the trading day immediately preceding the conversion notice date, or such lesser amount to the extent such exercise covers all of aholder's Series B cumulative convertible preferred units.The Series B cumulative convertible preferred units had a carrying value of $298.4 million and $295.4 million, including accrued distributions of $5.3million and $1.9 million, as of December 31, 2018 and 2017. The Series B cumulative convertible preferred units are classified as mezzanine equity on theconsolidated balance sheet since certain redemption provisions are outside the control of the Partnership.NOTE 13 — EARNINGS PER UNITThe Partnership applies the two-class method for purposes of calculating earnings per unit (“EPU”). The holders of the Partnership’s restricted commonand subordinated units have all the rights of a unitholder, including non-forfeitable distribution rights. As participating securities, the restricted common andsubordinated units are included in the calculation of basic earnings per unit. For the periods presented, the amount of earnings allocated to theseparticipating units was not material.Net income (loss) attributable to the Partnership is allocated to our general partner and the common and subordinated unitholders in proportion to theirpro rata ownership after giving effect to distributions, if any, declared during the period.For the purpose of calculating diluted EPU, the Series A redeemable preferred units could be converted into 0.2 million weighted average common unitsand 0.2 million weighted average subordinated units for the year ended December 31, 2018, 0.8 million weighted average common units and 1.1 millionweighted average subordinated units for the year ended December 31, 2017, and 1.6 million weighted average common units and 2.1 million weightedaverage subordinated units for the year ended December 31, 2016. For the year ended December 31, 2018, if the outstanding Series A redeemable preferredunits were converted to common and subordinated units as of the beginning of the period, the effect would be anti-dilutive to common unitholders.Therefore, the Series A redeemable preferred units are not included in the diluted EPU calculations for common units for the year ended December 31, 2018.For the years December 31, 2017 and 2016, if the outstanding Series A redeemable preferred units were converted to common and subordinated units as of thebeginning of each period, the effect would be anti-dilutive. Therefore, the Series A redeemable preferred units are not included in the diluted EPUcalculations for the years ended December 31, 2017 and 2016.F-30BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSFor the purpose of calculating diluted EPU, the Series B cumulative convertible preferred units could be converted into 15.0 million and 1.6 millionweighted average common units for the years ended December 31, 2018 and 2017, respectively. For the year ended December 31, 2017, if the outstandingSeries B cumulative convertible preferred units were converted to common units as of the beginning of the period, the effect would be anti-dilutive.Therefore, the Series B cumulative convertible preferred units are not included in the diluted EPU calculations for the year ended December 31, 2017.The Partnership’s restricted performance unit awards are contingently issuable units that are considered in the calculation of diluted EPU. ThePartnership assesses the number of units that would be issuable, if any, under the terms of the arrangement if the end of the reporting period were the end ofthe contingency period. For the year ended December 31, 2018, there were an additional 0.2 million weighted average common units related to thePartnership’s restricted performance unit awards included in the calculation of diluted EPU.The following table sets forth the computation of basic and diluted earnings per unit: For the Year Ended December 31, 2018 2017 2016 (in thousands, except per unit amounts)NET INCOME (LOSS) $295,560 $157,153 $20,188Net (income) loss attributable to noncontrolling interests (24) 34 12Distributions on Series A redeemable preferred units (25) (3,117) (5,763)Distributions on Series B cumulative convertible preferred units (21,000) (1,925) —NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON ANDSUBORDINATED UNITS $274,511 $152,145 $14,437ALLOCATION OF NET INCOME (LOSS): General partner interest $— $— $—Common units 154,662 98,389 24,669Subordinated units 119,849 53,756 (10,232) $274,511 $152,145 $14,437NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON ANDSUBORDINATED UNIT: Per common unit (basic) $1.46 $1.01 $0.26Weighted average common units outstanding (basic) 106,064 97,400 96,073Per subordinated unit (basic) $1.25 $0.56 $(0.11)Weighted average subordinated units outstanding (basic) 96,099 95,149 95,138Per common unit (diluted)1 $1.45 $1.01 $0.26Weighted average common units outstanding (diluted) 121,264 97,400 96,243Per subordinated unit (diluted)2 $1.25 $0.56 $(0.11)Weighted average subordinated units outstanding (diluted) 96,346 95,149 95,1381 For the year ended December 31, 2018, diluted net income (loss) attributable to common units includes distributions on Series B cumulative convertiblepreferred units of $21 million.2 For the year ended December 31, 2018, diluted net income (loss) attributable to subordinated units includes distributions on Series A redeemable preferredunits of $0.3 million.NOTE 14 — COMMON AND SUBORDINATED UNITSCommon and Subordinated UnitsThe common units and subordinated units represent limited partner interests in the Partnership. The partnership agreement restricts unitholders’ votingrights 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 inBSMC prior to the IPO, their transferees, persons who acquired such units with the prior approval of the board of directors of the Partnership's general partner,holders of Series B cumulative convertible preferred units in connection with any vote, consent or approval of the Series B cumulative convertible preferredunits as a separate class, and persons who own 15% or more of any class as a result of any redemption or purchase of any otherF-31BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSperson's units or similar action by the Partnership or any conversion of the Series B cumulative convertible preferred units at the Partnership's option or inconnection with a change of control may not vote on any matter.The holders of common units and subordinated units are entitled to participate in distributions and exercise the rights and privileges provided to limitedpartners holding common units and subordinated units under the partnership agreement. The partnership agreement generally provides that any distributions will be paid each quarter during the subordination period (as defined in ourpartnership agreement) 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 plus any arrearages fromprior quarters; and•third, to the holders of subordinated units, until each subordinated unit has received the applicable minimum quarterly distribution.The priority right of the common unit holders will cease to exist upon full conversion of the subordinated units to common units, which may occur asearly as May of 2019. If the distributions to common and subordinated unitholders exceed the applicable minimum quarterly distribution per unit, then suchexcess amounts will be distributed pro rata on the common and subordinated units as if they were a single class.The following table provides information about our per share distributions to common and subordinated unitholders: Year Ended December 31, 2018 2017 2016DISTRIBUTIONS DECLARED AND PAID: Per common unit$1.33 $1.20 $1.10Per subordinated unit$1.13 $0.79 $0.74Common Unit Repurchase ProgramOn November 5, 2018, the Board of the Partnership's general partner authorized the repurchase of up to $75.0 million in common units. The repurchaseprogram authorizes the Partnership to make repurchases on a discretionary basis as determined by management, subject to market conditions, applicable legalrequirements, available liquidity, and other appropriate factors. In 2018, the Partnership repurchased a total of 128,627 common units for an aggregate cost of$2.0 million. The repurchase program is funded from the Partnership's cash on hand or availability on the Credit Facility. Any repurchased units are canceled.On March 4, 2016, the Board of the Partnership's general partner authorized the repurchase of up to $50.0 million in common units through a programthat terminated on September 15, 2016. The repurchase program authorized the Partnership to make repurchases on a discretionary basis as determined bymanagement, subject to market conditions, applicable legal requirements, available liquidity, and other appropriate factors. In 2016, the Partnershiprepurchased a total of 1,315,574 common units for an aggregate cost of $20.2 million. The repurchase program was funded from the Partnership's cash onhand or availability on the Credit Facility.NOTE 15 — AT-THE-MARKET OFFERING PROGRAMOn May 26, 2017, the Partnership commenced an at-the-market offering program (the “ATM Program”) and in connection therewith entered into anEquity Distribution Agreement with Wells Fargo Securities, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, and UBS Securities LLC, as SalesAgents (each a “Sales Agent” and collectively the “Sales Agents”). Pursuant to the terms of the ATM Program, the Partnership may sell, from time to timethrough the Sales Agents, the Partnership’s common units representing limited partner interests having an aggregate offering amount of up to $100,000,000.Sales of common units, if any, may be made in negotiated transactions or transactions that are deemed to be “at the market” offerings as defined in Rule 415under the Securities Act of 1933, as amended (the “Securities Act”), including sales made directly on the New York Stock Exchange or sales made to orthrough a market maker other than on an exchange.F-32BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSUnder the terms of the ATM Program, the Partnership may also sell common units to one or more of the Sales Agents as principal for its own account at aprice to be agreed upon at the time of sale. Any sale of common units to a Sales Agent as principal would be pursuant to the terms of a separate agreementbetween the Partnership and such Sales Agent.The Partnership intends to use the net proceeds from any sales pursuant to the ATM Program, after deducting the Sales Agents’ commissions and thePartnership’s offering expenses, for general partnership purposes, which may include, among other things, repayment of indebtedness outstanding under thePartnership’s Credit Facility.Common units to be sold pursuant to the Equity Distribution Agreement will be offered and sold pursuant to the Partnership’s existing effective shelf-registration statement on Form S-3 (File No. 333-215857), which was declared effective by the Securities and Exchange Commission on February 8, 2017.The Equity Distribution Agreement contains customary representations, warranties and agreements, indemnification obligations, including for liabilitiesunder the Securities Act, other obligations of the parties and termination provisions.For the year ended December 31, 2018, the Partnership sold 2,243,775 common units under the ATM Program for net proceeds of $40.5 million. For theyear ended December 31, 2017, the Partnership sold 2,001,823 common units under the ATM Program for net proceeds of $32.5 million.NOTE 16 — SUBSEQUENT EVENTSOn February 7, 2019, the Board approved a distribution for the period from October 1, 2018 to December 31, 2018 of $0.37 per common unit and $0.37per subordinated unit. Distributions were paid on February 26, 2019 to unitholders of record at the close of business on February 19, 2019.F-33BLACK STONE MINERALS, L.P. AND SUBSIDIARIESSUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES—UNAUDITEDGeographic Area of Operation All the Partnership’s proved reserves are located within the continental U.S., with the majority concentrated in Texas, Louisiana, and North Dakota.However, the Partnership also owns mineral and royalty interests and non-operated working interests in various producing and non-producing oil and naturalgas properties in several other areas throughout the U.S. Therefore, the following disclosures about the Partnership’s costs incurred and proved reserves arepresented on a consolidated basis.Costs Incurred in Oil and Natural Gas Property Acquisitions, Exploration, and Development ActivitiesCosts incurred in oil and natural gas property acquisition, exploration and development, whether capitalized or expensed, are presented below: Year Ended December 31, 2018 2017 2016 (in thousands)Acquisition Costs of Properties:1 Proved $13,438 $96,596 $40,242Unproved 136,079 383,535 100,888Exploration Costs 13,544 618 645Development Costs1 165,198 81,056 73,316Total $328,259 $561,805 $215,091 1 See Note 4 – Oil and Natural Gas Properties Acquisitions for further discussion. Unproved properties include purchases of leasehold prospects.Development costs include costs incurred on farmout wells subject to reimbursement under our farmout agreements.Property acquisition costs include costs incurred to purchase, lease, or otherwise acquire a property. Development costs include costs incurred to gainaccess to and prepare development well locations for drilling, to drill and equip development wells, and to provide facilities to extract, treat, and gathernatural gas. Refer below for total capitalized costs and associated accumulated DD&A and impairment.Oil and Natural Gas Capitalized CostsAggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, and amortization,including impairments, are presented below: As of December 31, 2018 2017 (in thousands)Proved properties1 $2,377,305 $2,258,893Unproved properties 1,063,883 988,720Total 3,441,188 3,247,613Accumulated depreciation, depletion, amortization, and impairment (1,865,692) (1,766,842)Oil and natural gas properties, net $1,575,496 $1,480,7711 Proved properties include capitalized costs related to farmout wells not yet assigned.F-34Oil and Natural Gas Reserve InformationThe following table sets forth estimated net quantities of the Partnership’s proved, proved developed, and proved undeveloped oil and natural gasreserves. These reserve estimates exclude insignificant natural gas liquid quantities owned by the Partnership. Estimated reserves for the periods presented arebased on the unweighted average of first-day-of-the-month commodity prices over the period January through December for the year in accordance withdefinitions and guidelines set forth by the SEC and the FASB. Crude Oil (MBbl) Natural Gas (MMcf) Total (MBoe)Net proved reserves at December 31, 2015 15,842 203,675 49,788Revisions of previous estimates1, 9 2,097 23,106 5,948Purchases of minerals in place2, 9 1,520 6,717 2,639Extensions, discoveries and other additions3, 9 2,589 84,339 16,646Production (3,680) (47,498) (11,596)Net proved reserves at December 31, 2016 18,368 270,339 63,425Revisions of previous estimates 1, 9 (2,298) 14,505 120Purchases of minerals in place 4,9 2,335 31,323 7,555Extensions, discoveries and other additions5, 9 3,046 43,886 10,360Production (3,552) (59,779) (13,515)Net proved reserves at December 31, 2017 17,899 300,274 67,945Revisions of previous estimates1 (35) (11,027) (1,873)Purchases of minerals in place6 227 419 297Extensions, discoveries and other additions5 4,438 95,976 20,434Production (4,962) (71,622) (16,899)Net proved reserves at December 31, 2018 17,567 314,020 69,904Net Proved Developed Reserves7 December 31, 2016 18,150 223,057 55,327December 31, 2017 17,891 233,017 56,727December 31, 2018 17,567 278,233 63,939Net Proved Undeveloped Reserves8 December 31, 2016 218 47,282 8,098December 31, 2017 8 67,257 11,218December 31, 2018 — 35,787 5,9651 Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors.The most notable technical revisions are related to well performance in certain Haynesville/ Bossier wells.2Includes the acquisition of mineral and royalty reserves primarily in the Marcellus and Wolfcamp plays.3 Includes discoveries and additions primarily related to active drilling in the Haynesville/Bossier, Bakken/Three Forks, Wilcox, Eagle Ford, andFayetteville plays.4 Includes the acquisition of mineral and royalty reserves primarily in East Texas and the Permian and Williston basins.5 Includes extensions and additions related to drilling activities within multiple basins.6 Includes the acquisition of mineral and royalty reserves primarily in the Wolfcamp play and East Texas.7 As of December 31, 2018, no proved developed reserves were attributable to noncontrolling interests in the Partnership's consolidated subsidiaries. Proveddeveloped reserves of 61 MBoe and 74 MBoe as of December 31, 2017 and 2016, respectively, were attributable to noncontrolling interests.8 As of December 31, 2018, 2017, and 2016, no proved undeveloped reserves were attributable to noncontrolling interests.9 Due to the Noble Acquisition in November 2017 and increased drilling activity on our mineral acreage in 2018, we modified our methodology forcomputing the sources of changes in proved reserves. The change in methodology is to classify currentF-35period production from new wells as extensions, discoveries and other additions and to classify current period production from new acquisitions aspurchases of minerals in place. These items were previously classified as revisions of previous estimates. We changed the presentation of 2017 and 2016 tobe consistent with our 2018 presentation. We believe the change in methodology is a more accurate reflection of the changes in our reserves although theimpact to the previous years presentation was not material.Standardized Measure of Discounted Future Net Cash FlowsFuture cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the 12-month unweighted averageof first-day-of-the-month commodity prices for the periods presented. All prices are adjusted by field for quality, transportation fees, energy content andregional price differentials. Future cash inflows are computed by applying applicable prices relating to the Partnership’s proved reserves to the year-endquantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assumingcontinuation of existing economic conditions. There are no future income tax expenses deducted from future production revenues in the calculation of thestandardized measure because the Partnership is not subject to federal income taxes. The Partnership is subject to certain state based taxes; however, theseamounts are not material. See Note 2 – Summary of Significant Accounting Policies for further discussion. Year Ended December 31, 2018 2017 2016 (in thousands)Future cash inflows $2,038,508 $1,643,582 $1,267,179Future production costs (222,342) (211,064) (193,749)Future development costs (58,403) (70,111) (36,509)Future income tax expense (6,333) (2,655) (3,516)Future net cash flows (undiscounted) 1,751,430 1,359,752 1,033,405Annual discount 10% for estimated timing (663,814) (497,103) (430,390)Total1 $1,087,616 $862,649 $603,015 1 Includes standardized measure of discounted future net cash flows of approximately $0.5 million and $0.6 million for December 31, 2017 and 2016attributable to noncontrolling interests in the Partnership’s consolidated subsidiaries.The following summarizes the principal sources of change in the standardized measure of discounted future net cash flows: Year Ended December 31, 2018 2017 2016 (in thousands)Standardized measure, beginning of year $862,649 $603,015 $554,972Sales, net of production costs (475,742) (295,941) (210,354)Net changes in prices and production costs related to future production1 275,091 161,221 (80,721)Extensions, discoveries and improved recovery, net of future production anddevelopment costs1 370,695 166,616 139,407Previously estimated development costs incurred during the period 14,509 11,118 28,909Revisions of estimated future development costs1 (558) 2,653 (2,380)Revisions of previous quantity estimates, net of related costs1 (5,401) 60,476 57,577Accretion of discount 86,441 60,512 55,662Purchases of reserves in place, less related costs1 8,975 113,342 42,940Changes in timing and other1 (49,043) (20,363) 17,003Net increase (decrease) in standardized measures 224,967 259,634 48,043Standardized measure, end of year $1,087,616 $862,649 $603,0151 Due to the Noble Acquisition in November 2017 and increased drilling activity on our mineral acreage in 2018, we modified our methodology forcomputing the principal sources of changes in the standardized measure. The change in methodology isF-36to classify current period production from new wells as extensions, discoveries and improved recovery and to classify current period production from newacquisitions as purchases of reserves in place. These items were previously classified as revisions of previous quantity estimates. We changed thepresentation of 2017 and 2016 to be consistent with our 2018 presentation. We believe the change in methodology is a more accurate reflection of theprincipal sources of changes in the standardized measure although the impact to the previous years presentation was not material. The data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since thecomputations are based on a significant amount of estimates and assumptions. The required projection of production and related expenditures over timerequires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to besubstantially different from historical prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amountsshould give specific recognition to the computational methods utilized and the limitations inherent therein.F-37Selected Quarterly Financial Information—UnauditedQuarterly financial data was as follows for the periods indicated. FirstQuarter Second Quarter Third Quarter Fourth Quarter (In thousands, except for per unit data)2018 Total revenue $114,494 $109,309 $139,718 $246,047Income (loss) from operations 47,960 33,524 66,180 170,717Net income (loss) 41,957 28,690 60,775 164,138Net income (loss) attributable to the general partner and common andsubordinated units 36,655 23,488 55,503 158,865Net income (loss) attributable to common and subordinated units per unit (basic)1 Per common unit (basic) 0.23 0.17 0.27 0.78Per subordinated unit (basic) 0.13 0.06 0.27 0.78Net income (loss) attributable to common and subordinated units per unit(diluted)1 Per common unit (diluted) 0.23 0.17 0.27 0.72Per subordinated unit (diluted) 0.13 0.06 0.27 0.78Cash distributions declared and paid per limited partner unit Per common unit $0.3125 $0.3125 $0.3375 $0.3700Per subordinated unit $0.2088 $0.2087 $0.3375 $0.3700Total assets $1,635,978 $1,669,464 $1,754,259 $1,750,124Long-term debt 436,000 421,000 402,000 410,000Total mezzanine equity 300,644 298,361 298,361 298,3612017 Total revenue $124,582 $120,524 $89,111 $95,442Income (loss) from operations 65,015 57,840 26,216 23,013Net income (loss) 61,583 54,174 22,034 19,362Net income (loss) attributable to the general partner and common andsubordinated units 60,460 53,518 21,388 16,779Net income (loss) attributable to common and subordinated units per unit (basic)1 Per common unit (basic) 0.37 0.33 0.16 0.15Per subordinated unit (basic) 0.26 0.22 0.05 0.03Net income (loss) attributable to common and subordinated units per unit(diluted)1 Per common unit (diluted) 0.37 0.33 0.16 0.15Per subordinated unit (diluted) 0.26 0.22 0.05 0.03Cash distributions declared and paid per limited partner unit Per common unit $0.2875 $0.2875 $0.3125 $0.3125Per subordinated unit $0.1838 $0.1838 $0.2088 $0.2088Total assets $1,199,722 $1,250,086 $1,246,070 $1,576,451Long-term debt 388,000 393,000 362,000 388,000Total mezzanine equity 34,145 27,085 27,092 322,422 1 See Note 13 – Earnings Per Unit in the consolidated financial statements. F-38Exhibit 21.1SUBSIDIARIES OF BLACK STONE MINERALS, L.P. Entity Jurisdiction of OrganizationBlack Stone Energy Company, L.L.C. TexasBlack Stone Minerals Company, L.P. DelawareBlack Stone Minerals GP, L.L.C. DelawareBlack Stone Natural Resources, L.L.C. DelawareBlack Stone Natural Resources Management Company TexasBSMC GP, L.L.C. DelawareTLW Investments, L.L.C. OklahomaNAMP Holdings, L.L.C. DelawareNAMP GP, L.L.C. OklahomaNAMP 1, L.P. OklahomaNAMP 2, L.P. OklahomaExhibit 23.1CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM We consent to the incorporation by reference in the following Registration Statements: (1) Registration Statement (Form S-8 No. 333-203909) pertaining to the Long-Term Incentive Plan of Black StoneMinerals, L.P., (2)Registration Statement (Form S-3 No. 333-211426) of Black Stone Minerals, L.P., and (3) Registration Statement (Form S-3 No. 333-215857) of Black Stone Minerals, L.P.;of our reports dated February 26, 2019, with respect to the consolidated financial statements of Black Stone Minerals, L.P. and subsidiaries and theeffectiveness of internal control over financial reporting of Black Stone Minerals, L.P. and subsidiaries included in this Annual Report (Form 10-K) for theyear ended December 31, 2018./s/ Ernst & Young LLP Houston, TexasFebruary 26, 2019 Exhibit 23.2 CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTSWe hereby consent to the use of the name Netherland, Sewell & Associates, Inc., the references to our report of Black Stone Minerals, L.P.’s proved oil andnatural gas reserves estimates and future net revenue as of December 31, 2018, and the inclusion of our corresponding report letter, dated January 17, 2019, inthe 2018 Annual Report on Form 10-K (the “Annual Report”) of Black Stone Minerals, L.P. We hereby also consent to the incorporation by reference of suchreport and the information contained therein in the Registration Statement on Form S-8 (File No. 333-203909), Form S-3 (No. 333-211426), and Form S-3(No. 333-215857) of Black Stone Minerals, L.P. NETHERLAND, SEWELL & ASSOCIATES, INC. By:/s/ J. Carter Henson, Jr. J. Carter Henson, Jr., P.E. Senior Vice President Houston, Texas February 26, 2019 Exhibit 31.1Certification of Chief Executive OfficerPursuant to Rule 13a-14(a) and Rule 15d-14(a)of the Securities Exchange Act OF 1934, as amendedI, Thomas L. Carter, Jr., certify that:1.I have reviewed this report on Form 10-K of Black Stone Minerals, L.P. (the “registrant”);2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects thefinancial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;4.The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined inExchange Act Rules 13a-15(e) and 15d-15(e)) and internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))for the registrant and have: a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision,to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others withinthose entities, particularly during the period in which this report is being prepared; b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements forexternal purposes in accordance with generally accepted accounting principles; c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about theeffectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s mostrecent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely tomaterially affect, the registrant’s internal control over financial reporting; and5.The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which arereasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internalcontrol over financial reporting.Date:February 26, 2019 /s/ Thomas L. Carter, Jr. Thomas L. Carter, Jr. Chief Executive Officer and Chairman Black Stone Minerals GP, L.L.C.,the general partner of Black Stone Minerals, L.P. Exhibit 31.2Certification of Chief Financial OfficerPursuant to Rule 13a-14(a) and Rule 15d-14(a)of the Securities Exchange Act OF 1934, as amendedI, Jeff Wood, certify that:1.I have reviewed this report on Form 10-K of Black Stone Minerals, L.P. (the “registrant”);2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects thefinancial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;4.The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined inExchange Act Rules 13a-15(e) and 15d-15(e)) and internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))for the registrant and have: a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision,to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others withinthose entities, particularly during the period in which this report is being prepared; b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements forexternal purposes in accordance with generally accepted accounting principles; c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about theeffectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s mostrecent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely tomaterially affect, the registrant’s internal control over financial reporting; and5.The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which arereasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internalcontrol over financial reporting.Date:February 26, 2019 /s/ Jeff Wood Jeff Wood President and Chief Financial Officer Black Stone Minerals GP, L.L.C.,the general partner of Black Stone Minerals, L.P. Exhibit 32.1Certification ofChief Executive Officer and Chief Financial Officerunder Section 906 of theSarbanes Oxley Act of 2002, 18 U.S.C. § 1350In connection with the report on Form 10-K of Black Stone Minerals, L.P. (the “Company”), as filed with the Securities and Exchange Commission on thedate hereof (the “Report”), Thomas L. Carter, Jr., Chief Executive Officer of the Company, and Jeff Wood, Chief Financial Officer of the Company, eachcertify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge: (1)the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and (2)the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Date:February 26, 2019 /s/ Thomas L. Carter, Jr. Thomas L. Carter, Jr. Chief Executive Officer and Chairman Black Stone Minerals GP, L.L.C.,the general partner of Black Stone Minerals, L.P. Date:February 26, 2019 /s/ Jeff Wood Jeff Wood President and Chief Financial Officer Black Stone Minerals GP, L.L.C.,the general partner of Black Stone Minerals, L.P. January 17, 2019Mr. Brock E. MorrisBlack Stone Minerals, L.P.1001 Fannin, Suite 2020Houston, Texas 77002Dear Mr. Morris:In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2018, to the Black StoneMinerals, L.P. (Black Stone) interest in certain oil and gas properties located in the United States. We completed our evaluation on or about thedate of this letter. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by BlackStone. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and ExchangeCommission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for Black Stone'suse in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate forsuch purpose.We estimate the net reserves and future net revenue to the Black Stone interest in these properties, as of December 31, 2018, to be: Net Reserves Future Net Revenue (M$) Oil Gas Present WorthCategory (MBBL) (MMCF) Total at 10% Proved Developed Producing 17,413.8 254,791.3 1,591,211.8 988,699.7Proved Developed Non-Producing 153.2 23,441.1 72,044.0 41,743.9Proved Undeveloped 0.0 35,787.5 94,507.1 61,131.8 Total Proved 17,567.0 314,019.8 1,757,763.0 1,091,575.5Totals may not add because of rounding.The oil volumes shown include crude oil and condensate. Oil volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. Nostudy was made to determine whether probable or possible reserves might be established for these properties. The estimates of reserves andfuture revenue included herein have not been adjusted for risk. This report does not include any value that could be attributed to interests inundeveloped acreage beyond those tracts for which undeveloped reserves have been estimated.Gross revenue is Black Stone's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is afterdeductions for Black Stone's share of production taxes, ad valorem taxes, capital costs, abandonment costs, and operating expenses but beforeconsideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth,which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted orundiscounted, should not be construed as being the fair market value of the properties.Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the periodJanuary through December 2018. For oil volumes, the average West Texas Intermediate spot price of $65.56 per barrel is adjusted for quality,transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $3.100 per MMBTU is adjusted for energycontent, transportation fees, and market differentials. When applicable, gas prices have been adjusted to include the value for natural gas liquids.All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaininglives of the properties are $62.81 per barrel of oil and $2.978 per MCF of gas.Operating costs used in this report are based on operating expense records of Black Stone, where available. For other properties, we haveestimated operating costs based on our knowledge of similar operations in the area. Operating costs include the per-well overhead expensesallowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Operating costshave been divided into per-well costs and per-unit-of-production costs. Since all properties are nonoperated, headquarters general andadministrative overhead expenses of Black Stone are not included. Operating costs are not escalated for inflation.Capital costs used in this report were provided by Black Stone and are based on authorizations for expenditure and actual costs from recentactivity. Capital costs are included as required for workovers, new development wells, and production equipment. Based on our understanding offuture development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital coststo be reasonable. Abandonment costs used in this report are Black Stone's estimates of the costs to abandon the wells and production facilities,net of any salvage value. Capital costs and abandonment costs are not escalated for inflation.For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or conditionof the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do notinclude any costs due to such possible liability.We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the Black Stone interest.Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections arebased on Black Stone receiving its net revenue interest share of estimated future gross production. Additionally, we have been informed by BlackStone that they are not aware of any firm transportation contracts to which Black Stone is a party that contain volume commitments which mightrepresent a liability to the company; no adjustments have been made to our estimates of future revenue to account for such contracts.The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oiland gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible;probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimatesof reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance.In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to,that the properties will be developed consistent with current development plans as provided to us by Black Stone, that the properties will beoperated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner torecover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, therevenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies anduncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may varyfrom assumptions made while preparing this report.For the purposes of this report, we used technical and economic data including, but not limited to, well logs, well test data, production data,historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministicmethods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and GasReserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geosciencemethods, or a combination of methods, including performance analysis, analogy, and material balance, that we considered to be appropriate andnecessary to categorize and estimate reserves in accordance with SEC definitions and regulations. As in all aspects of oil and gas evaluation,there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent onlyinformed professional judgment.The data used in our estimates were obtained from Black Stone, public data sources, and the nonconfidential files of Netherland, Sewell &Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to theproperties or independently confirmed the actual degree or type of interest owned. The technical person primarily responsible for preparing theestimates presented herein meets the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPEStandards. J. Carter Henson, Jr., a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering atNSAI since 1989 and has over 8 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, andpetrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.Sincerely,NETHERLAND, SEWELL & ASSOCIATES, INC.Texas Registered Engineering Firm F-2699/s/ C.H. (Scott) Rees IIIBy: C.H. (Scott) Rees III, P.E.Chairman and Chief Executive Officer/s/ J. Carter Henson, Jr.By: J. Carter Henson, Jr., P.E. 73964Senior Vice PresidentDate Signed: January 17, 2019JCH:LRGPlease be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document isintended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions statedin the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digitaldocument.DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4‑10(a). Also included is supplementalinformation from (1) the 2018 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB AccountingStandards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations.(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase orlease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs,and other costs incurred in acquiring properties.(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth,temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus mayprovide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogousreservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest:(i)Same geological formation (but not necessarily in pressure communication with the reservoir of interest);(ii)Same environment of deposition;(iii)Similar geological structure; and(iv)Same drive mechanism.Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur,metals, and other non-hydrocarbons.(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, whenproduced, is in the liquid phase at surface pressure and temperature.(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from thegeoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:(i)Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared tothe cost of a new well; and(ii)Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving awell.Supplemental definitions from the 2018 Petroleum Resources Management System:Developed Producing Reserves – Expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate.Improved recovery Reserves are considered producing only after the improved recovery project is in operation.Developed Non-Producing Reserves – Shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals that are open atthe time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable ofproduction for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or futurere-completion before start of production with minor cost to access these reserves. In all cases, production can be initiated or restored with relatively low expenditurecompared to the cost of drilling a new well.(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil andgas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs ofdevelopment activities, are costs incurred to:(i)Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drillingsites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing theproved reserves.(ii)Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of wellequipment such as casing, tubing, pumping equipment, and the wellhead assembly.Definitions - Page 1 of 6DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)(iii)Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, andproduction storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.(iv)Provide improved recovery systems.(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. Asexamples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group ofseveral fields and associated facilities with a common ownership may constitute a development project.(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or isreasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oiland gas producing activities as defined in paragraph (a)(16) of this section.(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of thatdate.(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to haveprospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs maybe incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types ofexploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:(i)Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and otherexpenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological andgeophysical or "G&G" costs.(ii)Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and themaintenance of land and lease records.(iii)Dry hole contributions and bottom hole contributions.(iv)Costs of drilling and equipping exploratory wells.(v)Costs of drilling exploratory-type stratigraphic test wells.(13) Exploratory well. An exploratory well is 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 gasin another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well asthose items are defined in this section.(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/orstratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by localgeologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operationalfield. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broaderterms of basins, trends, provinces, plays, areas-of-interest, etc.(16) Oil and gas producing activities.(i)Oil and gas producing activities include:(A)The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;(B)The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from suchproperties;(C)The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition,construction, installation, and maintenance of field gathering and storage systems, such as:(1)Lifting the oil and gas to the surface; and(2)Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); andDefinitions - Page 2 of 6DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)(D)Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable naturalresources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on thelease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the productionfunction as:a.The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marineterminal; andb.In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaserprior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or afacility which upgrades such natural resources into synthetic oil or gas.Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in thestate in which the hydrocarbons are delivered.(ii)Oil and gas producing activities do not include:(A)Transporting, refining, or marketing oil and gas;(B)Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legalright to produce or a revenue interest in such production;(C)Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can beextracted; or(D)Production of geothermal steam.(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.(i)When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plusprobable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimatelyrecovered will equal or exceed the proved plus probable plus possible reserves estimates.(ii)Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data areprogressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and verticallimits of commercial production from the reservoir by a defined project.(iii)Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recoveryquantities assumed for probable reserves.(iv)The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical andcommercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similarprojects.(v)Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the sameaccumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuitiesand that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known(proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are incommunication with the proved reservoir.(vi)Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential existsfor an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the highercontact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certaintycriterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together withproved reserves, are as likely as not to be recovered.(i)When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plusprobable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal orexceed the proved plus probable reserves estimates.(ii)Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data areless certain, even if the interpreted reservoir continuity of structure or productivityDefinitions - Page 3 of 6DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area ifthese areas are in communication with the proved reservoir.(iii)Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons inplace than assumed for proved reserves.(iv)See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occurfor each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associatedprobabilities of occurrence.(20) Production costs.(i)Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of supportequipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the costof oil and gas produced. Examples of production costs (sometimes called lifting costs) are:(A)Costs of labor to operate the wells and related equipment and facilities.(B)Repairs and maintenance.(C)Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.(D)Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.(E)Severance taxes.(ii)Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, andmarketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation andapplicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization ofcapitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced alongwith production (lifting) costs identified above.(21) Proved area. The part of a property to which proved reserves have been specifically attributed.(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and 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 economicconditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidenceindicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract thehydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.(i)The area of the reservoir considered as proved includes:(A)The area identified by drilling and limited by fluid contacts, if any, and(B)Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economicallyproducible oil or gas on the basis of available geoscience and engineering data.(ii)In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a wellpenetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.(iii)Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap,proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data andreliable technology establish the higher contact with reasonable certainty.(iv)Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) areincluded in the proved classification when:(A)Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operationof an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonablecertainty of the engineering analysis on which the project or program was based; and(B)The project has been approved for development by all necessary parties and entities, including governmental entities.Definitions - Page 4 of 6DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)(v)Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be theaverage price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmeticaverage of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excludingescalations based upon future conditions.(23) Proved properties. Properties with proved reserves.(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. Ifprobabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A highdegree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience(geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certainEUR is much more likely to increase or remain constant than to decrease.(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested andhas been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogousformation.(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a givendate, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there willexist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and allpermits and financing required to implement the project.Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs arepenetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by anon-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).Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of theyear:a. Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)b. Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation ofthe properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordancewith paragraphs 932-235-50-3 through 50-11B:a. Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities ofthose reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing theproved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated developmentexpenditures are significant, they shall be presented separately from estimated production costs.c. Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of futuretax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. Thefuture income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.d. Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from futurecash inflows.e. Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to provedoil and gas reserves.f. Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.Definitions - Page 5 of 6DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined byimpermeable rock or water barriers and is individual and separate from other reservoirs.(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimatedto be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gasinjection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition.Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as coretests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known areaor "development type" if drilled in a known area.(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells onundrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.(i)Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production whendrilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.(ii)Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they arescheduled to be drilled within five years, unless the specific circumstances, justify a longer time.From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations —by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of thefacts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five yearsinclude, but are not limited to, the following:Ÿ The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wellsnecessary to maintain the lease generally would not constitute significant development activities);Ÿ The company's historical record at completing development of comparable long-term projects;Ÿ The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;Ÿ The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development planseveral times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); andŸ The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions ondevelopment on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties withhigher priority).(iii)Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or otherimproved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or ananalogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.(32) Unproved properties. Properties with no proved reserves.Definitions - Page 6 of 6

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