Black Stone Minerals
Annual Report 2017

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, 2017OR¨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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and postedpursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post suchfiles). 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. (Check One): Large Accelerated Filerxx Accelerated Filer¨¨ Non-Accelerated Filer¨¨(Do not check if a smaller reporting company) Smaller Reporting Company¨¨ Emerging Growth Company¨¨ If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised 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 $1,197,800,850 on June 30, 2017, the last business day of the registrant’s most recently completed secondfiscal quarter, based on a closing price of $15.76 per unit as reported by the New York Stock Exchange on such date. As of February 20, 2018, 104,258,290 common units,95,388,424 subordinated units, 24,803 Series A redeemable preferred units, and 14,711,219 Series B cumulative convertible preferred units of the registrant were outstanding.Documents Incorporated by Reference: Certain information called for in Items 10, 11, 12, 13, and 14 of Part III are incorporated by reference from the registrant’s definitive 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 FACTORS30ITEM 1B.UNRESOLVED STAFF COMMENTS51ITEM 3.LEGAL PROCEEDINGS51ITEM 4.MINE SAFETY DISCLOSURES51 PART II ITEM 5.MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS, AND ISSUER PURCHASESOF EQUITY SECURITIES52ITEM 6.SELECTED FINANCIAL DATA58ITEM 7.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS59ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK76ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA76ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE76ITEM 9A.CONTROLS AND PROCEDURES77ITEM 9B.OTHER INFORMATION77 PART III ITEM 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE78ITEM 11.EXECUTIVE COMPENSATION78ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDERMATTERS78ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE78ITEM 14.PRINCIPAL ACCOUNTING FEES AND SERVICES78 PART IV ITEM 15.EXHIBITS AND FINANCIAL STATEMENT SCHEDULES79ii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 in the acquisition, exploitation, and exploration of proved oil and natural gas reserves.Development well. A well drilled within the proved area of an oil and natural gas reservoir to the depth of a stratigraphic horizon known to be productive.Differential. An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil 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 at a right angle withina specified 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 constituting part of thecurrent operating expenses of a working interest. Such costs include labor, supplies, repairs, maintenance, allocated overhead charges, workover costs,insurance, and other expenses incidental to production, but exclude lease acquisition or drilling or completion costs.Log. An analysis that provides information on porosity, hydraulic conductivity, and fluid content of formations drilled in fluid-filled boreholes.MBbls. One thousand barrels of oil or other liquid hydrocarbons.MBoe. One thousand Boe.MBoe/d. MBoe per day.Mcf. One thousand cubic feet of natural gas.Mineral interests. Real-property interests that grant ownership of the oil and natural gas under a tract of land and the rights to explore for, drill for, 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, in average pressure and temperature conditions, is found in a gaseous state. In nature, it is found inunderground accumulations, 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. The majority of our producing acreage is pooled with third-party acreage. Pooling refers to an operator’s consolidation of multiple adjacent leasedtracts, which may be covered by multiple leases with multiple lessors, in order to maximize drilling efficiency or to comply with state mandated well spacingrequirements. Pooling dilutes our royalty in a given well or unit, but it also increases both the acreage footprint and the number of wells in which we have aneconomic interest. To estimate our total potential drilling locations in a given play, we include third-party acreage that is pooled with our acreage.Production Costs. The production or operational costs incurred while extracting and producing, storing, and transporting oil and/or natural gas. Typical ofthese costs are wages for workers, facilities lease costs, equipment maintenance, logistical support, applicable taxes, and insurance.PUD. Proved undeveloped, used to characterize reserves.Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the productionexceed production expenses and taxes.Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.Proved developed producing reserves. Reserves expected to be recovered from existing completion intervals in existing wells.Proved reserves. The estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to 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 costs of development.Seismic data. Seismic data is used by scientists to interpret the composition, fluid content, extent, and geometry of rocks in the subsurface. Seismic data 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. Because we are a limitedpartnership, we are generally not subject to federal or state income taxes and thus make no provision for federal or state income taxes in the calculation of ourstandardized measure. Standardized measure does not give effect to derivative transactions.Tight formation. A formation with low permeability that produces natural gas with low flow rates for long periods of time.Trend. A region of oil and/or natural gas production, the geographic limits of which have been generally defined, having geological characteristics that 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. An operating interest that gives the owner the right to drill, produce, and conduct operating activities on the property, and receive a shareof 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 terms on those leases to encourage and acceleratedrilling activity, and selectively participating alongside our lessees on a working-interest basis in low-risk development-drilling opportunities on ourinterests. Our primary business objective is to grow our reserves, production, and cash generated from operations over the long term, while paying, to theextent practicable, a growing quarterly distribution to our unitholders.We own mineral interests in approximately 16.8 million acres, with an average 43.4% ownership interest in that acreage. We also own NPRIs in 1.9million acres 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 approximately 55,728 producing wells. Our mineral and royalty interests are located in 41 states and in 64 onshore basins in the continentalUnited States. Many of these interests are in active resource plays, including the Haynesville/Bossier Shales in East Texas/Western Louisiana, theWolfcamp/Spraberry/Bone Spring in the Permian Basin, the Bakken/Three Forks in the Williston Basin, the Eagle Ford Shale in South Texas, theNiobrara/Codell Shales in the DJ Basin, and the Fayetteville Shale in the Arkoma Basin, as well as emerging plays such as the Lower Wilcox play in EastTexas and the Canyon Lime play in the Texas Panhandle. The combination of the breadth of our asset base, the long-lived, non-cost-bearing nature of ourmineral and royalty interests, and our active management expose us to potential additional production and reserves from new and existing plays withoutinvesting 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 at a price to the public of $19.00 per common unit. Our common units trade on the New YorkStock 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Our AssetsAs of December 31, 2017, our total estimated proved oil and natural gas reserves were 67,945 MBoe based on a reserve report prepared by Netherland,Sewell & Associates, Inc. (“NSAI”), an independent third-party petroleum engineering firm. Of the reserves as of December 31, 2017, approximately 83.5%were proved developed reserves (approximately 82.4% proved developed producing and 1.1% proved developed non-producing) and approximately 16.5%were proved undeveloped reserves. At December 31, 2017, our estimated proved reserves were 26.3% oil and 73.7% natural gas.The locations of our oil and natural gas properties are presented on the following map. Additional information related to these properties follows thismap. 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, drill for, and produce oil and natural gas on that land or to lease those exploration and development rights to a third party. When those 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 that we have the most influence over. In addition to mineral interests, we also own other types of non-cost-bearing royalty interests, which include:•Nonparticipating royalty interests (“NPRIs”), which are royalty interests that are carved out of the mineral estate and represent the right, which istypically perpetual, to receive a fixed, cost-free percentage of production or revenue from production, without an associated right to lease or receivelease bonus; and3•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.Working-Interest Participation ProgramWe own working interests related to our mineral interests in various plays across our asset base. Many of these working interests were acquired throughworking-interest participation rights, which we often include in the terms of our leases. This participation right complements our core mineral-and-royalty-interest business because it allows us to realize additional value from our minerals. Under the terms of the relevant leases, we are typically granted a unit-by-unit or a well-by-well option to participate on a non-operated working-interest basis in drilling opportunities on our mineral acreage. This right to participatein a unit or well is exercisable at our sole discretion. We generally only exercise this option when the results from prior drilling and production activitieshave substantially reduced the economic risk associated with development drilling and where we believe the probability of achieving attractive economicreturns is high. A small portion of our working interests, unrelated to our mineral and royalty assets, were acquired because of the attractive working-interestinvestment opportunities on those properties. The majority of these assets are focused in the Anadarko Basin, and to a lesser extent, in the Permian andPowder River Basins.We collectively refer to these working interests as our “working-interest participation program.” When we participate in non-operated working-interestopportunities, we are required to pay our portion of the costs associated with drilling and operating these wells. Working interest production represented40.0% of our total production volumes during the year ended December 31, 2017. As of December 31, 2017, we owned non-operated working interests in9,688 gross (352 net) wells.Our 2018 drilling capital expenditure budget associated with our working-interest participation program is expected to range between $15 million and$25 million. Approximately 99% of our 2018 drilling capital budget will be spent in the Haynesville/Bossier play with the remainder spent in various playsincluding the Bakken/Three Forks and Wolfcamp plays. In 2018, we also expect to spend an additional $10 million to $12 million to drill two 100%working interest exploratory wells to evaluate a Lower Wilcox prospect in East Texas.Farmout 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 are anticipated to be drilled over an initial phase, beginning with wells spud afterJanuary 1, 2017. As of December 31, 2017, 10 wells had been drilled during the initial phase. At its option, Canaan may participate in two additional phaseswith each phase continuing for the lesser of 2 years or until 20 wells have been drilled. During the first three phases of the agreement, Canaan will commit ona phase-by-phase basis and fund 80% of our drilling and completion costs and will be assigned 80% of our working interests in such wells (40% workinginterest on an 8/8ths basis). After the third phase, Canaan can earn 40% of our working interest (20% working interest on an 8/8ths basis) in additional wellsdrilled in the area by continuing to fund 40% of our costs for those wells on a well-by-well basis. We will receive a base ORRI before payout and anadditional ORRI after payout on all wells drilled under the agreement. The Canaan Farmout is anticipated to reduce our future capital expenditures byapproximately $40 to $50 million annually during the term of the agreement.On November 21, 2017, we entered into a farmout agreement with a portfolio company of Tailwater Capital, LLC, Pivotal Petroleum Partners (“Pivotal”),that covers substantially all of our remaining working interests under active development in the Shelby Trough area of East Texas targeting the Haynesvilleand Bossier shale acreage after giving effect to the Canaan Farmout (discussed above) over the next eight years. In wells operated by XTO Energy Inc. in SanAugustine County, Texas, Pivotal will earn our remaining approximate 20% working interest (10% working interest on an 8/8ths basis) not covered by theCanaan Farmout, as well as 100% of our working interests (ranging from approximately 12.5% to 25% on an 8/8ths basis) in wells operated by our othermajor operator in the area. Initially, Pivotal will be obligated to fund the development of up to 80 wells across several development areas and then will haveoptions to continue funding our working interest across those areas for the duration of the eight year term. After the funding of a designated group of wells byPivotal and once Pivotal achieves a specified payout for such well group, the Partnership will obtain a majority of the original working interest in thedesignated group of wells.As a result of the farmout agreements with Canaan and Pivotal, we expect capital requirements associated with non-operated working interests to beminimal beyond the first quarter of 2018.4Our PropertiesMaterial Basins and Producing RegionsWe may own more than one type of interest in the same tract of land. For example, where we have acquired working interests through our working-interest participation program in a given tract, our working-interest acreage in that tract will relate to the same acres as our mineral-interest acreage in thattract. Consequently, some of the acreage shown for one type of interest below may also be included in the acreage shown for another type of interest. Becauseof our working-interest participation program, overlap between working-interest acreage and mineral-and-royalty-interest acreage can be significant, whileoverlap between the different types of mineral and royalty interests is not significant. The following table describes our mineral and royalty interests andworking interests: Acreage as of December 31, 2017 Average DailyProduction (Boe/d)For the Year EndedDecember 31, 2017 Mineral and Royalty Interests Working Interests1 USGS Petroleum Province2 Mineral Interests NPRIs ORRIs Gross Net Louisiana-Mississippi Salt Basins 5,408,632 238,426 26,104 59,117 7,999 4,752Western Gulf (onshore) 1,732,750 297,303 282,208 122,167 18,692 5,561Permian Basin 1,647,573 800,654 185,069 8,113 5,051 2,820Williston Basin 1,543,797 65,974 34,099 59,875 7,895 3,624Palo Duro Basin 1,024,913 22,791 1,120 — — 87East Texas Basin 598,717 55,155 78,960 148,121 50,693 13,704Anadarko Basin 577,264 13,723 280,283 30,939 21,254 1,652Appalachian Basin 495,843 416 14,861 — — 853Arkoma Basin 357,394 9,999 38,109 9,045 2,333 1,337Bend Arch-Fort Worth Basin 149,260 56,703 43,514 52,885 13,475 353Southwestern Wyoming 22,338 — 77,529 14,056 2,050 483Other 3,235,453 314,539 1,033,649 39,152 8,742 1,785Total 16,793,934 1,875,683 2,095,505 543,470 138,184 37,0111 Excludes acreage for which we have incomplete seller records. 2 The basins and regions shown in the table are consistent with U.S. Geological Survey (“USGS”) delineations of petroleum provinces of onshore and stateoffshore areas in the continental United States. We refer to these petroleum provinces as “basins” or “regions.”The following is an overview of the U.S. basins and regions we consider most material to our current and future business.•Louisiana-Mississippi Salt Basins. The Louisiana-Mississippi Salt Basins region ranges from northern Louisiana and southern Arkansas through southcentral and southern Mississippi, southern Alabama, and the Florida Panhandle. The Haynesville/Bossier plays, which have been extensivelydelineated through drilling, are the most prospective and most active unconventional plays for natural gas production and reserves within this region.Approximately half of the Haynesville/Bossier plays’ prospective acreage is within the Louisiana-Mississippi Salt Basins region, where we ownsignificant mineral and royalty interests and working interests. There are a number of additional conventional and unconventional plays in this regionin which we hold considerable mineral and royalty interests, including the Brown Dense, Cotton Valley, Hosston, Norphlet, Smackover, TuscaloosaMarine Shale, and Wilcox plays.•Western Gulf (onshore). The Western Gulf region, which ranges from South Texas through southeastern Louisiana, includes a variety of bothconventional and unconventional plays. We have extensive exposure to the Eagle Ford Shale in South Texas, where we are experiencing a significantlevel of development drilling on our mineral interests within the oil and rich-gas and condensate areas of the play. In addition to the Eagle Ford Shaleplay, there are a number of other conventional and unconventional plays to which we have exposure to in the region, including the Austin Chalk,Buda, Eaglebine (or Maness) Shale, Frio, Glenrose, Olmos, Woodbine, Vicksburg, Wilcox, and Yegua plays.5•Permian Basin. The Permian Basin ranges from southeastern New Mexico into West Texas and is currently one of the most active areas for drilling inthe United States. It includes three geologic provinces: the Midland Basin to the east, the Delaware Basin to the west, and the Central Basin Platformin between. Our acreage underlies prospective areas for the Wolfcamp play in the Midland and Delaware Basins, the Spraberry formation in theMidland Basin, and the Bone Spring formation in the Delaware Basin, which are among the plays most actively targeted by drillers within the basin. Inaddition to these plays, we own mineral and royalty interests that are prospective for a number of other conventional and unconventional plays in thePermian Basin, including the Atoka, Clearfork, Ellenberger, San Andres, Strawn, and Wichita Albany plays.•Williston Basin. The Williston Basin stretches through the western half of North Dakota, the northwest part of South Dakota, and eastern Montana andincludes plays such as the Bakken/Three Forks plays, where we have significant exposure through our mineral and royalty interests as well as throughour working interests. We are also exposed to other well-known plays in the basin, including the Duperow, Mission Canyon, Madison, Ratcliff, RedRiver, and Spearfish plays.•Palo Duro Basin. The Palo Duro Basin covers much of the Texas Panhandle but also occupies a small portion of the Oklahoma Panhandle and extendspartially into New Mexico to the west. We have a significant acreage position in the Palo Duro Basin, much of which underlies an unconventional oilplay in the Canyon Lime. We are also well positioned relative to a number of other conventional and unconventional plays in the Palo Duro Basin,including the Brown Dolomite, Canyon Wash, Cisco Sand, and Strawn Wash plays. •East Texas Basin. The East Texas Basin ranges from central East Texas to northeast Texas and includes the Haynesville/Bossier plays and the CottonValley play, which are among the most prolific natural gas plays in the basin. We own a material acreage position in the southern Shelby Trough areaof the Haynesville/Bossier plays located in San Augustine, Nacogdoches, and Angelina Counties, which is one of the most active areas being drilledtoday for that play in the East Texas Basin. There are other active plays to which we have significant exposure, including the Bossier Sand, GoodlandLime, James Lime, Pettit, Travis Peak, Smackover, and Woodbine plays.•Anadarko Basin. The Anadarko Basin encompasses the Texas Panhandle, southeastern Colorado, southwestern Kansas, and western Oklahoma. Weown mineral and royalty interests as well as working interests in prospective areas for most of the prolific plays in this basin, including the GraniteWash, Atoka, Cleveland, Meramac, and Woodford Shale plays. Other plays in which we hold interests in prospective acreage include the CottageGrove, Hogshooter, Marmaton, Springer, and Tonkawa plays.•Appalachian Basin. The Appalachian Basin covers most of Pennsylvania, eastern Ohio, West Virginia, western Maryland, eastern Kentucky, centralTennessee, western Virginia, northwestern Georgia, and northern Alabama. The basin’s most active plays in which we have acreage are the MarcellusShale and Utica plays, which cover most of western Pennsylvania, northern West Virginia, and eastern Ohio. In addition to the Marcellus Shale, thereare a number of other conventional and unconventional plays to which we have material exposure in the Appalachian Basin, including the Berea, BigInjun, Devonian, Huron, Rhinestreet, and Utica plays. •Arkoma Basin. The Arkoma Basin stretches from southeast Oklahoma through central Arkansas. The Fayetteville Shale play is one of the basin’s mostsignificant unconventional natural gas plays. We own material mineral and royalty interests within the prospective area of the Fayetteville Shale. Inaddition, we have exposure to a number of other conventional and unconventional plays in the basin, including the Atoka, Cromwell, Dunn, Hale, andWoodford Shale plays.•Bend Arch-Fort Worth Basin. The Bend Arch-Fort Worth Basin covers much of north central Texas and includes the Barnett Shale play as its mostactive unconventional play. Through our mineral and royalty interests in this basin, we have significant exposure to the Barnett Shale as well as anumber of other active conventional and unconventional plays in the basin, including the Bend Conglomerate, Caddo, Marble Falls, andMississippian Lime plays.•Southwestern Wyoming. The Southwestern Wyoming region covers most of southern and western Wyoming. The Pinedale Anticline is one of theregion’s largest producing fields and mainly produces from the Lance formation. We have a meaningful position in the Pinedale Anticline, and wehave interests prospective for other plays as well, including the Mesaverde, Niobrara, and Wasatch plays.6Interests by USGS Petroleum ProvinceThe following tables present information about our mineral-and-royalty-interest and non-operated working-interest acreage, production, and well countby USGS petroleum province.Mineral InterestsThe following table sets forth information about our mineral interests: As of December 31, 2017 Average Daily Production (Boe/d) for the YearEnded December 31,USGS Petroleum Province1 Acres Average OwnershipInterest2 Average OwnershipLeased3 2017 2016 2015Louisiana-Mississippi Salt Basins 5,408,632 53.3% 8.7% 3,867 3,415 3,384Western Gulf (onshore) 1,732,750 52.7% 36.0% 4,668 4,526 5,021Permian Basin 1,647,573 11.6% 79.2% 2,443 1,035 585Williston Basin 1,543,797 14.6% 44.7% 2,906 2,534 2,430Palo Duro Basin 1,024,913 46.2% 8.7% 75 24 23East Texas Basin 598,717 53.0% 32.3% 3,098 1,854 884Black Warrior Basin 594,906 54.6% 2.3% 38 — 39Anadarko Basin 577,264 31.7% 61.8% 745 673 959Eastern Great Basin 567,909 96.7% 0.1% — 39 —Appalachian Basin 495,843 39.4% 15.3% 191 163 80Arkoma Basin 357,394 52.9% 31.6% 1,172 1,302 1,458Western Great Basin 338,303 90.5% — — — —North-Central Montana 182,868 13.5% 32.5% 3 9 4Piedmont 179,879 67.8% — — — —Atlantic Coastal Plain 171,791 12.5% 31.7% — 199 —Bend Arch-Fort Worth Basin 149,260 20.8% 34.7% 198 — 392Cherokee Platform 112,384 13.8% 33.6% 26 34 41Florida Peninsula 90,744 12.1% 47.6% — 2 —Illinois Basin 80,864 53.1% 8.0% 2 3 2Powder River Basin 80,239 11.2% 26.7% 6 — 56Other 857,904 30.6% 27.2% 967 1,295 301Total 16,793,934 43.4% 26.4% 20,405 17,107 15,6591 The basins and regions shown in the table are consistent with USGS petroleum-province delineations.2Ownership interest is equal to the percentage that our undivided ownership interest in a tract bears to the entire tract. The average ownership interestsshown reflects the weighted averages of our ownership interests in all tracts in the basin or region. Our weighted-average mineral royalty for all of ourmineral interests is approximately 20%, which may be multiplied by our ownership interest to approximate the average royalty interest in our mineral androyalty interests.3The average percent leased reflects the weighted average of our leased acres relative to our total acreage on a tract-by-tract basis in the basin or region. 7NPRIsThe following table sets forth information about our NPRIs: As of December 31, 2017 Average Daily Production (Boe/d) for the YearEnded December 31,USGS Petroleum Province1 Acres Average RoyaltyInterest2 Average PercentLeased3 2017 2016 2015Permian Basin 800,654 1.9% 61.6% 39 19 31Western Gulf (onshore) 297,303 3.5% 61.2% 7 14 10Louisiana-Mississippi Salt Basins 238,426 4.1% 64.9% 4 1 —North-Central Montana 138,027 3.0% 11.6% — — —Marathon Thrust Belt 117,442 4.9% 1.6% — — —Williston Basin 65,974 2.7% 38.0% 108 92 106Bend Arch-Fort Worth Basin 56,703 4.1% 14.4% 1 1 —East Texas Basin 55,155 2.6% 79.9% 556 179 381Powder River Basin 33,467 6.1% 7.2% — — —Palo Duro Basin 22,791 3.8% 1.7% — — —Anadarko Basin 13,723 3.6% 94.3% 32 18 8Arkoma Basin 9,999 2.4% 85.3% 9 13 21Cambridge Arch-Central Kansas Uplift 8,903 5.5% 83.7% — — —Southwest Montana 4,367 6.2% 7.3% — — —Cherokee Platform 2,555 4.7% 31.3% — — —Nemaha Uplift 2,334 1.6% 41.4% — — —Montana Thrust Belt 2,242 4.1% —% — — —Sedgwick Basin 1,850 2.5% 82.2% — — —Black Warrior Basin 1,500 0.3% 100.0% — — —Uinta-Piceance Basin 560 1.0% —% — — —Other 1,708 5.2% 29.9% 169 180 185Total 1,875,683 3.0% 51.3% 925 518 7421 The basins and regions shown in the table are consistent with USGS petroleum-province delineations.2Average royalty interest is equal to the weighted-average percentage of production or revenues (before operating costs) that we are entitled to on a tract-by-tract basis in the basin or region. NPRIs may be denominated as a “fractional royalty,” which entitles the owner to the stated fraction of gross production, ora “fraction of royalty,” where the stated fraction is multiplied by the lease royalty. In cases where our land documentation does not specify the form ofNPRI, we have assumed a fractional royalty for purposes of the average royalty interests shown above.3The average percent leased reflects the weighted average of our leased acres relative to our total acreage on a tract-by-tract basis in the basin or region.8ORRIsThe following table sets forth information about our ORRIs: As of December 31, 2017 Average Daily Production (Boe/d) for the Year EndedDecember 31,USGS Petroleum Province1 Acres Average RoyaltyInterest2 2017 2016 2015North-Central Montana 457,897 2.5% 2 13 35Western Gulf (onshore) 282,208 2.8% 246 157 262Anadarko Basin 280,283 3.4% 188 200 232Permian Basin 185,069 1.0% 106 64 72Uinta-Piceance Basin 174,701 2.5% 21 24 37Powder River Basin 120,722 3.8% 26 45 98East Texas Basin 78,960 6.9% 97 96 81Southwestern Wyoming 77,529 2.0% 415 451 529Michigan Basin 56,512 1.0% 20 18 21Denver Basin 45,608 4.4% 156 117 83Bend Arch-Fort Worth Basin 43,514 4.7% 100 108 160Paradox Basin 43,301 1.3% 1 — 2Arkoma Basin 38,109 3.0% 20 23 29San Juan Basin 37,644 1.1% 4 6 3Williston Basin 34,099 2.1% 62 59 76Louisiana-Mississippi Salt Basins 26,104 3.8% 405 705 1,185Northern Alaska 24,214 3.5% 28 28 32Wind River Basin 8,528 1.1% 34 27 33Cambridge Arch-Central Kansas Uplift 17,469 4.9% 3 3 5Appalachian Basin 14,861 2.5% 706 693 —Other 48,173 1.4% 91 156 911Total 2,095,505 2.8% 2,731 2,993 3,8861 The basins and regions shown in the table are consistent with USGS petroleum-province delineations.2 Average royalty interest is equal to the weighted-average percentage of production or revenues (before operating costs) that we are entitled to on a tract-by-tract basis in the basin or region. 9Working InterestsThe following table sets forth information about our non-operated working interests: As of December 31, 2017 Average Daily Production (Boe/d) for the Year EndedDecember 31,USGS Petroleum Province1 Gross Acres2 Net Acres2 2017 2016 2015East Texas Basin 148,121 50,693 9,803 4,776 2,341Western Gulf (onshore) 122,167 18,692 640 1,494 1,234Williston Basin 59,875 7,895 548 1,377 1,425Louisiana-Mississippi Salt Basins 59,117 7,999 476 932 1,007Bend Arch-Fort Worth Basin 52,885 13,475 54 118 108Anadarko Basin 30,939 21,254 687 1,018 1,205Southwestern Wyoming 14,056 2,050 24 11 1Michigan Basin 13,287 1,330 — 6 6Powder River Basin 12,936 3,382 68 103 169Arkoma Basin 9,045 2,333 136 277 341Permian Basin 8,113 5,051 232 323 214Denver Basin 4,923 1,040 133 130 5Paradox Basin 2,602 1,281 2 4 5North-Central Montana 2,080 605 — 1 1Uinta-Piceance Basin 1,005 482 50 68 —San Juan Basin 960 334 — 15 11Wind River Basin 440 43 — — —Southern Oklahoma 390 92 97 132 174Cherokee Platform 328 137 — 1 5Illinois Basin 200 16 — — —Other 1 — — 279 128Total 543,470 138,184 12,950 11,065 8,3801 The basins and regions shown in the table are consistent with USGS petroleum-province delineations.2 Excludes acreage that is not quantifiable due to incomplete seller records. 10WellsThe following tables set forth information about our mineral-and-royalty-interest and working-interest wells as of December 31, 2017:Mineral and Royalty Interests Working InterestsUSGS Petroleum Province1 Gross Well Count2 USGS Petroleum Province1 Gross Well Count2Permian Basin 23,685 Anadarko Basin 2,898Anadarko Basin 4,068 Uinta-Piceance Basin 1,378East Texas Basin 3,992 Permian Basin 908Williston Basin 3,561 East Texas Basin 907Louisiana-Mississippi Salt Basin 3,504 Arkoma Basin 751Western Gulf (onshore) 3,494 Western Gulf (onshore) 640Arkoma Basin 2,009 Louisiana-Mississippi Salt Basin 546Uinta-Piceance Basin 1,750 Williston Basin 542Bend Arch-Fort Worth Basin 1,230 Southern Oklahoma 389Michigan Basin 924 Bend Arch-Fort Worth Basin 228Appalachian Basin 846 Appalachian Basin 189Southwestern Wyoming 783 Nemaha Uplift 104Denver Basin 707 Powder River Basin 63Cherokee Platform 642 Michigan Basin 62San Juan Basin 627 Denver Basin 21North-Central Montana 605 Cherokee Platform 16Powder River Basin 490 Palo Duro Basin 11Wyoming Thrust Belt 391 North-Central Montana 10Southern Oklahoma 369 Paradox Basin 8San Joaquin Basin 363 Black Warrior Basin 5Other 1,688 Other 12Total 55,728 Total 9,6881 The basins and regions shown in the table are consistent with USGS petroleum-province delineations.2We own both mineral and royalty interests and working interests in 3,973 of the wells shown in each column above. 11Material Resource PlaysWe may own more than one type of interest in the same tract of land. For example, where we have acquired working interests through our working-interest participation program in a given tract, our working-interest acreage in that tract will relate to the same acres as our mineral-interest acreage in thattract. Consequently, some of the acreage shown for one type of interest above may also be included in the acreage shown for another type of interest. Becauseof our working-interest participation program, overlap between working-interest acreage and mineral-and-royalty-interest acreage can be significant, whileoverlap between the different types of mineral and royalty interests is not significant. The following table presents information about our mineral-and-royalty-interest and working-interest acreage by the resource plays we consider most material to our current and future business. These plays accounted for70% of our aggregate production for the year ended December 31, 2017. Acreage as of December 31, 20171 Mineral and Royalty Interests Working InterestsResource Play2 Mineral Interests NPRIs ORRIs Gross NetBakken Shale 366,359 40,022 15,450 55,220 7,239Haynesville Shale 360,587 7,335 28,741 191,523 55,169Three Forks 355,665 37,203 13,810 55,422 6,866Bossier Shale 329,717 1,896 20,530 178,902 53,753Wolfcamp — Midland 288,718 134,284 124,272 160 4Marcellus Shale 246,542 — 13,467 — —Canyon Lime 226,149 — — — —Tuscaloosa Marine Shale 189,147 23,397 2,192 — —Wolfcamp — Delaware 137,759 38,021 6,403 2,642 1,291Granite Wash 109,876 5,031 104,308 4,840 1,254Fayetteville Shale 74,401 4,789 11,861 — —Eagle Ford Shale 67,478 107,019 49,613 1,147 87Barnett Shale 61,788 4,164 37,633 13,417 7,7471 Excludes acreage for which we have incomplete seller records.2 The plays above have been delineated based on information from the Energy Information Administration ("EIA"), the USGS, or state agencies, or accordingto areas of the most active industry development. 12Interests by Resource PlayThe following tables present information about our mineral-and-royalty-interest and non-operated working-interest acreage, and production by resourceplay. As with the acreage shown for the basins and regions above, we may own more than one type of interest in the same tract of land. Consequently, some ofthe acreage shown for one type of interest below may also be included in the acreage shown for another type of interest.Mineral InterestsThe following table sets forth information about our mineral interests: As of December 31, 2017 Average Daily Production (Boe/d) for the Year EndedDecember 31,Resource Play1 Acres Average OwnershipInterest2 Average OwnershipLeased3 2017 2016 2015Bakken Shale 366,359 17.2% 76.6% 1,877 1,659 1,746Haynesville Shale 360,587 63.7% 52.2% 5,391 3,727 2,728Three Forks 355,665 16.8% 78.5% 991 968 823Bossier Shale 329,717 68.1% 49.1% 337 330 351Wolfcamp — Midland 288,718 4.6% 98.1% 659 136 76Marcellus Shale 246,542 14.4% 26.9% 118 111 71Canyon Lime 226,149 30.5% 30.2% 67 16 8Tuscaloosa Marine Shale 189,147 58.1% 43.8% 35 52 46Wolfcamp — Delaware 137,759 9.7% 97.0% 785 437 148Granite Wash 109,876 15.0% 60.6% 136 167 194Fayetteville Shale 74,401 56.0% 78.6% 1,014 1,181 1,349Eagle Ford Shale 67,478 14.1% 85.4% 1,743 2,095 2,355Barnett Shale 61,788 15.8% 57.2% 172 181 2391 The plays above have been delineated based on information from the EIA, the USGS, or state agencies, or according to areas of the most active industrydevelopment.2 Ownership interest is equal to the percentage that our undivided ownership interest in a tract bears to the entire tract. The per-play average ownershipinterests shown above reflect the weighted average of our ownership interests in all tracts in the play. Our weighted-average mineral royalty for all of ourmineral interests is approximately 20%, which may be multiplied by our ownership interest to approximate the average royalty interest in our mineral androyalty interests.3 The average percent leased reflects the weighted average of our leased acres relative to our total acreage on a tract-by-tract basis in the play. 13NPRIsThe following table sets forth information about our NPRIs: As of December 31, 2017 Average Daily Production (Boe/d) for the Year EndedDecember 31,Resource Play1 Acres Average Royalty Interest2 Average Percent Leased3 2017 2016 2015Wolfcamp — Midland 134,284 0.7% 82.8% 25 11 22Eagle Ford Shale 107,019 1.2% 42.4% 6 14 3Bakken Shale 40,022 1.3% 57.7% 74 63 56Wolfcamp — Delaware 38,021 0.6% 86.7% 7 4 1Three Forks 37,203 1.2% 61.3% 37 36 50Tuscaloosa Marine Shale 23,397 0.5% 93.3% — — —Haynesville Shale 7,335 4.2% 96.1% 443 167 325Granite Wash 5,031 0.8% 100.0% 31 16 5Fayetteville Shale 4,789 0.1% 100.0% 9 13 —Barnett Shale 4,164 2.7% 86.9% 1 1 —Bossier Shale 1,896 2.9% 51.8% 113 11 53Canyon Lime — — — — — —Marcellus Shale — — — — — —1The plays above have been delineated based on information from the EIA, the USGS, or state agencies, or according to areas of the most active industrydevelopment.2 Average royalty interest is equal to the weighted-average percentage of production or revenues (before operating costs) that we are entitled to on a tract-by-tract basis for the given area. NPRIs may be denominated as a “fractional royalty,” which entitles the owner to the stated fraction of gross production, or a“fraction of royalty,” where the stated fraction is multiplied by the lease royalty. In cases where our land documentation does not specify the form of NPRI,we have assumed a fractional royalty for purposes of the average royalty interests shown above.3The average percent leased reflects the weighted average of our leased acres relative to our total acreage on a tract-by-tract basis in the play. 14ORRIsThe following table sets forth information about our ORRIs: As of December 31, 2017 Average Daily Production (Boe/d) for the Year EndedDecember 31,Resource Play1 Acres Average Royalty Interest2 2017 2016 2015Wolfcamp — Midland 124,272 0.4% 31 <1 5Granite Wash 104,308 1.6% 72 155 115Eagle Ford Shale 49,613 2.2% 193 95 204Barnett Shale 37,633 5.0% 99 109 158Haynesville Shale 28,741 4.9% 383 686 1,111Bossier Shale 20,530 5.7% 8 28 57Bakken Shale 15,450 1.3% 32 34 41Three Forks 13,810 1.3% 25 21 27Marcellus Shale 13,467 2.3% 19 37 6Fayetteville Shale 11,861 4.0% — — —Wolfcamp — Delaware 6,403 2.1% 4 — —Tuscaloosa Marine Shale 2,192 13.5% — <1 —Canyon Lime — — — — —1 The plays above have been delineated based on information from the EIA, the USGS, or state agencies, or according to areas of the most active industrydevelopment.2Average royalty interest is equal to the weighted-average percentage of production or revenues (before operating costs) that we are entitled to on a tract-by-tract basis in this play. 15Working InterestsThe following table sets forth information about our working interests. As of December 31, 2017 Average Daily Production (Boe/d) for the Year EndedDecember 31,Resource Play1 Gross Acres2 Net Acres2 2017 2016 2015Haynesville Shale 191,523 55,169 9,631 5,077 2,909Bossier Shale 178,902 53,753 690 309 135Three Forks 55,422 6,866 194 491 551Bakken Shale 55,220 7,239 347 864 792Barnett Shale 13,417 7,747 51 87 104Granite Wash 4,840 1,254 283 429 537Wolfcamp — Delaware 2,642 1,291 143 150 23Eagle Ford Shale 1,147 87 — 76 11Wolfcamp — Midland 160 4 2 1 —Canyon Lime — — 14 — —Fayetteville Shale — — — 23 —Marcellus Shale — — — <1 —Tuscaloosa Marine Shale — — — — —1 The plays above have been delineated based on information from the EIA, the USGS, or state agencies, or according to areas of the most active industrydevelopment.2 Excludes acreage that is not quantifiable due to incomplete seller records.16Estimated Proved ReservesEvaluation and Review of Estimated Proved ReservesThe reserves estimates as of December 31, 2017, 2016, and 2015 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, 2017 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 32 years of reservoir-engineering and operations experience.Our historical proved reserve estimates were prepared in accordance with our internal control procedures. Throughout the year, our technical team 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 and net revenue interests in the reserves database against our well ownership system;•Review of historical realized commodity prices and differentials from index prices compared to the differentials used in the reserves database;•Evaluation of capital cost assumptions derived from Authority for Expenditure estimates received;•Review of actual historical production volumes compared to projections in the reserve report;•Discussion of material reserve variances among our internal reservoir engineers and our Senior Vice President, Engineering and Geology; and•Review of preliminary reserve estimates by our President and Chief Executive Officer with our internal technical staff.17Estimation of Proved 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, 2017, 2016, and 2015 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.In order to establish reasonable certainty with respect to our estimated net proved reserves, NSAI employed technologies including, but not limited to,well logs, core analysis, geologic maps, and available down hole pressure and production data, seismic data, and well test data. Reserves attributable toproducing wells with sufficient production history were estimated using appropriate decline curves or other performance relationships. Reserves attributableto producing wells with limited production history and for undeveloped locations were estimated using performance from analogous wells in the surroundingarea and geologic data to assess the reservoir continuity. In addition to assessing reservoir continuity, geologic data from well logs, core analyses, andseismic data were 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 inour properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operatingexpenses, and quantities of recoverable oil and natural gas may vary substantially from these estimates.18The following table presents our estimated proved oil and natural gas reserves: As of December 31, 20171 20162 20153 (Unaudited)Estimated proved developed reserves4: Oil (MBbls)17,891 18,150 15,497Natural gas (MMcf)233,017 223,057 174,555Total (MBoe)56,727 55,327 44,590Estimated proved undeveloped reserves5: Oil (MBbls)8 218 345Natural gas (MMcf)67,257 47,282 29,120Total (MBoe)11,218 8,098 5,198Estimated proved reserves: Oil (MBbls)17,899 18,368 15,842Natural gas (MMcf)300,274 270,339 203,675Total (MBoe)67,945 63,425 49,788Percent proved developed83.5% 87.2% 89.6%1 Estimates of reserves as of December 31, 2017, were prepared using oil and natural gas prices equal to the unweighted arithmetic average of the first-day-of-the-month market price for each month in the period from January through December 2017. For oil volumes, the average WTI spot oil price of $51.34 perbarrel is used for estimates of reserves for all the properties as of December 31, 2017. This average price is adjusted for quality, transportation fees, andmarket differentials. For natural gas volumes, the average Henry Hub price of $2.98 per MMBTU is used for estimates of reserves for all the properties as ofDecember 31, 2017. 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 $46.59 per barrel for oil and $2.70 per Mcf for natural gas as of December 31, 2017.2 Estimates of reserves as of December 31, 2016 were prepared using oil and natural gas prices equal to the unweighted arithmetic average of the first-day-of-the-month market price for each month in the period January through December 2016. For oil volumes, the average WTI spot oil price of $42.75 per 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. 3 Estimates of reserves as of December 31, 2015 were prepared using oil and natural gas prices equal to the unweighted arithmetic average of the first-day-of-the-month market price for each month in the period January through December 2015. For oil volumes, the average WTI spot oil price of $50.28 per barrelis used for estimates of reserves for all the properties as of December 31, 2015. These average prices are adjusted for quality, transportation fees, and marketdifferentials. For natural gas volumes, the average Henry Hub price of $2.59 per MMBTU is used for estimates of reserves for all the properties as ofDecember 31, 2015. 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 gas price weighted by production over the remaining lives ofthe properties is $2.45 per Mcf. 4 Proved developed reserves of 61, 74, and 84 MBoe as of December 31, 2017, 2016, and 2015, respectively, were attributable to noncontrolling interests inour consolidated subsidiaries.5 As of December 31, 2017, 2016, and 2015, no proved undeveloped reserves were attributable to noncontrolling interests in our consolidated subsidiaries.19Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas that 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, 2017, which is included as an exhibit to this Annual Report.Estimated Proved Undeveloped ReservesAs of December 31, 2017, our PUDs comprised 8 MBbls of oil and 67,257 MMcf of natural gas, for a total of 11,218 MBoe. PUDs will be converted fromundeveloped to developed as the applicable wells begin production.The following tables summarizes our changes in PUDs during the year ended December 31, 2017 (in MBoe): Estimated Proved Undeveloped Reserves (Unaudited)As of December 31, 20168,098Acquisitions of reserves920Divestiture of reserves(672)Extensions and discoveries4,564Revisions of previous estimates945Transfers to estimated proved developed(2,637)As of December 31, 201711,218New PUD reserves totaling 4,564 MBoe were added during the year ended December 31, 2017, resulting from development activities in theHaynesville/Bossier play. There were 920 MBoe of PUD reserves acquired in the Haynesville/Bossier play. This was partially offset by the divestiture of 672MBoe of PUD reserves associated with the farmouts to Canaan and to Pivotal.During the year ended December 31, 2017, we had reductions of 127 Mboe PUD reserves, primarily as a result of updated operator information. This wasoffset by increases in previous estimates of 1,072 Mboe based on performance from offset and analog production. This resulted in a total upward revision of945 Mboe comprised of an increase of 5,831 MMcf natural gas reserves and a decrease of 27 Mbbl of oil reserves.Costs incurred relating to the development of locations that were classified as PUDs at December 31, 2016 were $29.3 million during the year endedDecember 31, 2017. Additionally, during the year ended December 31, 2017, we incurred $26.7 million drilling and completing other wells which were notclassified as PUDs as of December 31, 2016. Estimated future development costs relating to the development of PUD reserves at December 31, 2017 areprojected to be approximately $20.5 million. All of our PUD drilling locations as of December 31, 2017 are scheduled to be drilled within five years or lessfrom the date the reserves were initially booked as proved undeveloped reserves.We generally do not have evidence of approval of our operators’ development plans. As a result, our proved undeveloped reserve estimates are limited tothose relatively few locations for which we have received and approved an authorization for expenditure and which remained undrilled as of December 31,2017. As of December 31, 2017, approximately 16.5% of our total proved reserves were classified as PUDs.20Oil and Natural Gas Production Prices and Production CostsProduction and Price HistoryFor the year ended December 31, 2017, 26.3% of our production and 47.1% of our oil and natural gas revenues were related to oil and condensateproduction and sales, respectively. During the same period, natural gas and NGL sales were 73.7% of our production and 52.9% of our oil and natural 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, 2017 2016 2015Production: Oil and condensate (MBbls)1 3,552 3,680 3,565Natural gas (MMcf)1 59,779 47,498 41,389Total (MBoe) 13,515 11,596 10,463Average daily production (MBoe/d) 37.0 31.7 28.7Realized Prices2: Oil and condensate (per Bbl) $47.78 $38.69 $45.87Natural gas and natural gas liquids (per Mcf)1 $3.19 $2.59 $2.80Unit Cost per Boe: Production costs and ad valorem taxes $3.51 $3.06 $3.421As a mineral-and-royalty interest owner, we are often provided insufficient and inconsistent data by our operators related to NGLs. As a result, we areunable to reliably determine the total volumes of NGLs associated with the production of natural gas on our acreage. As such, the realized prices for naturalgas account for all value attributable to NGLs. The oil and condensate production volumes and natural gas production volumes do not include NGLvolumes.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. As ofDecember 31, 2017, we owned mineral and royalty interests or working interests in 61,443 productive wells, which consisted of 38,112 oil wells and 23,331natural gas wells. As of December 31, 2017, we owned mineral and royalty interests in 55,728 productive wells, which consisted of 37,189 oil wells and18,539 natural gas wells, and working interests in 9,688 gross productive wells and 352 net productive wells, which consisted of 3,693 gross (65net) productive oil wells and 5,995 gross (287 net) productive natural gas wells. We own both mineral and royalty interests and working interests in 3,973 ofthese wells.21AcreageMineral and Royalty InterestsThe following table sets forth information relating to our acreage for our mineral interests as of December 31, 2017:State Developed Acreage Undeveloped Acreage Total AcreageTexas 342,912 4,717,981 5,060,893Oklahoma 116,555 458,278 574,833Louisiana 35,259 498,331 533,590Montana 20,844 545,925 566,769North Dakota 18,016 1,141,046 1,159,062Arkansas 4,887 1,274,169 1,279,056Mississippi 4,576 2,403,176 2,407,752Alabama 2,859 2,057,740 2,060,599Nevada — 792,588 792,588Florida — 743,452 743,452Other 82,555 1,532,785 1,615,340Total 628,463 16,165,471 16,793,934The following table sets forth information relating to our acreage for our NPRIs as of December 31, 2017:State Developed Acreage Undeveloped Acreage Total AcreageTexas 203,805 1,104,471 1,308,276Oklahoma 6,976 5,829 12,805Louisiana 10,508 86,521 97,029Montana 11,684 172,876 184,560North Dakota 20,100 20,898 40,998Arkansas 3,974 30,122 34,096Mississippi 10,533 137,299 147,832Wyoming 1,360 17,160 18,520New Mexico 14,289 960 15,249Kansas 9,042 2,983 12,025Other 367 3,926 4,293Total 292,638 1,583,045 1,875,683 22The following table sets forth information relating to our acreage for our ORRIs as of December 31, 2017:State Developed Acreage Undeveloped Acreage Total AcreageTexas 289,062 243,733 532,795Oklahoma 142,300 94,240 236,540Louisiana 15,907 93,997 109,904Montana 295,401 183,588 478,989Wyoming 133,461 100,516 233,977New Mexico 46,151 19,240 65,391Utah 40,510 153,317 193,827Michigan 55,272 1,239 56,511Colorado 27,108 23,647 50,755Alaska 7,664 16,550 24,214Other 75,808 36,794 112,602Total 1,128,644 966,861 2,095,505Working InterestsThe following table sets forth information relating to our acreage for our non-operated working interests as of December 31, 2017: Developed Acreage Undeveloped Acreage Total AcreageState Gross Net Gross Net Gross NetTexas 206,581 55,208 140,227 43,234 346,808 98,442Louisiana 41,683 4,638 14,662 2,812 56,345 7,450North Dakota 48,510 6,505 7,565 793 56,075 7,298Wyoming 22,210 4,161 4,902 994 27,112 5,155Michigan 13,208 1,330 79 — 13,287 1,330Oklahoma 11,623 3,030 10 3 11,633 3,033Colorado 7,725 2,601 — — 7,725 2,601Kansas 6,480 6,213 921 — 7,401 6,213New Mexico 6,238 3,622 160 80 6,398 3,702South Dakota 2,160 504 880 55 3,040 559Other 6,436 2,127 1,210 274 7,646 2,401Total 372,854 89,939 170,616 48,245 543,470 138,184The following table lists the net undeveloped acres, the net acres expiring in the years ending December 31, 2018, 2019, and 2020, and, whereapplicable, the net acres expiring that are subject to extension options: 2018 Expirations 2019 Expirations 2020 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.48,245 13,828 9 2,328 300 1,355 582 23Drilling 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, 2017 2016 2015Gross development wells: Productive 23.0 47.0 74.0Dry — — 1.0Total 23.0 47.0 75.0Net development wells: Productive 6.1 4.7 2.9Dry — — <0.1Total 6.1 4.7 2.9For the years ended December 31, 2017, 2016, and 2015, we did not have any productive or dry exploratory wells on a gross or net basis. As ofDecember 31, 2017, we had 20 wells in the process of drilling, completing or dewatering, or shut in awaiting infrastructure that are not reflected in the abovetable.24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 and25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, but legal challenges to this rule followed and the rule was stayednationwide by the U.S. Sixth Circuit Court of Appeals in October 2015 pending resolution of the court challenges. In January 2017, the U.S. Supreme Courtaccepted review of the rule to determine whether jurisdiction rests with the federal district or appellate courts. Additionally, following the issuance of apresidential executive order to review the rule, the EPA and the Corps proposed a rulemaking to repeal the June 2015 rule in June 2017. The EPA and Corpsalso announced their intent to issue a new rule defining the CWA’s jurisdiction. In January 2018, the U.S. Supreme Court held that jurisdiction to hearchallenges to the rule rests with federal district courts. In addition, the EPA has proposed to stay implementation of the June 2015 rule during the rulemakingprocess for the repeal. All of the actions of the EPA and the Corps are subject to legal challenge. As a result, future implementation of the June 2015 rule isuncertain at this time. To the extent this rule or a revised rule expands the scope of the CWA’s jurisdiction, operations on our properties could face increasedcosts and delays with respect to obtaining permits for dredge and fill activities in wetland areas in connection with any expansion activities. In addition, spillprevention, control, and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent thecontamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture, or leak. The EPA has also adopted regulations requiringcertain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. The OPA is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response 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. While ouroperators do not use diesel fuels in their hydraulic fracturing fluids, they may become subject to federal permitting under SDWA if their fracturing formulachanges. In addition, the SDWA grants the EPA broad authority to take action to protect public health when an underground source of drinking water isthreatened with pollution that presents an imminent and substantial endangerment to humans, which could result in orders prohibiting or limiting theoperations of oil and natural gas production facilities. Moreover, the SDWA also regulates saltwater disposal wells under the Underground Injection ControlProgram. Recent concerns related to the operation of saltwater disposal wells and induced seismicity have led some states to impose limits on the totalvolume of produced water such wells can dispose of, order disposal wells to cease operations, or limited the construction of new wells. These seismic eventshave also resulted in environmental groups and local residents filing lawsuits against operators in areas where the events occur seeking damages andinjunctions limiting or prohibiting saltwater disposal well construction activities and operations. A lack of saltwater disposal wells in production areas couldresult in increased disposal costs for our operators if they are forced to transport produced water by truck, pipeline, or other method over long distances, orforce them to curtail operations.Noncompliance with the Clean Water Act, SDWA, or the OPA may result in substantial administrative, civil, and criminal penalties, as well as injunctiveobligations, all of which could affect production from our properties and adversely affect our business and prospects.26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 newemission 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. The EPA is still inthe process of designating the attainment status of air quality areas with the new ozone NAAQS, but has stated that the agency intends to complete theprocess during the first half of 2018. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit the abilityof our operators to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. Morerecently, in June 2016, the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permittingpurposes applicable to the oil and natural gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, therebytriggering more stringent air permitting processes and requirements. These laws and regulations may increase the costs of compliance for oil and natural gasproducers and impact production on our properties, and federal and state regulatory agencies can impose administrative, civil, and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. Moreover, obtaining or renewingpermits has the potential to delay the development of oil and natural gas exploration and development projects. All of these factors could impact productionon 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.However, in June 2017, the EPA proposed to stay the requirements for a period of two years and revisit implementation of the federal methane rules in theirentirety. Several states, including Colorado, where we hold interests, have also adopted rules to control and minimize methane emissions from the productionof oil and natural gas. Moreover, in response to public concerns regarding methane emissions, many operators have recently voluntarily agreed to implementmethane controls with respect to their operations. State and existing 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 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 potential27effects of climate change have directed their attention at sources of funding for energy companies, which has resulted in certain financial institutions, funds,and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult foroperators on our properties to secure funding for exploration and production activities. Notwithstanding potential risks related to climate change, theInternational Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and gas will continueto represent a substantial percentage of global energy use over that time. Exploration and production activities are capital intensive, and capital constraintsof our operators could have a material adverse impact on production from our properties. Finally, it should be noted that some scientists have concluded thatincreasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequencyand 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 onour 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 has issued final regulations under the federal Clean Air Act governingperformance standards, including standards for the capture of air released during hydraulic fracturing; finalized effluent limitation guidelines in June 2016that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants; and issued in May 2014 anAdvanced Notice of Proposed Rulemaking (“ANPRM”) seeking comment on its intent to develop regulations under the Toxic Substances Control Act(“TSCA”) to require companies to disclose information regarding the chemicals used in hydraulic fracturing. However, no further action has been taken byEPA with respect to the TSCA ANPRM and additional federal regulation of hydraulic fracturing is uncertain at this time.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. These existing or any new legal requirements establishing seismic permitting requirements or similar restrictions on the construction oroperation of disposal wells for the injection of produced water likely will result in added costs to comply and affect our operators’ rate of production, whichin turn could have a material adverse effect on our results of operations and financial position. In addition to state laws, local land use restrictions, such ascity ordinances, may restrict or prohibit the performance of well drilling in general or hydraulic fracturing in particular. In the event state, local, or municipallegal restrictions are adopted in areas where our operators conduct operations, our operators may incur substantial costs to comply with these requirements,which may be significant in nature, experience delays, or curtailment in the pursuit of exploration, development, or production activities and perhaps even beprecluded from the drilling of wells.28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 mineral interests. This could cause our operators to incurincreased costs arising from species protection measures, delay the completion of exploration and production activities, and/or result in limitations onoperating 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.29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.The loss 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, 2017 2016 2015Exxon Mobil Corporation 20.8% 11.0% **Accounted for less than 10% of total revenues for the period indicated.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, 2017, Black StoneManagement had 113 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. 30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 preferred unitholders have priority with respect to rights to share in distributions over our common and subordinated unitholders forso long as our Series B cumulative convertible preferred units are outstanding. Furthermore, our partnership agreement does not require us to paydistributions to our common and subordinated unitholders on a quarterly basis or otherwise. The amount of cash to be distributed each quarter will bedetermined by the board of directors of our general partner.The amount of cash we have to distribute each quarter principally depends upon the amount of revenues we generate, which are largely dependent uponthe prices that our operators realize from the sale of oil and natural gas. The actual amount of cash we will have to distribute each quarter will be reduced byprincipal 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;31•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 31,2017 During the Five YearsPrior to 2018 As of December 31, High Low High1 Low2 2017 2016 2015WTI Light sweet crude oil ($/Bbl) $60.46 $42.48 $110.62 $26.19 $60.46 $53.75 $37.13Henry Hub spot market price of natural gas ($/MMBtu) $3.71 $2.44 $8.15 $1.49 $3.69 $3.71 $2.281 High prices for WTI and Henry Hub were in 2013 and 2014, respectively2 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. Oil prices are expected to remain depressed for the foreseeable future as compared to historical highs. Approximately 47.1% of our 2017 oil andnatural gas revenues were derived from oil and condensate sales. Any additional decreases in prices of oil may adversely affect our cash generatedfrom operations, results of operations, financial position, and our ability to pay the minimum quarterly distribution on all of our outstanding commonand subordinated units, perhaps materially.The spot WTI market price at Cushing, Oklahoma has declined from $98.17 per Bbl on December 31, 2013 to $60.46 per Bbl on December 31, 2017. Thereduction in price has been caused by many factors, including substantial increases in U.S. oil production from unconventional (shale) reservoirs, withlimited increases in demand. If prices for oil are depressed for an32extended period of time or there are future declines, we may be required to write down the value of our oil and natural gas properties in addition toimpairments taken during 2015 and 2016, and some of our undeveloped locations may no longer be economically viable. In addition, sustained low pricesfor oil may negatively impact the value of our estimated proved reserves and the amount that we are allowed to borrow under our bank credit facility andreduce the amounts of cash we would otherwise have available to pay expenses, fund capital expenditures, make distributions to our unitholders, and serviceour indebtedness.Natural gas prices are expected to remain depressed for the foreseeable future as compared to historical highs. Approximately 52.9% of our 2017 oiland natural gas revenues were derived from natural gas and natural gas liquids sales. Any future decreases in prices of natural gas may adverselyaffect our cash generated from operations, results of operations, financial position, and our ability to pay the minimum quarterly distribution on all ofour outstanding common and subordinated units, perhaps materially.During the ten years prior to 2018, natural gas prices at Henry Hub have ranged from a high of $13.31 per MMBtu in 2008 to a low of $1.49 per MMBtuin 2016. On December 31, 2017, the Henry Hub spot market price of natural gas was $3.69 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.33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 of the exploration, development, and production on the properties underlying our mineral androyalty interests and non-operated working interests. Substantially all of our revenue is derived from the sale of oil and natural gas production fromproducing wells in which we own a royalty interest or a non-operated working interest. A reduction in the expected number of wells to be drilled onour acreage by these operators or the failure of our operators to adequately and efficiently develop and operate our acreage could have an adverseeffect on our results of operations.Our assets consist of mineral and royalty interests and non-operated working interests. For the year ended December 31, 2017, 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 that will be 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.34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.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 working-interest participation program, and our operators’ development activities of our leases will require substantialcapital, and we and our operators may be unable to obtain needed capital or financing on satisfactory terms or at all.The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in connection with theacquisition of mineral and royalty interests and participation in our working-interest participation program. To date, we have financed capital expendituresprimarily with funding from cash generated by operations, limited borrowings under our credit facility, executed farmout agreements, and the issuance ofequity securities.In the future, we may restrict distributions to fund acquisitions and participation in our working interests but eventually we may need capital in excess 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.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.35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.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.36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, 2017, 2016, and 2015 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, 2017, 2016, and 2015 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, 2017, 2016, and 2015, 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.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.37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 all of the operations on our properties. Moreover, these lawsand regulations have generally imposed increasingly strict requirements related to water use and disposal, air pollution control, and waste management.Laws and regulations governing exploration and production may also affect production levels. Our operators must comply with federal and state 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.38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 final regulations under the federal Clean Air Act governing performance standards, including standards for the capture of air emissionsreleased during hydraulic fracturing; finalized effluent limitation guidelines in June 2016 to prohibit the discharge of wastewater from hydraulic fracturingoperations to publicly owned wastewater treatment plants; and issued in May 2014 an Advance Notice of Proposed Rulemaking ("ANPRM") seekingcomment on its intent to develop regulations under the Toxic Substances Control Act ("TSCA") to require companies to disclose information regarding thechemicals used in hydraulic fracturing. However, no further action has been taken by the EPA with respect to the TSCA ANPRM and additional federalregulation of hydraulic fracturing is uncertain at this time.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 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, including Colorado, North Dakota, Louisiana, Oklahoma, and Texas, where we own interests in oil and natural gas producing properties,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 RRC published a final rule in October 2014 governing permitting or re-permitting of disposalwells that require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, aswell as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit failsto demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates39such a disposal well is likely to be or determined to be contributing to seismic activity, then the RRC may deny, modify, suspend, or terminate the permitapplication or existing operating permit for that well. These existing or any new legal requirements establishing seismic permitting requirements or similarrestrictions on the construction or operation of disposal wells for the injection of produced water likely will result in added costs to comply and affect ouroperators’ rate of production, which in turn could have a material adverse effect on our results of operations and financial position. In addition to state laws,local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general or hydraulic fracturing in particular. Inthe event state, local, or municipal legal restrictions are adopted in areas where our operators conduct operations, our operators may incur substantial costs tocomply with these requirements, which may be significant in nature, experience delays, or curtailment in the pursuit of exploration, development, orproduction activities and perhaps even be precluded from the drilling of wells.There has been increasing public controversy regarding hydraulic fracturing with regard to increased risks of induced seismicity, the use of 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, declines in reserves, lending requirements, or regulations or certain other circumstances. As of December 31, 2017,we had outstanding borrowings of $388.0 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 2017 is $550.0 million and the next semi-annual redetermination is scheduled for April 2018.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 common units.We may not be able to obtain such financing or complete such transactions on terms acceptable to us or at all. Failure to make the required repayment couldresult in a default under our credit facility, which could materially adversely affect our business, financial condition, results of operations, and distributionsto our unitholders.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, 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.40Our credit facility restricts our ability to make distributions to unitholders or to repurchase units unless after giving effect to such distribution orrepurchase, there is no event of default under our credit facility and our outstanding borrowings are not in excess of our borrowing base. While we currentlyare not restricted by our credit facility from declaring a distribution, we may be restricted from paying a distribution in the future.We also are required to comply with certain financial covenants and ratios under the credit facility. Our ability to comply with these restrictions 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 GHGs present an endangerment to public health and the environment, theEPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, require preconstruction and operating permitsfor certain large stationary sources. Facilities required to obtain preconstruction permits for their GHG emissions also will be required to meet “best availablecontrol technology” standards that will be established on a case-by-case basis. These EPA rulemakings could adversely affect operations on our propertiesand restrict or delay the ability of our operators to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring themonitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in the United States on an annualbasis, which include gathering and boosting facilities as well as GHG emissions from completions and workovers of hydraulically fractured wells. Also, inJune 2016, the EPA finalized rules that establish new air emission controls for methane emissions from certain new, modified, or reconstructed equipment andprocesses in the oil and natural gas source category, including production, processing, transmission, and storage activities. However, in June 2017, the EPAproposed to stay the requirements for a period of two years and revisit implementation of the federal methane rules in their entirety. Several states, includingColorado, where we hold interests, have also adopted rules to control and minimize methane emissions from the production of oil and natural gas. Moreover,in response to public concerns regarding methane emissions, many operators have recently voluntarily agreed to implement methane controls with respect totheir operations. State and federal methane rules have substantial similarities with respect to pollution control equipment and leak detection and repair(“LDAR”) requirements. These rules could result in increased compliance costs for our operators and require them to make expenditures to purchase pollutioncontrol equipment and hire additional personnel to assist with complying with LDAR requirements, such as increased frequency of inspections and repairs forcertain processes and equipment. Consequently, these and other regulations related to controlling GHG emissions could have an adverse impact onproduction 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 emissionswould impact our business, any future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our operators’ equipmentand operations 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.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 physical41effects, such as increased frequency and severity of storms, floods, droughts, and other extreme climatic events; if any of these effects were to occur, theycould 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.Cyber attacks could significantly affect us.Cyber attacks on businesses have escalated in recent years. We rely on electronic systems and networks to control and manage our business and havemultiple layers of security to mitigate risks of cyber attack. If, however, we were to experience an attack and our security measures failed, the potentialconsequences to our businesses and the communities in which we operate could be significant. 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.42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 $1.25per common and subordinated unit on an annualized basis (or $0.3125 per unit on a quarterly basis) for the four quarters ending March 31, 2018. Theminimum quarterly distribution will be $1.35 per common and subordinated unit on an annualized basis (or $0.3375 per unit on a quarterly basis) for the fourquarters ending March 31, 2019. We expect that we will distribute a substantial majority of the cash we generate from operations each quarter. However, theboard of directors of our general partner could elect not to pay distributions for one or more quarters or at all. Please read Part II, Item 5. “Market forRegistrant’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. Any modification or revocation of our cash distributionpolicy could substantially reduce or eliminate the amounts of distributions to our unitholders. The amount of distributions we make, if any, and the decisionto make any distribution at all will be determined by the board of directors of our general partner. If we make distributions, our Series B cumulativeconvertible preferred unitholders have priority with respect to rights to share in those distributions over our common and subordinated unitholders for solong as our Series B cumulative convertible preferred units are outstanding. Please read Part II, Item 5. “Market for Registrant’s Common Equity, RelatedUnitholder Matters, and Issuer Purchases of Equity Securities — Cash Distribution Policy — Series B Cumulative Convertible Preferred Units.”Our minimum quarterly distribution provides the common unitholders a specified priority right to distributions over the subordinated unitholders if 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.43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.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;•entry into 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.44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 of 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 our affiliates for common units during the 90-day period preceding the date such notice is first mailed. This limited callright is not exercisable as long as any of our Series B cumulative convertible preferred units are outstanding, or at any time after the subordination period hasended.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 preferred units. Our issuance of additional common units or other equity interests ofequal 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 preferred units with respect to rights to share in distributions, redemption obligations, or redemption rights without Series Bcumulative convertible preferred unitholder approval.45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, 2017, we had 103,455,864 common units and 95,388,424 subordinated units outstanding. All of the subordinated units couldconvert into common units on no more than a one-to-one basis at the end of the subordination period. Sales by holders of a substantial number of ourcommon units in the public markets, or the perception that these sales might occur, could have a material adverse effect on the price of our common units orimpair our ability to obtain capital through an offering of equity securities.The price of our common units may fluctuate significantly, and unitholders could lose all or part of their investment.The market price of our common units may be influenced by many factors, some of which are beyond our control, including those described elsewhere 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.46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. 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’, federal income tax status does not have or is not reasonably likely to have a material adverse effect on the rates chargeable by us to customers and(b) whose ownership could not result in our loss of ownership in any material part of our assets, as determined by our general partner with the advice ofcounsel. If an investor is not an Eligible Holder, in certain circumstances as set forth in our partnership agreement, units by such investor may be redeemed byus at the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.Tax Risks to Common UnitholdersOur tax treatment depends on our status as a partnership for federal income tax purposes, and not being subject to a material amount of entity-leveltaxation. If the Internal Revenue Service (“IRS”) were to treat us as a corporation for federal income tax purposes or we were to become subject toentity-level taxation for state tax purposes, then our cash distributions to unitholders could be substantially reduced.The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for 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 federal income tax purposesunless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. However,we have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us. Failing to meet the qualifying incomerequirement or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as anentity.If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate.Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, or deductions would flow through toour unitholders. Because a tax would be imposed upon us as a corporation, cash distributions to our unitholders would be substantially reduced. In addition,changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and otherreasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, and other formsof taxation. Imposition of any of those taxes may substantially reduce the cash distributions to our unitholders. Therefore, treatment of us as a corporation orthe assessment of a material amount of entity-level taxation would result in a material reduction in the anticipated cash generated from operations and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.47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 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 federal income tax laws that affect publicly traded partnerships. Although there is no current legislative proposal, a priorlegislative proposal would have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon whichwe rely for our treatment as a partnership for federal income tax purposes.In addition, on January 24, 2017, final regulations regarding which activities give rise to qualifying income within the meaning of Section 7704 of theCode (the “Final Regulations”) were published in the Federal Register. The Final Regulations apply to taxable years beginning on or after January 19, 2017and generally treat income from passive mineral interests (such as royalty income) as qualifying income. However, there can be no assurance that there willnot be further changes to the Treasury Department's interpretation of the qualifying income rules in a manner that could impact our ability to qualify as apartnership in the future.Any modification to the federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exceptionfor certain publicly traded partnerships to be treated as partnerships for federal income tax purposes. We are unable to predict whether any of these changes orother proposals will ultimately be enacted or adopted. Any such changes could negatively impact the value of an investment in our common units. You areurged to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potential effect onyour investment in our common units.Future legislation may result in the elimination of certain U.S. federal income tax deductions currently available with respect to oil and natural 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 U.S. tax laws, including to certain key U.S.federal income tax provisions currently available to oil and gas companies. Such legislative changes have included, but not been limited to, (i) the repeal ofthe percentage depletion allowance for oil and natural gas properties; (ii) the elimination of current deductions for intangible drilling and development costs;and (iii) an extension of the amortization period for certain geological and geophysical expenditures. Congress could consider, and could include, some orall of these proposals as part of tax reform legislation, to accompany lower 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 with respect to oil and gas development, or increase costs, and any such changes could have an adverse effect on the Company’sfinancial position, results of operations and cash flows.If the IRS were to contest the federal income tax positions we take, it may adversely affect the market for our common units, and the costs of any suchcontest would reduce cash available for distribution to our unitholders.We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affectingus. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some orall of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely affect themarket for our common units and the price at which they trade. Moreover, the costs of any contest between us and the IRS will result in a reduction in cashavailable for distribution to our unitholders and thus will be borne indirectly by our unitholders.48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 our cashavailable for distribution to our unitholders might be substantially reduced and our current and former unitholders may be required to indemnify usfor any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders' behalf.Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income taxreturns, 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 Schedule K-1 to each unitholder with respect to an audited and adjusted return. Although our generalpartner may elect to have our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit,there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current unitholders may bear someor all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result ofany such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might besubstantially reduced and our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest)resulting from such audit adjustments that were paid on such unitholders' behalf. These rules are not applicable for tax years beginning on or prior toDecember 31, 2017.Even if you, as a unitholder, do not receive any cash distributions from us, you will be required to pay taxes on your share of our taxable income.You will be required to pay federal income taxes and, in some cases, state and local income taxes, on your share of our taxable income, whether or notyou 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, such as debt exchanges, debt repurchases, or modifications of our existing debt could result in “cancellation ofindebtedness income” being allocated to our unitholders as taxable income without any increase in our cash available for distribution. You may not receivecash distributions from us equal to your share of our taxable income or even equal to the actual tax due from you with respect to that income.Tax gain or loss on disposition of our common units could be more or less than expected.If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those 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 units you sell will, in effect, become taxable income to you if you sell your units at a price greater than your taxbasis in those units, even if the price you receive is less than your original cost. In addition, because the amount realized includes a unitholder’s share of ournonrecourse liabilities, if you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale.A substantial portion of the amount realized from the sale of your units, whether or not representing gain, may be taxed as ordinary income to you due topotential recapture items, including depreciation recapture. Thus, you may recognize both ordinary income and capital loss from the sale of your units if theamount realized on a sale of your units is less than your adjusted basis in the units. Net capital loss may only offset capital gains and, in the case ofindividuals, up to $3,000 of ordinary income per year. In the taxable period in which you sell your units, you may recognize ordinary income from ourallocations of income and gain to you prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the saleof 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, will be unrelated business taxable income and will be taxable to them. Further, with respect to taxable years beginning after December 31,2017, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours that isengaged in one or more unrelated trade or business) is required to compute the unrelated business taxable income of such tax-49exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, foryears beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offsetunrelated business taxable income from another unrelated trade or business and vice versa. Tax-exempt entities should consult a tax advisor before investingin our common units.Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our units.Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S.trade or business (“effectively connected income”). Income allocated to our unitholders and any gain from the sale of our units will generally be consideredto be “effectively connected” with a U.S. trade or business. As a result, distributions to a non-U.S. unitholder will be subject to withholding at the highestapplicable effective tax rate and a non-U.S. unitholder who sells or otherwise disposes of a unit will also be subject to U.S. federal income tax on the gainrealized from the sale or disposition of that unit.The Tax Cuts and Jobs Act imposes a withholding obligation of 10% of the amount realized upon a non-U.S. unitholder’s sale or exchange of an interestin a partnership that is engaged in a U.S. trade or business. However, due to challenges of administering a withholding obligation applicable to open markettrading and other complications, the IRS has temporarily suspended the application of this withholding rule to open market transfers of interest in publiclytraded partnerships pending promulgation of regulations or other guidance that resolves the challenges. It is not clear if or when such regulations or otherguidance will be issued. Non-U.S. unitholders should consult a tax advisor before investing in our common units.We treat each purchaser of common units as having the same tax benefits without regard to the common units actually purchased. The IRS 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 unit is transferred. The IRS maychallenge this treatment, which could change the allocation of items of income, gain, loss, and deduction among our unitholders.We generally prorate our items of income, gain, loss, and deduction between transferors and transferees of our units each month based upon theownership of our units on the first day of each month (the “Allocation Date”), instead of on the basis of the date a particular unit is transferred. Similarly, wegenerally allocate certain deductions for depreciation of capital additions, gain or loss realized on a sale or other disposition of our assets and, in thediscretion of the general partner, any other extraordinary item of income, gain, loss, or deduction based upon ownership on the Allocation Date. TreasuryRegulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRSwere to challenge our proration method, we may be required to change the allocation of items of income, gain, loss, and deduction among our unitholders.A unitholder whose units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of units) may be considered to havedisposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan andcould recognize gain or loss from the disposition.Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a unitholder whose units are thesubject of a securities loan may be considered to have disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as apartner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from this disposition.Moreover, during the period of the loan, any of our income, gain, loss, or deduction with respect to those units may not be reportable by the unitholder andany cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status aspartners and avoid the risk of gain recognition from a securities loan are urged to modify any applicable brokerage account agreements to prohibit theirbrokers from borrowing their units.50You, as a unitholder, may be subject to state and local taxes and return filing requirements in states where you do not live as a result of investing inour common units.In addition to federal income taxes, you likely will be subject to other taxes, including state and local taxes, unincorporated business taxes and estate,inheritance, or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if youdo not live in any of those jurisdictions. We will initially own assets and conduct business in several states, many of which impose a personal income tax andalso impose income taxes on corporations and other entities. You may be required to file state and local income tax returns and pay state and local incometaxes in these jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. As we make acquisitions or expand ourbusiness, we may own assets or conduct business in additional states or foreign jurisdictions that impose a personal income tax. It is your responsibility to fileall U.S. federal, foreign, state, and local tax returns.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.51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.” Our common units began trading on the NYSE on May 1, 2015 at an initial publicoffering price of $19.00 per common unit. The following table sets forth the daily high and low sales price for our common units as reported by the NYSE, aswell 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 Unit2016 First Quarter $15.76 $10.71 $0.2625 $0.18375Second Quarter $17.15 $13.61 $0.2875 $0.18375Third Quarter $19.65 $14.71 $0.2875 $0.18375Fourth Quarter $19.86 $16.94 $0.2875 $0.18375 2017 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 $0.208751 Represents cash distributions attributable to the quarter. Cash distributions declared in respect of a quarter are paid in the following quarter.As of February 20, 2018, there were 104,258,290 common units outstanding held by 494 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 20, 2018, we also had outstanding 95,388,424 subordinated units, 24,803 Series A redeemable preferred units, and 14,711,219 Series Bcumulative convertible preferred units. All Series A redeemable preferred units not redeemed by March 31, 2018 automatically convert to common andsubordinated units effective as of January 1, 2018 or as soon as practicable thereafter. There is no established public market in which the subordinated unitsor the preferred units are traded.52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, 2017 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 April 30, 2015 As of December 31, 2015 2016 2017Black Stone Minerals, L.P. $100.00 $78.22 $109.07 $110.89S&P 500 Index 100.00 99.47 111.37 135.69Alerian MLP Index 100.00 66.99 79.25 74.08The 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.53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 December 14, 2017, we closed on the purchase of certain mineral interests using 7,338 common units valued at $0.1 million to fund the purchaseprice.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 Rule 506(c) of Regulation D thereunder. The investors are "accredited investors" (as defined in Regulation D), the investors acquired the commonunits for investment purposes only and not for resale, and we took appropriate measures to restrict the transfer of the common units issued and verify theaccredited investor status of the investors.Purchases of Equity Securities by the Issuer and Affiliated PurchasersThe following tables set forth our purchases of our common and subordinated units for each month during the three months ended December 31, 2017:Purchases of Common UnitsPeriod Total Number of Common UnitsPurchased Average PricePaid Per Unit Total Number of Common UnitsPurchased as Part of PubliclyAnnounced Plans or Programs Maximum Dollar Value ofCommon Units That May Yet BePurchased Under the Plans orProgramsDecember 1 – December 31, 2017 18,9991 $17.93 — $— Purchases of Subordinated UnitsPeriod Total Number of SubordinatedUnits Purchased Average PricePaid Per Unit Total Number of Common UnitsPurchased as Part of PubliclyAnnounced Plans or Programs Maximum Dollar Value ofCommon Units That May Yet BePurchased Under the Plans orProgramsDecember 1 – December 31, 2017 — $— — $—1 Includes units withheld to satisfy tax withholding obligations upon the vesting of certain restricted common units held by our executive officers andcertain other employees.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.54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 applicable minimum quarterly distribution forthe periods specified below is as follows: Minimum Quarterly Distribution (per unit)Four Quarters Ending March 31, Per Quarter Annualized2018 0.3125 1.252019 and thereafter 0.3375 1.35After March 31, 2019, the minimum quarterly distribution shall be the same as it is for each of the four quarters ending March 31, 2019. The minimumquarterly distribution does not provide the common unitholders the right to require payment of any distributions. It merely reflects the specified priority rightof 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 preferred units to distributions, please read "Series A Redeemable Preferred Units"and "Series B Cumulative Convertible Preferred Units" below.Replacement capital expenditures are expenditures necessary to replace our existing oil and natural gas reserves or otherwise maintain our asset 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.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.55•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. Our partnership agreement does not limit the amount of cash reserves thatour general partner may establish. Any decision to establish cash reserves made by our general partner will be binding on our unitholders.•Under Section 17-607 of the Delaware Act, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of 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 UnitsThe limited partners of BSM’s Predecessor own all of our subordinated units. The principal difference between our common and subordinated units isthat, for any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution until the holders of thecommon units have received the applicable minimum quarterly distribution for such quarter plus any arrearages in the payment of the minimum quarterlydistribution from prior quarters. Subordinated units will not accrue arrearages. Our common unitholders are only entitled to arrearages in the payment of theminimum quarterly distribution from prior quarters during the subordination period. To the extent we have cash generated from operations available fordistribution in any quarter during the subordination period in excess of the amount necessary to pay the applicable minimum quarterly distribution toholders of our common units, we will use this excess cash to pay any distribution arrearages on the common units related to prior quarters before any cashdistribution 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.56Series A Redeemable Preferred UnitsUntil March 31, 2018, the holders of our outstanding Series A redeemable preferred units have 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 shall automatically convert to common and subordinated units effective as of January 1, 2018 or as soon as practicablethereafter. Therefore, as of the date of this report, the holders of our outstanding Series A redeemable preferred units do not have the right to receive any futuredistributions on their units.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.57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, 2017 2016 2015 2014 2013 (in thousands, except per unit amounts)Total revenue $429,659 $260,833 $392,924 $548,321 $463,559Net income (loss) 157,153 20,188 (101,305) 169,187 168,963Net income (loss) attributable to the general partner andcommon units and subordinated units subsequent to initialpublic offering 152,145 14,437 (108,017) * *Net income (loss) attributable to limited partners per commonand subordinated unit (basic)1 Per common unit (basic) 1.01 0.26 (0.56) * *Per subordinated unit (basic) 0.56 (0.11) (0.56) * *Net income (loss) attributable to limited partners per commonand subordinated unit (diluted)1 Per common unit (diluted) 1.01 0.26 (0.56) * *Per subordinated unit (diluted) 0.56 (0.11) (0.56) * *Cash distributions declared per common and subordinated unit Per common unit 1.20 1.10 0.42 * *Per subordinated unit 0.79 0.74 0.42 * *Total assets2 1,576,451 1,128,827 1,061,436 1,326,782 1,444,413Long-term debt 388,000 316,000 66,000 394,000 451,000Total mezzanine equity 322,422 54,015 79,162 161,165 161,392*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, $117.9 million, and $57.1 million, forthe years ended December 31, 2016, 2015, 2014, and 2013, respectively. We did not have impairments of oil and natural gas properties for the year endedDecember 31, 2017.58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 of oil and natural gas mineral interests in the United States. Our principal business is maximizing the value of ourexisting portfolio of mineral and royalty assets through active management and expanding our asset base through acquisitions of additional mineral androyalty interests. We maximize value through the marketing of our mineral assets for lease, creative structuring of those leases to encourage and acceleratedrilling activity, and selectively participating alongside our lessees on a working-interest basis. Our primary business objective is to grow our reserves,production, and cash generated from operations over the long term, while paying, to the extent practicable, a quarterly distribution to our unitholders.On May 6, 2015, we completed our initial public offering of 22,500,000 common units representing limited partner interests. Our common units trade onthe New York Stock Exchange under the symbol "BSM."Our mineral and royalty interests consist of mineral interests in approximately 16.8 million acres, with an average 43.4% ownership interest in thatacreage, NPRIs in 1.9 million acres, and ORRIs in 2.1 million acres. These non-cost-bearing interests include ownership in over 55,728 producing wells. Wealso own non-operated working interests, a significant portion of which are on positions where we also have a mineral and royalty interest. We recognize oiland natural gas revenue from our mineral and royalty and non-operated working interests in producing wells when the oil and natural gas production from theassociated acreage is sold. Our other sources of revenue include mineral lease bonus and delay rentals, which are recognized as revenue according to theterms of the lease agreements.Recent Developments2017 AcquisitionsOn November 28, 2017, we closed on the acquisition of (i) certain mineral interests and other non-cost bearing royalty interests from Noble Energy Inc.,Noble Energy Wyco, LLC, and Rosetta Resources Operating LP, and (ii) one hundred percent (100%) of the issued and outstanding securities of SamedanRoyalty, LLC ("Samedan") from Noble Energy US Holdings, LLC, collectively, the "Noble Acquisition." The mineral interests and other non-cost bearingroyalty interests acquired in the Noble Acquisition, including interests owned by Samedan, include approximately 1.1 million gross (140,000 net) mineralacres, 380,000 gross acres of non-participating royalty interests, and 600,000 gross acres of overriding royalty interests collectively spread over 20 states withsignificant concentrations in Texas, Oklahoma, and North Dakota. We funded the cash purchase price of the Noble Acquisition of $335 million, beforecustomary post-closing adjustments, with the proceeds from the issuance of $300 million of Series B cumulative convertible preferred units and $35 millionof cash from borrowings on our credit facility. See "Recent Developments — Series B Cumulative Convertible Preferred Units" below for additionalinformation about our Series B cumulative convertible preferred units.Throughout 2017, we also closed numerous acquisitions consisting of various mineral and royalty interests in several Texas counties. We acquiredmineral and royalty interests in East Texas prospective for the Haynesville and Bossier shales for a total of $4.8 million in cash and $45.7 million in ourcommon units through acquisitions of assets previously owned by Angelina County Lumber Company. We also acquired mineral and royalty interests in theDelaware Basin for $30.8 million in cash and $12.0 million in common units, as well as additional mineral and royalty interests in East Texas for $55.3million in cash and $14.0 million in our common units, and mineral and royalty interests in the Anadarko Basin for $0.4 million in cash.59Put Option Related to Noble AcquisitionBy acquiring 100% of the issued and outstanding securities of Samedan, now NAMP Holdings, LLC, we acquired a 100% interest in Comin-Termin,LLC, now NAMP GP, LLC ("Holdings"), Comin 1989 Partnership LLLP, now NAMP 1, LP ("Comin"), and Temin 1987 Partnership LLLP, now NAMP 2, LP("Temin"). Pursuant to certain co-ownership agreements, various co-owners hold undivided beneficial ownership interests in 47.34% and 44.39% of theminerals interests held of record by Holdings and Temin, respectively. Based on the terms of the co-ownership agreements, the co-owners each have anunconditional option to require Comin or Temin, as applicable, to purchase their beneficial ownership interest in the mineral interests held of record byHoldings or Temin, as applicable, at any time within 30 days of receiving such repurchase notice. The purchase price of the beneficial ownership interestshall be based on an evaluation performed by Comin or Temin, as applicable, in good faith. As of December 31, 2017, we had not received notice from anyco-owner to exercise their repurchase option, and as such, no liability was recorded.Farmout AgreementsOn February 21, 2017, we announced that we entered into a farmout agreement with Canaan, which covers certain Haynesville and Bossier shale acreagein San Augustine County, Texas operated by XTO Energy Inc., a subsidiary of Exxon Mobil Corporation. We have an approximate 50% working interest inthe acreage. A total of 18 wells are anticipated to be drilled over an initial phase, beginning with wells spud after January 1, 2017. As of December 31, 2017,10 wells have been drilled during the initial phase. At its option, Canaan may participate in two additional phases with each phase continuing for the lesserof 2 years or until 20 wells have been drilled. During the first three phases of the agreement, Canaan will commit on a phase-by-phase basis and fund 80% ofour drilling and completion costs and will be assigned 80% of our working interests in such wells (40% working interest on an 8/8ths basis). After the thirdphase, Canaan can earn 40% of our working interest (20% working interest on an 8/8ths basis) in additional wells drilled in the area by continuing to fund40% of our costs for those wells on a well-by-well basis. We will receive a base ORRI before payout and an additional ORRI after payout on all wells drilledunder the agreement. The Canaan Farmout is anticipated to reduce our future capital expenditures by approximately $40 to $50 million annually during theterm of the agreement.On November 21, 2017, we entered into a farmout agreement with Pivotal that covers substantially all of our remaining working interests under activedevelopment in the Shelby Trough area of East Texas targeting the Haynesville and Bossier shale acreage after giving effect to the Canaan Farmout(discussed above) over the next eight years. In wells operated by XTO Energy Inc. in San Augustine County, Texas, Pivotal will earn our remainingapproximate 20% working interest (10% working interest on an 8/8ths basis) not covered by the Canaan Farmout, as well as 100% of our working interests(ranging from approximately 12.5% to 25% on an 8/8th basis) in wells operated by our other major operator in the area. Initially, Pivotal will be obligated tofund the development of up to 80 wells across several development areas and then will have options to continue funding our working interest across thoseareas for the duration of the eight year term. After the funding of a designated group of wells by Pivotal and once Pivotal achieves a specified payout for suchwell group, the Partnership will obtain a majority of the original working interest in the designated group of wells.As a result of the farmout agreements with Canaan and Pivotal, we expect capital requirements associated with non-operated working interests to beminimal beyond the first quarter of 2018.At-the-Market Offering ProgramIn the second quarter of 2017, we commenced an at-the-market offering (the “ATM Program”) program and in connection therewith entered into anEquity Distribution Agreement. The ATM Program permits us from time to time through our Sales Agents to sell our common units having an aggregateoffering price of up to $100,000,000. We intend to use the net proceeds from any sales pursuant to the ATM Program, after deducting commissions andoffering expenses, for general partnership purposes, which may include, among other things, repayment of indebtedness outstanding under our credit facility.Common units to be sold pursuant to the Equity Distribution Agreement will be offered and sold pursuant to our existing effective shelf-registrationstatement on Form S-3 (File No. 333-215857), which was declared effective by the Securities and Exchange Commission on February 8, 2017. Proceeds, netof commissions and expenses, of these sales through December 31, 2017 amounted to $32.5 million. See Note 15 – At-the-Market Offering Program to ourconsolidated financial statements included herein for further discussion.60Series B Cumulative Convertible Preferred UnitsOn November 22, 2017, we entered into a purchase agreement with Mineral Royalties One, L.L.C., a Delaware limited liability company and affiliate ofThe Carlyle Group ("Carlyle"), pursuant to which, on November 28, 2017, we issued and sold in a private placement 14,711,219 Series B cumulativeconvertible preferred units representing limited partner interests in us to Carlyle for a cash purchase price of $20.3926 per Series B cumulative convertiblepreferred unit (the “Issue Price”), resulting in proceeds to us of approximately $300 million. Proceeds from the private placement were used to partially fundthe Noble Acquisition.The holders of the Series B cumulative convertible preferred units will receive cumulative quarterly distributions in an amount equal to 7% per annum,subject to certain adjustments. Each holder may elect to convert all or any portion of its Series B cumulative convertible preferred units into common unitson a one-for-one basis, subject to customary anti-dilution adjustments and an adjustment for any distributions that have accrued but not been paid when due,at any time after the second anniversary of November 28, 2017. Under certain conditions, we may elect to convert all or any portion of the Series Bcumulative convertible preferred units into common units at any time after the second anniversary of November 28, 2017. We may also may elect to redeemthe Series B cumulative convertible preferred units at any time during the 90-day period beginning on the sixth anniversary of November 28, 2017 at aredemption price equal to 105% of the Issue Price plus any accrued and unpaid distributions on the applicable Series B cumulative convertible preferredunits, and at any time during the 90-day period beginning on each Readjustment Date at a redemption price payable wholly in cash equal to the Issue Priceplus any accrued and unpaid distributions on the applicable Series B cumulative convertible preferred units.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 $58.00 per Bbl in both 2018 and 2019. During the year ended December 31, 2017, the WTI oil spot price reached a low of $42.48 perBbl on June 21, 2017 but rebounded to a high of $60.46 per Bbl on December 29, 2017.The EIA forecasts that the Henry Hub spot natural gas price will average $3.20 per MMBtu for 2018 and $3.08 per MMBtu for 2019. During the yearended December 31, 2017, Henry Hub spot natural gas prices ranged from a high of $3.71 per MMBtu on January 2, 2017 to a low of $2.44 per MMBtu onFebruary 27, 2017.To manage the variability in cash flows associated with the projected sale of our oil and natural gas production, we use various derivative instruments,which have recently consisted of fixed-price swap contracts.The following table reflects commodity prices at the end of each quarter presented: 2017Benchmark Prices Fourth Quarter Third Quarter Second Quarter First QuarterWTI spot oil ($/Bbl)1 $60.46 $48.18 $46.02 $50.54Henry Hub spot natural gas ($/MMBtu)1 $3.69 $2.95 $2.98 $3.131 Source: EIARig CountAs we are the operator of record on only three properties, drilling on our acreage is dependent upon the exploration and production companies that leaseour acreage. In addition to drilling plans that we seek from our operators, we also monitor rig counts in an effort to identify existing and future leasing anddrilling activity on our acreage.61The following table shows the rig count at the close of each quarter presented: 2017U.S. Rotary Rig Count1 Fourth Quarter Third Quarter Second Quarter First QuarterOil 747 750 756 662Natural gas 182 189 184 160Other — 1 — 2Total 929 940 940 824 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. Despite anticipated risingproduction, the EIA forecasts that inventories will conclude the withdrawal season, which is the end of March 2018, at 1,429 Bcf, or 17% below the five-yearaverage. The EIA expects inventories to build slightly over the five-year average to a projected 3,861 Bcf at the end of October 2018; in 2019, inventories areexpected to be about 6% lower on average than 2018 levels.The following table shows natural gas storage volumes by region at the close of each quarter presented: 2017Region1 Fourth Quarter Third Quarter Second Quarter First Quarter (Bcf)East 740 861 564 268Midwest 875 989 699 479Mountain 183 220 187 142Pacific 268 311 287 216South Central 1,060 1,127 1,151 946Total 3,126 3,508 2,888 2,0511 Source: EIA62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 hedges; and•Adjusted EBITDA, distributable cash flow, and distributable cash flow after net working interest capital expenditures.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 thatcomprise 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 of 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 crude oil plays an important role in its refining and subsequent sale as petroleum products. As a result, variations inchemical composition relative to the benchmark crude oil, usually WTI, will result in price adjustments, which are often referred to as qualitydifferentials. The characteristics that most significantly affect quality differentials include the density of the oil, as characterized by its API gravity,and the presence and concentration of impurities, such as sulfur.Location differentials generally result from transportation costs based on the produced oil’s proximity to consuming and refining markets and 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 price thannatural gas which is predominantly methane, which has a lower Btu value. Natural gas with a higher concentration of impurities will realize a lowervolumetric price due to the presence of the impurities in the natural gas when sold or the cost of treating the natural gas to meet pipeline qualityspecifications.Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply and demand conditions andthe cost to transport natural gas to end user markets.63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. Since 2015, we have only entered into fixed-price swap contracts.Under fixed-price swap contracts, a counterparty is required to make a payment to us if the settlement price is less than the swap strike price. Conversely, weare required to make a payment to the counterparty if the settlement price is greater than the swap strike price. We may employ contractual arrangementsother than fixed-price swap contracts in the future to mitigate the impact of price fluctuations. If commodity prices decline in the future, our hedgingcontracts will partially mitigate the effect of lower prices on our future revenue.Our open oil and natural gas derivative contracts as of December 31, 2017, and as of the date of this filing, are detailed in Note 5 – CommodityDerivative Financial Instruments to our consolidated financial statements included elsewhere in this Annual Report. Prior to amending and restating ourcredit agreement on November 1, 2017, we were allowed to hedge all of our estimated production from our proved developed producing reserves based onthe most recent reserve information provided to our lenders.Pursuant to our Fourth Amended and Restated Credit Agreement, we are allowed to hedge certain percentages of expected future monthly productionvolumes equal to the lesser of (i) internally forecasted production and (ii) the average of reported production for the most recent three months. We are allowedto 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. Pursuant to our updatedhedge provisions, we have hedged 85.5% and 19.9% of our available oil and condensate hedge volumes for 2018 and 2019, respectively. Also, we havehedged 98.8% and 27.7% of our available natural gas hedge volumes for 2018 and 2019, respectively. 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 to remain significantly hedged for the following 12 to 24 months. We do not enter into derivative instrumentsfor speculative purposes.Non-GAAP Financial MeasuresAdjusted EBITDA, distributable cash flow, and distributable cash flow after net working interest capital expenditures are supplemental non-GAAPfinancial measures used by our management and external users of our financial statements such as investors, research analysts, and others, to assess thefinancial performance of our assets and our ability to sustain distributions over the long term without regard to financing methods, capital structure, orhistorical 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. We definedistributable cash flow after net working interest capital expenditures as distributable cash flow less net working interest capital expenditures. Net workinginterest capital expenditures consists of all capital expenditures related to working interest wells less the recoupment of working interest expenditures underour farmout agreements.Adjusted EBITDA, distributable cash flow, and distributable cash flow after net working interest capital expenditures should not be considered analternative to, or more meaningful than, net income (loss), income (loss) from operations, cash flows from operating activities, or any other measure offinancial performance presented in accordance with generally accepted accounting principles (“GAAP”) in the United States as measures of our financialperformance.Adjusted EBITDA, distributable cash flow, and distributable cash flow after net working interest capital expenditures have important limitations asanalytical tools because they exclude some but not all items that affect net income (loss), the most directly comparable GAAP financial measure. Ourcomputation of Adjusted EBITDA, distributable cash flow, and distributable cash flow after net working interest capital expenditures may differ fromcomputations of similarly titled measures of other companies.64The following table presents a reconciliation of Adjusted EBITDA, distributable cash flow, and distributable cash flow after net working interest capitalexpenditures to net income (loss), the most directly comparable GAAP financial measure, for the periods indicated. Year Ended December 31, 2017 2016 2015 (in thousands)Net income (loss) $157,153 $20,188 $(101,305)Adjustments to reconcile to Adjusted EBITDA: Depreciation, depletion and amortization 114,534 102,487 104,298Interest expense 15,694 7,547 6,418Impairment of oil and natural gas properties — 6,775 249,569Accretion of asset retirement obligations 1,026 892 1,075Equity-based compensation1 33,045 43,138 18,000Unrealized (gain) loss on commodity derivative instruments (11,691) 81,253 (27,063)Adjusted EBITDA 309,761 262,280 250,992Adjustments to distributable cash flow: Restructuring charges — — 4,208Incremental general and administrative related to initial public offering — — 1,303Deferred revenue (2,086) (870) (660)Cash interest expense (14,817) (6,676) (5,483)(Gain) loss on sales of assets, net (931) (4,793) (4,873)Estimated replacement capital expenditures2 (13,500) (11,250) —Cash paid to noncontrolling interests (120) (111) (208)Preferred unit distributions (5,042) (5,763) (11,562)Distributable cash flow 273,265 232,817 233,717Net working interest capital expenditures $(39,477) (80,179) (54,244)Distributable cash flow after net working interest capital expenditures $233,788 $152,638 $179,4731 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.Factors Affecting the Comparability of Our Financial ResultsOur historical financial condition and results of operations for the periods presented may not be comparable, either from period to period or goingforward, because we will incur higher general and administrative expenses than in prior periods as a result of operating as a publicly traded partnership. Theseincremental expenses include costs associated with SEC reporting requirements, including annual and quarterly reports to unitholders; tax return andSchedule K-1 preparation and distribution fees; Sarbanes-Oxley Act compliance; New York Stock Exchange listing fees; independent registered publicaccounting firm fees; legal fees, investor-relations activities, registrar and transfer agent fees; director and officer insurance; and additional compensation.These direct, incremental general and administrative expenses are not included in our historical results of operations for periods prior to our IPO.65Results of OperationsYear 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 %Gain (loss) on commodity derivative instruments 26,902 (36,464) 63,366 (173.8)%Lease bonus and other income 42,062 32,079 9,983 31.1 %Total revenue $429,659 $260,833 $168,826 64.7 %Realized prices, without derivatives: Oil and condensate ($/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 %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.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 83.1% and 77.3% of total oil and condensate volumes for theyears ended 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 production66accounted for 51.3% and 59.3% of our natural gas and NGL volumes for the years ended December 31, 2017 and 2016, respectively. 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 expenses. Lease operating expense includes normally recurring expenses associated with our non-operated working interests necessaryto produce hydrocarbons from our oil and natural gas wells, as well as certain nonrecurring expenses, such as well repairs. Lease operating expense decreasedfor the 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 2016.67Year Ended December 31, 2016 Compared to Year Ended December 31, 2015The following table shows our production, revenue, and operating expenses for the periods presented: Year Ended December 31, 2016 2015 Variance (dollars in thousands, except for realized prices and per BOE data)Production: Oil and condensate (MBbls) 3,680 3,565 115 3.2 %Natural gas (MMcf)1 47,498 41,389 6,109 14.8 %Equivalents (MBoe) 11,596 10,463 $1,133 10.8 %Revenue: Oil and condensate sales $142,382 $163,538 $(21,156) (12.9)%Natural gas and natural gas liquids sales1 122,836 116,018 6,818 5.9 %Gain (loss) on commodity derivative instruments (36,464) 90,288 (126,752) (140.4)%Lease bonus and other income 32,079 23,080 8,999 39.0 %Total revenue $260,833 $392,924 $(132,091) (33.6)%Realized prices: Oil and condensate ($/Bbl) $38.69 $45.87 $(7.18) (15.7)%Natural gas ($/Mcf)1 $2.59 $2.80 $(0.21) (7.5)%Equivalents ($/Boe) $22.87 $26.72 $(3.85) (14.4)%Operating expenses: Lease operating expense $18,755 $21,583 $(2,828) (13.1)%Production costs and ad valorem taxes 35,464 35,767 (303) (0.8)%Exploration expense 645 2,592 (1,947) (75.1)%Depreciation, depletion, and amortization 102,487 104,298 (1,811) (1.7)%Impairment of oil and natural gas properties 6,775 249,569 (242,794) (97.3)%General and administrative 73,139 77,175 (4,036) (5.2)%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.RevenueThe $132.1 million decrease in total revenue for the year ended December 31, 2016 compared to the year ended December 31, 2015 was due to $126.8million of losses attributable to commodity derivative instruments and $36.7 million lower realized commodity prices, partially offset by $22.4 millionrelated to higher oil and condensate and natural gas and NGL volumes and $9.0 million in additional lease bonus and other income.Oil and condensate sales. Oil and condensate sales during 2016 were lower than the corresponding period in 2015 primarily due to a steep decline inrealized prices. Our mineral-and-royalty-interest oil volumes accounted for 77.3% and 76.8% of total oil and condensate volumes for the years endedDecember 31, 2016 and 2015, respectively. Our oil and condensate volumes increased in 2016 relative to 2015 primarily driven by production increases fromnew wells in the Bakken/Three Forks, Wilcox, and Wolfcamp plays.Natural gas and natural gas liquids sales. Natural gas and NGL sales increased for the year ended December 31, 2016 as compared to 2015. During2016, increases in production from our Haynesville and Wilcox properties served to more than mitigate the impact of further depressed realized natural gasand NGL prices. Mineral-and-royalty-interest production made up 59.3% and 67.3% of our natural gas and NGL volumes for the years ended December 31,2016 and 2015, respectively. 68Gain (loss) on commodity derivative instruments. In 2016, we recognized $16.0 million of net losses from oil commodity contracts, which included$27.5 million of realized gains, compared to $57.7 million of combined gains in 2015, of which $41.8 million were realized. In 2016, we recognized $20.5million of net losses from natural gas commodity contracts, which included $17.3 million of realized gains, compared to $32.6 million of combined gains in2015, of which $21.4 million were realized gains.Lease bonus and other income. Lease bonus and delay rental revenue increased for the year ended December 31, 2016, as compared to 2015. In 2016,we successfully closed several significant lease transactions in Jasper, Tyler, Pecos, and Newton Counties of Texas, in the Red River parish of Louisiana, andin Potter County of Pennsylvania. Closings in 2015 included large lease transactions in the Wolfcamp, the Eagle Ford Shale, and various plays in EastTexas and in Southern Mississippi.Operating ExpensesLease operating expenses. Lease operating expense decreased for the year ended December 31, 2016 as compared to 2015, primarily due to lowerworkover expense, realized cost efficiencies resulting from a currently depressed industry market, the plugging of certain uneconomical working interestwells, and fewer remedial projects initiated by our operators.Production costs and ad valorem taxes. For the year ended December 31, 2016, production and ad valorem taxes increased over the year endedDecember 31, 2015, generally as a result of higher production volumes.Exploration expense. Exploration expense for the years ended December 31, 2016 and 2015 primarily resulted from costs incurred to acquire 3-D seismicinformation related to our mineral and royalty interests from a third-party service provider.Depreciation, depletion, and amortization. Depreciation, depletion, and amortization expense increased for the year ended December 31, 2016 ascompared to 2015, primarily due to higher production rates offset by the impact of a reduced cost basis resulting from impairment charges related to priorperiods.Impairment of oil and natural gas properties. Impairments of $249.6 million for the year ended December 31, 2015 primarily resulted from changes inreserve values due to declines in future expected realized net cash flows as a result of lower commodity prices. Impairments of $6.8 million for 2016 wereinsignificant.General and administrative. For the year ended December 31, 2016, general and administrative expenses decreased compared to 2015. In 2016,personnel costs and costs attributable to our long-term incentive plans were lower primarily due to one-time incentive compensation awards granted in 2015as a result of our IPO and certain restructuring costs incurred in 2015. In addition, we also incurred $2.5 million for our Sarbanes-Oxley Act complianceproject and other consulting work during 2015.Interest expense. Interest expense increased due to higher average outstanding borrowings under our credit facility. Outstanding borrowings during 2016were higher than 2015, primarily due to additional borrowings for multiple acquisitions, preferred unit redemptions, and common unit repurchases.69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 distributions equal in amount to the applicable minimum quarterlydistribution will be paid on each common and subordinated unit for each quarter to the extent we have sufficient cash generated from our operations afterestablishment of cash reserves, if any, and after we have made the required distributions to the holders of our outstanding preferred units. However, we do nothave a legal or contractual obligation to pay distributions on our common and subordinated units quarterly or on any other basis, at the applicable minimumquarterly distribution rate or at any other rate, and there is no guarantee that we will pay distributions to our common and subordinated unitholders in anyquarter. Our minimum quarterly distribution provides the common unitholders a specified priority right to distributions over the subordinated unitholders.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. On June 8, 2017, the board of directors of our general partnerestablished a replacement capital expenditure estimate of $13.0 million for the period of April 1, 2017 to March 31, 2018.Cash FlowsThe following table shows our cash flows for the periods presented: Year Ended December 31, 2017 2016 2015 (in thousands)Cash flows provided by operating activities $281,852 $196,656 $284,735Cash flows used in investing activities (454,249) (221,542) (90,998)Cash flows provided by (used in) financing activities 168,267 21,425 (195,307)Year Ended December 31, 2017 Compared to Year Ended December 31, 2016Operating Activities. Our operating cash flow is dependent, in large part, on our production, realized commodity prices, leasing revenues, and operatingexpenses. For the year ended December 31, 2017, cash flows from operating activities increased by $85.2 million. This increase was primarily due toincreased oil and natural gas revenue driven by higher oil and natural gas sales, an increase in lease bonus and other income, as well as changes in workingcapital, which was partially offset by increased production costs and ad valorem taxes and general and administrative expenses, as well as a decrease in netcash received on the settlement of commodity derivative financial instruments.Investing Activities. The net cash used in investing activities increased by $232.7 million in 2017 as compared to 2016 primarily due to the cash portionof oil 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.70Financing Activities. For the year ended December 31, 2017, financing activities increased by $146.8 million. The increase was primarily due toproceeds from the issuance of common units under our ATM Program and proceeds from the issuance of the Series B cumulative convertible preferred units.Decreased distributions to holders of the Series A redeemable preferred units and decreased repurchases of common and subordinated units also contributedto increased financing cash flows. These increases were partially offset by increased distributions to common and subordinated unitholders and a decrease innet borrowings under our credit facility compared to 2016.Year Ended December 31, 2016 Compared to Year Ended December 31, 2015Operating Activities. Our operating cash flow is dependent, in large part, on our production, realized commodity prices, leasing revenues, and operatingexpenses. For the year ended December 31, 2016, cash flows from operating activities decreased by $88.1 million. This decrease was primarily due to lowercash collections of $68.9 million related to oil and natural gas sales as compared to 2015 and the impact of $18.4 million in lower cash collections related tothe settlement of commodity derivative instruments.Investing Activities. The net cash used in investing activities increased by $130.5 million in 2016 as compared to 2015 primarily due to four mineral andproperty acquisitions that closed during 2016 and higher capital expenditures for our working interests.Financing Activities. For the year ended December 31, 2016, we generated cash from financing activities as we increased borrowings under our creditfacility and lowered distributions on our subordinated units as compared to the corresponding period in 2015. Financing activities were further impacted bythe repurchase of common units.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. After the completion and approval of the capital budget, we establish an estimate of replacementcapital expenditures.Our 2018 capital expenditure budget associated with our working-interest participation program is expected to be between $15.0 million and $25.0million, approximately 99% of which will be spent in the Haynesville/Bossier play with the remainder to be spent in various plays including theBakken/Three Forks and Wolfcamp plays. We also expect to spend approximately $10 million to $12 million to drill two 100% working interest exploratorywells to evaluate a Lower Wilcox prospect in East Texas.During 2017, we spent approximately $58.6 million related to drilling and completion costs. We also spent approximately $425.7 million related toacquisitions of oil and natural gas properties. Additionally, our capital expenditures were offset by proceeds from farmout agreements of approximately $19.2million.During 2016, we spent approximately $73.3 million related to drilling and completion costs. We also spent approximately$141.1 million related to fourmineral acquisitions in 2016 as well as a final holdback payment from an acquisition in 2015.During 2015, we spent approximately $54.2 million related to drilling and completion costs, the majority of which was in the Haynesville/Bossier,Bakken/Three Forks, and Wilcox plays. We also spent approximately $62.3 million on eight acquisitions. See Note 4 – Oil and Natural Gas PropertiesAcquisitions in the consolidated financial statements included elsewhere in this Annual Report for further discussion.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. Our credit facility now terminates on November 1, 2022. As of December 31, 2017, we had outstandingborrowings of $388.0 million at a weighted-average interest rate of 4.06%.71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 additionally have theright to request a redetermination following acquisition of oil and natural gas properties in excess of 10% of the value of the borrowing base immediatelyprior to such 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.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 base redetermination or otherwise, in some cases subject to a cure period, or (b) at the maturity date. Our credit facility is secured by liens onsubstantially all of our 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, 2017, we were in compliance with all debt covenants.Contractual ObligationsThe following table summarizes our minimum payments as of December 31, 2017 (in thousands): Payments due by period Total Less Than 1Year 1-3 Years 3-5 Years More Than 5 YearsCredit facility $388,000 $— $— $388,000 $—Operating lease obligations 1,708 1,65454 — —Purchase commitments 1,017 856 161 — —Total $390,725 $2,510 $215 $388,000 $—Off-Balance Sheet ArrangementsAt December 31, 2017, we did not have any material off-balance sheet arrangements.72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 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.Successful Efforts Method of AccountingWe 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 depreciation, depletion, and amortization ("DD&A"). DD&A of producing oil andnatural gas properties is recorded based on the units-of-production method. Capitalized development costs are amortized on the basis of proved developedreserves while leasehold acquisition costs and the costs to acquire proved properties are amortized on the basis of all proved reserves, both developed andundeveloped. Proved reserves are quantities of oil and natural gas that can be estimated with reasonable certainty to be economically producible from a givendate forward, from known reservoirs, under existing economic conditions, operating methods, and government regulations. DD&A expense related to ourproducing oil and natural gas properties was $114.3 million, $102.4 million and $102.7 million for the years ended December 31, 2017, 2016, and 2015,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.73There was no impairment of proved oil and natural gas properties for the year ended December 31, 2017. Impairment of proved oil and natural gasproperties was $4.9 million and $127.8 million for the years ended December 31, 2016 and 2015, respectively. The impairments primarily resulted fromdeclines in future expected realizable net cash flows. The charges are included in impairment of oil and natural gas properties on the consolidated statementsof 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 year endedDecember 31, 2017. Impairment of unproved properties was $1.9 million and $121.8 million for the years ended December 31, 2016 and 2015, respectively.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, 2017 reserve report. Applying this discount results in anapproximate 2.2% reduction of estimated proved reserve volumes as compared to the undiscounted pricing scenario used in our December 31, 2017 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 related asset.Revenue RecognitionWe recognize revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasiveevidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller’s price to the buyer is fixed or determinable, and(iv) collectability is reasonably assured.We recognize oil and natural gas revenue from our interests in producing wells when the associated production is sold. The volumes of natural gas soldmay differ from the volumes to which we are entitled based on our interests in the properties. These differences create imbalances that are recognized as aliability only when the properties’ estimated remaining reserves, net to us, will not be sufficient to enable the under-produced owner to recoup its entitledshare through production; however, such amounts are de minimis at December 31, 2017 and 2016.To the extent actual volumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not receivedfrom third parties, the expected sales volume and prices for these properties are estimated and recorded within accounts receivable in the accompanyingconsolidated balance sheets. Crude oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related tooil quality and physical location. Natural gas contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors,whether a well delivers to a gathering or transmission line, quality and heat content of natural gas, and prevailing supply and demand conditions, so that theprice of natural gas fluctuates to remain competitive with other available natural gas supplies. These market indices are determined on a monthly basis.74Other sources of revenue we receive include mineral lease bonuses and delay rentals. We generate lease bonus revenue by leasing our mineral interests toexploration and production companies. The lease agreements generally transfer the rights to any oil or natural gas discovered, grant us a right to a specifiedroyalty interest, and require that drilling and completion operations commence within a specified time period. We recognize such lease bonus revenue atwhich time the lease agreement has been executed, payment is determined to be collectable, and we have no further obligation to refund the payment. Wealso recognize revenue from delay rentals to the extent drilling has not started within the specified period, payment has been collected, and we have nofurther obligation to refund the payment.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, fixedprice 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 unitsunderlying 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 ofoperations. Distribution equivalent rights for the restricted performance unit awards that are expected to vest are charged to partners’ capital. Please read Note9 – Incentive Compensation within the consolidated financial statements included elsewhere in this Annual Report for additional information.Prior to our IPO, the board of directors of our Predecessor determined the fair value of unit-based awards by considering various objective and subjectivefactors, along with input from management, and using the same methodology as required under our Predecessor’s partnership agreement for purposes ofrepurchasing Predecessor common units from those limited partners who exercise their right to annually sell a portion of their units. To determine the fairvalue of the unit-based awards, the board of directors of our Predecessor considered information provided by third-party consultants and relied on generallyaccepted valuation techniques, which included the net asset value method under the asset approach, the guideline public company method under the marketapproach, and the dividend discount method of the income approach. Estimates of value using the net asset value method were derived using assumptionsincluding commodity prices, estimated development timing of our acreage, and market-based discount rates. The value conclusion using the guidelinepublic company method was estimated by considering peer company performance metrics, comparability of the peer company portfolio and risk profiles, andimplied forward distribution yields and multiples. To estimate the value of the awards using the transaction method, publicly available data related toacquisitions of mineral properties and applied the implied deal metrics to our performance measures were reviewed. The dividend discount method wasdeveloped based on assumptions including our projected distributions, anticipated long-term distribution growth rates, and near- and long-term cost ofcapital estimates. In determining the fair value of the awards, the board of directors of our Predecessor also considered our historical transactions andperformance in making these estimates.New and Revised Financial Accounting StandardsThe effects of new accounting pronouncements are discussed in Note 2 – Summary of Significant Accounting Policies within the consolidatedfinancial statements included elsewhere in this Annual Report. 75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, 2017. Applying this discount results in an approximate 2.2% reduction of proved reservevolumes as compared to the undiscounted December 31, 2017 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, 2017, we had nine counterparties, all of which are rated Baa1 or better byMoody’s. Seven 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, 2017, we had $388.0 million of outstanding borrowings underour credit facility, bearing interest at a weighted-average interest rate of 4.06%. 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 $3.9 million for the year ended December 31,2017, 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. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURENone.76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, 2017 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 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, 2017, 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, 2017.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, 2017, 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, 2017, that have materially affected, or are reasonably likely to materially affect, our internal control overfinancial reporting. ITEM 9B. OTHER INFORMATIONNone.77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 2018 Annual Meeting of LimitedPartners (“2018 Proxy Statement”), which will be filed with the SEC not later than 120 days after December 31, 2017.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 2018 Proxy Statement, which will be filed with the SEC not later than 120 days afterDecember 31, 2017.ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERSInformation required by this item is incorporated by reference to the 2018 Proxy Statement, which will be filed with the SEC not later than 120 days afterDecember 31, 2017.ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCEInformation required by this item is incorporated by reference to the 2018 Proxy Statement, which will be filed with the SEC not later than 120 days afterDecember 31, 2017.ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICESInformation required by this item is incorporated by reference to the 2018 Proxy Statement, which will be filed with the SEC not later than 120 days afterDecember 31, 2017.78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 of 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)). 7910.2 Third Amended and Restated Credit Agreement among Black Stone Minerals Company, L.P., as Borrower, Wells Fargo Bank, NationalAssociation, as Administrative Agent, Bank of America, N.A. and Compass Bank, as Co-Syndication Agents, Wells Fargo Bank, N.A. andAmegy Bank National Association, as Co-Documentation Agents, and a syndicate of lenders dated as of January 23, 2015 (incorporatedherein by reference to Exhibit 10.2 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC FileNo. 333-202875)). 10.3 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)). 10.4*# 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. 10.5^ 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^ Black Stone Minerals Company, L.P. 2012 Executive Incentive Plan (incorporated herein by reference to Exhibit 10.5 to Black StoneMinerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)). 10.8^ Restricted Unit Award Agreement by and between Black Stone Minerals Company, L.P. and Thomas L. Carter, Jr. effective as of January1, 2012 (incorporated herein by reference to Exhibit 10.6 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed onMarch 19, 2015 (SEC File No. 333-202875)). 10.9^ Restricted Unit Award Agreement by and between Black Stone Minerals Company, L.P. and Marc Carroll effective as of January 1, 2012(incorporated herein by reference to Exhibit 10.7 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19,2015 (SEC File No. 333-202875)). 10.10^ Restricted Unit Award Agreement by and between Black Stone Minerals Company, L.P. and Holbrook F. Dorn effective as of January 1,2012 (incorporated herein by reference to Exhibit 10.8 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March19, 2015 (SEC File No. 333-202875)). 10.11^ 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)). 10.12^ 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)). 10.13^ 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)). 10.14^ 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)). 10.15^ 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)). 10.16^ 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). 10.17* Form of STI Award Letter (Leadership) under the Black Stone Minerals, L.P. Long-Term Incentive Plan. 8010.18^ Separation and Consulting Agreement and General Release of Claims, dated as of November 21, 2016, by and among Marc Carroll, BlackStone Natural Resources Management Company, and Black Stone Minerals GP, L.L.C. (incorporated herein by reference to Exhibit 10.1Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on November 28, 2016 (SEC File No. 001-37362)). 10.19 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 BDO USA, LLP 23.3* 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 2002 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.#The agreement filed herewith is a corrected version of the agreement previously filed as Exhibit 10.1 to the Current Report on Form 8-K filed onFebruary 12, 2018.81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 February 28, 2018 By: /s/ Thomas L. Carter, Jr. Thomas L. Carter, Jr. President, Chief Executive Officer, and Chairman 82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. President, Chief Executive Officer, and Chairman February 28, 2018Thomas L. Carter, Jr. (Principal Executive Officer) /s/ Jeffrey P. Wood Senior Vice President and Chief Financial Officer February 28, 2018Jeffrey P. Wood (Principal Financial Officer) /s/ Dawn K. Smajstrla Vice President and Chief Accounting Officer February 28, 2018Dawn K. Smajstrla (Principal Accounting Officer) /s/ William G. Bardel Director February 28, 2018William G. Bardel /s/ Carin M. Barth Director February 28, 2018Carin M. Barth /s/ D. Mark DeWalch Director February 28, 2018D. Mark DeWalch /s/ Ricky J. Haeflinger Director February 28, 2018Ricky J. Haeflinger /s/ Jerry V. Kyle, Jr. Director February 28, 2018Jerry V. Kyle, Jr. /s/ Michael C. Linn Director February 28, 2018Michael C. Linn /s/ John H. Longmaid Director February 28, 2018John H. Longmaid /s/ William N. Mathis Director February 28, 2018William N. Mathis /s/ William E. Randall Director February 28, 2018William E. Randall /s/ Alexander D. Stuart Director February 28, 2018Alexander D. Stuart /s/ Allison K. Thacker Director February 28, 2018Allison K. Thacker 83INDEX TO CONSOLIDATED FINANCIAL STATEMENTSBLACK STONE MINERALS, L.P. Reports of Independent Registered Public Accounting Firms F-2 Consolidated Balance Sheets as of December 31, 2017 and December 31, 2016 F-5 Consolidated Statements of Operations for the Years Ended December 31, 2017, 2016 and 2015 F-6 Consolidated Statements of Equity for the Years Ended December 31, 2017, 2016 and 2015 F-7 Consolidated Statements of Cash Flows for the Years Ended December 31, 2017, 2016 and 2015 F-8 Notes to Consolidated Financial Statements F-9F-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, 2017and 2016, the related consolidated statements of operations, equity and cash flows for each of the two years in the period ended December 31, 2017, and therelated notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, theconsolidated financial position of the Partnership at December 31, 2017 and 2016, and the consolidated results of its operations and its cash flows for each ofthe two years in the period ended December 31, 2017, 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, 2017, 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 28, 2018 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 28, 2018F-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, 2017, 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, 2017, 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, 2017 and 2016, the related consolidated statements of operations, equity and cash flows for each of thetwo years in the period ended December 31, 2017, and the related notes and our report dated February 28, 2018 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 regulation 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 anunderstanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operatingeffectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. Webelieve 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 28, 2018F-3REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMThe Partners ofBlack Stone Minerals, L.P.Houston, TexasWe have audited the accompanying consolidated statements of operations, equity, and cash flows of Black Stone Minerals, L.P. and subsidiaries (the“Partnership”) for the year ended December 31, 2015. These consolidated financial statements are the responsibility of the Partnership’s management. Ourresponsibility is to express an opinion on these consolidated financial statements based on our audit.We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require thatwe plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. ThePartnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included considerationof internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose ofexpressing an opinion on the effectiveness of the Partnership's internal control over financial reporting. Accordingly, we express no such opinion. An auditalso includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, assessing the accountingprinciples used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believethat our audit provides a reasonable basis for our opinion.In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the results of operations and cash flows of BlackStone Minerals, L.P. and subsidiaries for the year ended December 31, 2015, in conformity with accounting principles generally accepted in the United Statesof America./s/ BDO USA, LLPHouston, TexasMarch 8, 2016F-4BLACK STONE MINERALS, L.P. AND SUBSIDIARIESCONSOLIDATED BALANCE SHEETS(in thousands) As of December 31, 2017 2016ASSETS CURRENT ASSETS Cash and cash equivalents$5,642 $9,772Accounts receivable80,695 68,181Commodity derivative assets94 —Prepaid expenses and other current assets1,212 1,036TOTAL CURRENT ASSETS87,643 78,989PROPERTY AND EQUIPMENT Oil and natural gas properties, at cost, using the successful efforts method of accounting, includes unproved properties of $988,720 and$605,736 at December 31, 2017 and 2016, respectively3,247,613 2,697,073Accumulated depreciation, depletion, amortization, and impairment(1,766,842) (1,652,930)Oil and natural gas properties, net1,480,771 1,044,143Other property and equipment, net of accumulated depreciation of $14,433 and $14,327 at December 31, 2017 and 2016, respectively559 528NET PROPERTY AND EQUIPMENT1,481,330 1,044,671DEFERRED CHARGES AND OTHER LONG-TERM ASSETS7,478 5,167TOTAL ASSETS$1,576,451 $1,128,827LIABILITIES, MEZZANINE EQUITY, AND EQUITY CURRENT LIABILITIES Accounts payable$2,464 $4,142Accrued liabilities52,631 50,952Commodity derivative liabilities4,222 16,237Other current liabilities417 —TOTAL CURRENT LIABILITIES59,734 71,331LONG-TERM LIABILITIES Credit facility388,000 316,000Accrued incentive compensation3,648 1,485Commodity derivative liabilities1,263 482Deferred revenue— 518Asset retirement obligations14,092 13,350Other long-term liabilities19,171 —TOTAL LIABILITIES485,908 403,166COMMITMENTS AND CONTINGENCIES (Note 11) MEZZANINE EQUITY Partners' equity — Series A redeemable preferred units, 26 and 53 units outstanding at December 31, 2017 and 2016, respectively27,028 54,015Partners' equity — Series B cumulative convertible preferred units, 14,711 and 0 units outstanding at December 31, 2017 and 2016,respectively295,394 —EQUITY Partners' equity — general partner interest— —Partners' equity — common units, 103,456 and 95,721 units outstanding at December 31, 2017 and 2016, respectively603,116 489,023Partners' equity — subordinated units, 95,388 and 95,164 units outstanding at December 31, 2017 and 2016, respectively164,138 181,602Noncontrolling interests867 1,021TOTAL EQUITY768,121 671,646TOTAL LIABILITIES, MEZZANINE EQUITY, AND EQUITY$1,576,451 $1,128,827 The 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 OPERATIONS(in thousands, except per unit amounts) Year Ended December 31, 2017 2016 2015REVENUE Oil and condensate sales$169,728 $142,382 $163,538Natural gas and natural gas liquids sales190,967 122,836 116,018Gain (loss) on commodity derivative instruments26,902 (36,464) 90,288Lease bonus and other income42,062 32,079 23,080TOTAL REVENUE429,659 260,833 392,924OPERATING (INCOME) EXPENSE Lease operating expense17,280 18,755 21,583Production costs and ad valorem taxes47,474 35,464 35,767Exploration expense618 645 2,592Depreciation, depletion and amortization114,534102,487104,298Impairment of oil and natural gas properties—6,775249,569General and administrative77,574 73,139 77,175Accretion of asset retirement obligations1,0268921,075(Gain) loss on sale of assets, net(931) (4,793) (4,873)Other expense— — 1,593TOTAL OPERATING EXPENSE257,575 233,364 488,779INCOME (LOSS) FROM OPERATIONS172,084 27,469 (95,855)OTHER INCOME (EXPENSE) Interest and investment income49 656 58Interest expense(15,694) (7,547) (6,418)Other income (expense)714 (390) 910TOTAL OTHER EXPENSE(14,931) (7,281) (5,450)NET INCOME (LOSS)157,153 20,188 (101,305)Net loss attributable to Predecessor— — (450)Net income attributable to noncontrolling interests subsequent to initial public offering34 12 1,260Distributions on Series A redeemable preferred units subsequent to initial public offering(3,117) (5,763) (7,522)Distributions on Series B cumulative convertible preferred units(1,925) — —NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATEDUNITS SUBSEQUENT TO INITIAL PUBLIC OFFERING$152,145 $14,437 $(108,017)ALLOCATION OF NET INCOME (LOSS) SUBSEQUENT TO INITIAL PUBLIC OFFERING ATTRIBUTABLE TO: General partner interest$— $— $—Common units98,389 24,669 (54,326)Subordinated units53,756 (10,232) (53,691) $152,145 $14,437 $(108,017)NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT: Per common unit (basic)$1.01 $0.26 $(0.56)Weighted average common units outstanding (basic)97,400 96,073 96,182Per subordinated unit (basic)$0.56 $(0.11) $(0.56)Weighted average subordinated units outstanding (basic)95,149 95,138 95,057Per common unit (diluted)$1.01 $0.26 $(0.56)Weighted average common units outstanding (diluted)97,400 96,243 96,182Per subordinated unit (diluted)$0.56 $(0.11) $(0.56)Weighted average subordinated units outstanding (diluted)95,149 95,138 95,057DISTRIBUTIONS DECLARED AND PAID SUBSEQUENT TO INITIAL PUBLIC OFFERING: Per common unit$1.20 $1.10 $0.42Per subordinated unit$0.79 $0.74 $0.42The 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 EQUITY(in thousands) Predecessor Black Stone Minerals, L.P. Predecessorunits Partners'equity Commonunits Subordinatedunits Partners'equity—commonunits Partners'equity—subordinatedunits Noncontrollinginterests TotalequityBALANCE AT DECEMBER 31, 2014164,484 653,217 — — $— $— $— $653,217Conversion of Predecessor redeemablepreferred units2,750 39,240 — — — — — 39,240Restricted Predecessor units granted562 — — — — — — —Repurchases of Predecessor units(164) (3,015) — — — — — (3,015)Distributions to Predecessor unitholders andnoncontrolling interests— (73,205) — — — — — (73,205)Distributions on Predecessor redeemablepreferred units— (4,040) — — — — — (4,040)Net income attributable to Predecessor— 450 — — — — — 450Allocation of Predecessor units and equity(167,632) (612,647) 72,575 95,057 264,235 345,875 2,537 —Issuance of common units for initial publicoffering, net of offering costs— — 22,500 — 391,500 — — 391,500Restricted common units granted, net offorfeitures— — 1,087 — — — — —Equity-based compensation— — — — 14,181 3,819 — 18,000Distributions— — — — (40,783) (40,304) (133) (81,220)Charges to partners' equity for accrueddistribution equivalent rights— — — — (159) — — (159)Net loss subsequent to initial public offering— — — — (50,543) (49,952) (1,260) (101,755)Distributions on Series A redeemable preferredunits— — — — (3,783) (3,739) — (7,522)BALANCE AT DECEMBER 31, 2015— — 96,162 95,057 574,648 255,699 1,144 831,491Conversion of Series A redeemable preferredunits— — 184 241 2,625 3,439 — 6,064Repurchases of common and subordinatedunits— — (1,618) (78) (27,436) — — (27,436)Restricted common and subordinated unitsgranted, net of forfeitures— — 993 (56) — — — —Equity-based compensation— — — — 21,022 2,823 — 23,845Distributions— — — — (105,817) (70,127) (111) (176,055)Charges to partners' equity for accrueddistribution equivalent rights— — — — (688) — — (688)Net income (loss)— — — — 27,565 (7,365) (12) 20,188Distributions on Series A redeemable preferredunits— — — — (2,896) (2,867) — (5,763)BALANCE AT DECEMBER 31, 2016— — 95,721 95,164 489,023 181,602 1,021 671,646Conversion of Series A redeemable preferredunits— — 201 263 2,868 3,756 — 6,624Repurchases of common and subordinatedunits— — (446) (39) (7,893) (292) — (8,185)Issuance of common units, net of offeringcosts— — 2,002 — 32,458 — — 32,458Issuance of units for property acquisitions— — 4,348 — 71,723 — — 71,723Restricted units granted, net of forfeitures— — 1,630 — — — — —Equity-based compensation— — — — 39,205 152 — 39,357Distributions— — — — (119,963) (74,836) (120) (194,919)Charges to partners' equity for accrueddistribution equivalent rights— — — — (2,694) — — (2,694)Net income (loss)— — — — 101,891 55,296 (34) 157,153Distributions on Series A redeemable preferredunits— — — — (1,577) (1,540) — (3,117)Distributions on Series B cumulativeconvertible preferred units— — — — (1,925) — — (1,925)BALANCE AT DECEMBER 31, 2017— — 103,456 95,388 $603,116 $164,138 $867 $768,121The accompanying notes to consolidated financial statements are an integral part of these financial statements.F-7BLACK STONE MINERALS, L.P. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF CASH FLOWS(in thousands) Year Ended December 31, 2017 2016 2015CASH FLOWS FROM OPERATING ACTIVITIES Net income (loss)$157,153 $20,188 $(101,305)Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation, depletion, and amortization114,534 102,487 104,298Impairment of oil and natural gas properties— 6,775 249,569Accretion of asset retirement obligations1,026 892 1,075Amortization of deferred charges877 871 935(Gain) loss on commodity derivative instruments(26,902) 36,464 (90,288)Net cash received (paid) on settlement of commodity derivative instruments15,211 44,789 63,225Equity-based compensation33,044 43,138 18,000(Gain) loss on sale of assets, net(931) (4,793) (4,873)Changes in operating assets and liabilities: Accounts receivable(6,084) (29,759) 33,586Prepaid expenses and other current assets(177) (180) 95Accounts payable and accrued liabilities(3,585) (23,029) 11,221Deferred revenue(2,086) (870) (660)Settlement of asset retirement obligations(228) (317) (143)NET CASH PROVIDED BY OPERATING ACTIVITIES281,852 196,656 284,735CASH FLOWS FROM INVESTING ACTIVITIES Acquisitions of oil and natural gas properties(425,667) (141,136) (62,278)Additions to oil and natural gas properties(58,648) (80,179) (54,244)Purchases of other property and equipment(207) (425) (181)Proceeds from the sale of oil and natural gas properties11,102 198 25,705Proceeds from farmouts of oil and natural gas properties19,171 — —NET CASH USED IN INVESTING ACTIVITIES(454,249) (221,542) (90,998)CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from issuance of common units of Black Stone Minerals, L.P., net of offering costs32,458 — 399,087Proceeds from issuance of Series B cumulative convertible preferred units of Black Stone Minerals, L.P., net ofoffering costs293,469 — —Distributions to Predecessor unitholders— — (126,383)Distributions to common and subordinated unitholders(194,799) (175,943) (81,087)Distributions to Series A redeemable preferred unitholders(3,777) (6,385) (13,578)Distributions to noncontrolling interests(120) (111) (208)Redemption of Series A redeemable preferred units(19,704) (18,461) (40,747)Repurchases of Predecessor units— — (3,015)Repurchases of common and subordinated units(8,185) (27,436) —Borrowings under credit facility292,500 349,000 245,600Repayments under credit facility(220,500) (99,000) (573,600)Debt issuance costs(3,075) (239) (1,376)NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES168,267 21,425 (195,307)NET CHANGE IN CASH AND CASH EQUIVALENTS(4,130) (3,461) (1,570)Cash and cash equivalents — beginning of the year9,772 13,233 14,803Cash and cash equivalents — end of the year$5,642 $9,772 $13,233SUPPLEMENTAL DISCLOSURE Interest paid$14,761 $6,535 $5,478NON-CASH ACTIVITIES Accrued distributions payable to Predecessor unitholders$— $— $(53,248)Conversion of Series A redeemable preferred units(6,624) (6,064) (39,240)Accrued distributions payable to Series A redeemable preferred unitholders(660) (1,324) (2,016)Accrued distributions payable to Series B cumulative convertible preferred unitholders(1,925) — —Additions to oil and natural gas properties financed through accounts payable and accrued liabilities34,247 26,553 21,496Public offering costs capitalized and offset against proceeds from initial public offering— — 7,587Asset retirement obligations incurred and revisions in estimated costs391 2,009 272Accrued distribution equivalent rights2,694 847 159 The accompanying notes to consolidated financial statements are an integral part of these financial statements.F-8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 formed on September 16, 2014. On May 6,2015, BSM completed its initial public offering (the “IPO”) of 22,500,000 common units representing limited partner interests at a price to the public of$19.00 per common unit. BSM received proceeds of $391.5 million from the sale of its common units, net of underwriting discount, structuring fee, andoffering expenses (including costs previously incurred and capitalized). BSM used the net proceeds from the IPO to repay substantially all indebtednessoutstanding under its Credit Facility, as defined in Note 8 – Credit Facility. On May 1, 2015, BSM’s common units began trading on the New York StockExchange under the symbol “BSM.”Black Stone Minerals Company, L.P., a Delaware limited partnership, and its subsidiaries (collectively referred to as “BSMC” or the “Predecessor”) ownoil and natural gas mineral and royalty interests in the United States ("U.S.") . In connection with the IPO, BSMC was merged into a wholly owned subsidiaryof BSM, with BSMC as the surviving entity. Pursuant to the merger, the Class A and Class B common units representing limited partner interests of thePredecessor were converted into an aggregate of 72,574,715 common units and 95,057,312 subordinated units of BSM at a conversion ratio of 12.9465:1 for0.4329 common units and 0.5671 subordinated units, and the preferred units of BSMC were converted into an aggregate of 117,963 Series A redeemablepreferred units of BSM at a conversion ratio of one to one. The merger was accounted for as a combination of entities under common control with assets andliabilities transferred at their carrying amounts in a manner similar to a pooling of interests. Unless otherwise stated or the context otherwise indicates, allreferences to the “Partnership” or similar expressions for time periods prior to the IPO refer to Black Stone Minerals Company, L.P. and its subsidiaries, thePredecessor, for accounting purposes. For time periods subsequent to the IPO, these terms refer to Black Stone Minerals, L.P. and its subsidiaries.In addition to mineral interests, which make up the vast majority of the asset base, the Partnership's assets also include nonparticipating royalty interestsand overriding royalty interests. These interests, which are substantially non-cost-bearing, are collectively referred to as “mineral and royalty interests.” ThePartnership’s mineral and royalty interests are located in 41 states and 64 onshore oil and natural gas producing basins of the continental U.S., including allof the major onshore producing basins. The Partnership also owns non-operated working interests in certain oil and natural gas properties.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, 2017, as discussed in Note 4 – Oil and Natural Gas Properties Acquisitions.In the opinion of management, all material adjustments, which are of a normal and recurring nature, necessary for the fair presentation of the financialresults for all periods presented have been reflected. All intercompany balances and transactions have been eliminated.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 forunder the cost method. The Partnership’s cost method investment is included in deferred charges and other long-term assets in the consolidated balancesheets. Investments in which the Partnership exercises control are consolidated, and the noncontrolling interests of such investments, which are notattributable directly or indirectly to the Partnership, are presented as a separate component of net income and equity in the accompanying consolidatedfinancial 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.F-9BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSSegment 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. NOTE 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.Commodity 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-10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 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 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 $114.3 million, $102.4 million and $102.7 million for the years ended December 31, 2017, 2016, and 2015,respectively.F-11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 reserves, future commodity prices, timingof future production, future capital expenditures, and a risk-adjusted discount rate.There was no impairment of proved oil and natural gas properties for the year ended December 31, 2017. Impairment of proved oil and natural gasproperties was $4.9 million and $127.8 million for the years ended December 31, 2016 and 2015, respectively. The impairments primarily resulted fromdeclines in future expected realizable net cash flows. The charges are included in impairment of oil and natural gas properties on the consolidated statementsof 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 year endedDecember 31, 2017. Impairment of unproved properties was $1.9 million and $121.8 million for the years ended December 31, 2016 and 2015, respectively,as included in impairment of oil and natural gas properties on the consolidated statements of operations and reflected in the net book value of oil and naturalgas 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, $0.1 million, and $1.6 million for the years ended December 31, 2017, 2016, and 2015, 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 as of December 31, 2017 and 2016: As of December 31, 2017 2016Accrued liabilities: (in thousands)Accrued capital expenditures$28,711 $17,775Accrued incentive compensation16,503 20,898Accrued property taxes4,090 3,175Accrued other3,327 9,104Total accrued liabilities$52,631 $50,952F-12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, 2017, 2016, and 2015, 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.Revenue RecognitionThe Partnership recognizes revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when:(i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller’s price to the buyer is fixed ordeterminable, and (iv) collectability is reasonably assured.The Partnership recognizes oil and natural gas revenue from its interests in producing wells when the associated production is sold. The volumes ofnatural gas sold may differ from the volumes to which the Partnership is entitled based on its interests in the properties. These differences create imbalancesthat are recognized as a liability only when the properties’ estimated remaining reserves, net to the Partnership, will not be sufficient to enable the under-produced owner to recoup its entitled share through production; however, such amounts are de minimis at December 31, 2017 and 2016.To the extent actual volumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not receivedfrom third parties, the expected sales volume and prices for these properties are estimated and recorded within accounts receivable in the accompanyingconsolidated balance sheets. Crude oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related tooil quality and physical location. Natural gas contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors,whether a well delivers to a gathering or transmission line, quality and heat content of natural gas, and prevailing supply and demand conditions, so that theprice of natural gas fluctuates to remain competitive with other available natural gas supplies. These market indices are determined on a monthly basis.Other sources of revenue received by the Partnership include mineral lease bonuses and delay rentals. The Partnership generates lease bonus revenue byleasing its mineral interests to exploration and production companies. The lease agreements generally transfer the rights to any oil or natural gas discovered,grant the Partnership a right to a specified royalty interest, and require that drilling and completion operations commence within a specified time period. ThePartnership recognizes such lease bonus revenue at which time the lease agreement has been executed, payment is determined to be collectable, and thePartnership has no further obligation to refund the payment. The Partnership also recognizes revenue from delay rentals to the extent drilling has not startedwithin the specified period, payment has been collected, and the Partnership has no further obligation to refund the payment.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.F-13BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSLimited partnerships that receive at least 90% of their gross income from designated passive sources, including royalties from mineral properties andother non-operated mineral interest income, and do not receive more than 10% of their income from operating an active trade or business, are classified as“passive entities” and are generally exempt from the Texas margin tax. The Partnership believes that it meets the requirements for being considered a“passive entity” for Texas margin tax purposes. As a result, each unitholder that is considered a taxable entity under the Texas margin tax would generally berequired to include its portion of the Partnership’s revenues in its own Texas margin tax computation. The Texas Administrative Code provides such incomeis 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, 2017 and 2016 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.Incentive 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 May 2014, the FASB issued Accounting Standards Update ("ASU") 2014-09, Revenue from Contracts with Customers (Topic 606) that will supersedeASC 605, Revenue Recognition. Under the new standard, entities will be required to use judgment and make estimates, including identifying performanceobligations in a contract, estimating the amount of variable consideration to include in the transaction price, allocating the transaction price to each separateperformance obligation, and determining when an entity satisfies its performance obligations. The new standard also requires more detailed disclosuresrelated to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The new guidance is effective forfiscal years and interim periods beginning after December 15, 2017. The standard allows for either “full retrospective” adoption, meaning that the standard isapplied to all of the periods presented with a cumulative catch-up adjustment as of the earliest period presented, or “modified retrospective” adoption,meaning the standard is applied only to the most current period presented in the financial statements with a cumulative catch-up as of the current period. The Partnership has completed its review of a representative sample of revenue contracts covering its material revenue streams that was designed toevaluate any potential changes in revenue recognition upon adoption of the new standard, and based on evaluations to-date, the implementation of the newstandard will not have a material impact on the consolidated financial statements and disclosures. The Partnership has also completed its review of theinformation technology and internal control changes that will be required to implement the new standard based on the results of its contract review process.The Partnership intends to use the modified retrospective approach upon adoption of the new guidance on the effective date of January 1, 2018, and does notanticipate recording or disclosing any material transition adjustments upon adoption.In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires lessees to recognize the lease assets and lease liabilities classifiedas operating leases on the balance sheet. The new standard will be effective for fiscal years beginning after December 15, 2018, including interim periodswithin those fiscal years, and early adoption is permitted. The Partnership will use the modified retrospective adoption approach and does not plan to earlyadopt. Based on current evaluations to-date, the new guidance will not have a material impact on the Partnership's consolidated financial statements andrelated disclosures as this guidance does not apply to leases to explore for or use minerals, oil, natural gas, and similar resources.F-14BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSIn August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments (Topic 230), toaddress diversity in practice of how certain cash receipts and cash payments are currently presented and classified in the statement of cash flows. The ASUaddresses the topic of separately identifiable cash flows and application of the predominance principle. Classification of cash receipts and payments thathave aspects of more than one class of cash flows should be determined first by applying specific guidance, and then by the nature of each separatelyidentifiable cash flow. In situations where there is an absence of specific guidance and the cash flow has aspects of more than one type of classification, thepredominance principle should be applied whereby the cash flow classification should depend on the activity that is likely to be the predominant source oruse of cash flows. The new guidance is effective for public business entities for fiscal years beginning after December 15, 2017, including interim periodswithin those fiscal years. The Partnership intends to use the retrospective transition method upon adoption of the new guidance on the effective date ofJanuary 1, 2018 and based on current evaluations to-date, adoption will not have a material impact to the consolidated financial statements and relateddisclosures.In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805), which clarifies the definition of a business in order to assistentities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The FASB issued this ASU inresponse to stakeholder feedback that the current definition of a business in ASC 805 is being applied too broadly and the application of the guidance wasnot resulting in consistent application in a cost-effective manner. This ASU provides a screen whereby a transaction will be accounted for as an asset purchase(or disposal) if substantially all of the fair value of the gross assets acquired (disposed) is concentrated in a single identifiable asset or a group of similaridentifiable assets. If the screen is not met, the entity will evaluate whether it is a business acquisition under revised criteria. The ASU is effective for publicbusiness entities for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. The Partnership will adopt the newguidance prospectively as of the effective date of January 1, 2018, and based on current evaluations to-date, adoption will not have a material impact to theconsolidated financial statements and related disclosures.In May 2017, the FASB issued ASU 2017-09, Compensation-Stock Compensation: Scope of Modification Accounting (Topic 718). The update providesguidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting under Topic718. The amendments require an entity to account for the effects of a modification unless all of the following conditions are met:•The fair value (or intrinsic or calculated value if elected) of the modified award is the same as the value of the original award immediately before theoriginal award was modified.•The vesting conditions of the modified award are the same as the vesting conditions of the original award immediately before the original award ismodified.•The classification of the modified award as an equity instrument or a liability instrument is the same as the classification of the original awardimmediately before the original award is modified.This ASU is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted.The Partnership will adopt the new guidance prospectively to all awards modified on or after the effective date of January 1, 2018, and based on currentevaluations to-date, adoption will not have a material impact to the consolidated financial statements and related 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-15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, 2017 2016 (in thousands)Beginning asset retirement obligations$13,350 $10,585Liabilities incurred308 2,009Liabilities settled(228) (317)Accretion expense1,026 892Revisions in estimated costs83 181Dispositions(30) —Ending asset retirement obligations$14,509 $13,350Current asset retirement obligations$417 $—Non-current asset retirement obligations$14,092 $13,350NOTE 4 — OIL AND NATURAL GAS PROPERTIES ACQUISITIONSNoble AcquisitionOn November 28, 2017, BSMC closed on the acquisition of (i) certain mineral interests and other non-cost bearing royalty interests from Noble EnergyInc., Noble Energy Wyco, LLC, and Rosetta Resources Operating LP and (ii) one hundred percent (100%) of the issued and outstanding securities ofSamedan Royalty, LLC ("Samedan") from Noble Energy 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 remains preliminaryand will be completed after post-closing purchase price adjustments are finalized, but in no case later than one year from the acquisition date.The following table summarizes the preliminary estimate and allocation of the fair value of the assets acquired and the acquisition-related costs. Assets Acquired Cash ConsiderationPaid Acquisition-Related Costs1 Proved Unproved Net Working Capital Total Fair Value (in thousands)Noble Assets$68,877 $259,749 $5,917 $334,543 $334,543 $2471Acquisition-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.F-16BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSThe 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. 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 nothave 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. The Partnership has an approximate 50%working interest in the acreage and is the largest mineral owner. A total of 18 wells are anticipated to be drilled over an initial phase, beginning with wellsspud after January 1, 2017. As of December 31, 2017, 10 wells had been drilled during the initial phase. At its option, Canaan may participate in twoadditional phases with each phase continuing for the lesser of 2 years or until 20 wells have been drilled. During the first three phases of the agreement,Canaan will commit on a phase-by-phase basis and fund 80% of the Partnership's drilling and completion costs and will be assigned 80% of the Partnership'sworking interests in such wells (40% working interest on an 8/8ths basis). After the third phase, Canaan can earn 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% of the Partnership's costs for those wells on a well-by-well basis. The Partnership will receive an overriding royalty interest (“ORRI”) before payout and an increased ORRI after payout on all wells drilledunder the agreement. For the year ended December 31, 2017, the Partnership received $13.6 million from Canaan under the agreement. All amounts receivedin 2017 are included in the Other long-term liabilities line of our December 31, 2017 consolidated balance sheet, as none of the drilled wells had beencompleted nor had any working interest been assigned to Canaan as of the balance sheet date.F-18BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSOn November 21, 2017, we entered into a farmout agreement with a portfolio company of Tailwater Capital, LLC, Pivotal Petroleum Partners (“Pivotal”),that covers substantially all of the Partnership's remaining working interests under active development in the Shelby Trough area of East Texas targeting theHaynesville and Bossier shale acreage after giving effect to the Canaan Farmout (discussed above) over the next eight years. In wells operated by XTOEnergy Inc. in San Augustine County, Texas, Pivotal will earn the Partnership's remaining approximate 20% working interest (10% working interest on an8/8th basis) not covered by the Canaan Farmout, as well as 100% of the Partnership's working interests (ranging from approximately 12.5% to 25% on an8/8ths basis) in wells operated by its other major operator in the area. Initially, Pivotal will be obligated to fund the development of up to 80 wells acrossseveral development areas and then will have options to continue funding the Partnership's working interest across those areas for the duration of the eightyear term. After the funding of a designated group of wells by Pivotal and once Pivotal achieves a specified payout for such well group, the Partnership willobtain a majority of the original working interest in the designated group of wells. For the year ended December 31, 2017, the Partnership received $5.6million from Pivotal under the agreement. All amounts received in 2017 are included in the Other long-term liabilities line of our December 31, 2017consolidated balance sheet, as none of the drilled wells had been completed nor had any working interest been assigned to Pivotal as of the balance sheetdate.2016 Acquisitions During the year ended December 31, 2016, the Partnership acquired producing oil and natural gas properties and unproved acreage in a diverse oil andnatural gas mineral asset package, and also completed an acquisition in June 2016 in the DJ Basin. The following table summarizes the fair value assigned tothe properties acquired: Assets Acquired Cash Consideration Paid Proved Unproved Net Working Capital ARO Total Fair Value (in thousands)June 2016$39,735 $79,827 $2,064 $(50) $121,576 $121,576The Partnership also acquired unproved mineral and royalty interests in the Permian Basin and Midland Basin for $10 million and $8.3 million in cash,respectively. Additionally, throughout 2016, the Partnership funded certain other oil and natural gas asset acquisitions for an aggregate amount of $1.2million in cash. All 2016 acquisition transactions were funded via borrowings under the Partnership's Credit Facility.2015 AcquisitionsDuring the year ended December 31, 2015, the Partnership acquired mineral and royalty interests in the Permian Basin for $51.7 million, mineral androyalty interests and non-operated working interests in the Eagle Ford Shale resource play for $9.7 million, and overriding royalty interests in the Utica Shaleand Marcellus Shale resource plays for $1.8 million. All 2015 acquisition transactions were funded via borrowings under the Partnership's Credit Facility.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, 2017, the Partnership's open derivatives contracts consisted of only fixed-price-swap contracts. A fixed-price-swap contract betweenthe Partnership and the counterparty specifies a fixed commodity price and a future settlement date. The Partnership has not designated any of its contracts asfair value or cash flow hedges. Accordingly, the changes in fair value of the contracts are included in the consolidated statement of operations in the period ofthe change. All derivative gains and losses from the Partnership's derivative contracts have been recognized in revenue in the Partnership's accompanyingconsolidated statements of operations. Derivative instruments that have not yet been settled in cash are reflected as either derivative assets or liabilities in thePartnership’s accompanying consolidated balance sheets as of December 31, 2017 and 2016. See Note 6 – Fair Value Measurements for further discussion.F-19BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSThe 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, 2017, the Partnershiphad nine counterparties, all of which are rated Baa1 or better by Moody’s. Seven 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 $12.1 million had the Partnership's counterparties as a group been unable tofulfill their obligations as of December 31, 2017. The 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, 2017 and 2016: 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 As of December 31, 2016Classification Balance Sheet Location Gross FairValue Effect ofCounterpartyNetting Net CarryingValue onBalance Sheet (in thousands)Assets: Current asset Commodity derivative assets $3,879 $(3,879) $—Long-term asset Deferred charges and other long-term assets — — —Total assets $3,879 $(3,879) $—Liabilities: Current liability Commodity derivative liabilities $20,116 $(3,879) $16,237Long-term liability Commodity derivative liabilities 482 — 482Total liabilities $20,598 $(3,879) $16,719 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 consisted of the following for the periods presented: For the year ended December 31,Derivatives not designated as hedging instruments 2017 2016 2015 (in thousands)Beginning fair value of commodity derivative instruments $(16,719) $64,534 $37,471Gain (loss) on oil derivative instruments (5,091) (15,998) 57,681Gain (loss) on natural gas derivative instruments 31,993 (20,466) 32,607Net cash received on settlements of oil derivative instruments (10,901) (27,450) (41,786)Net cash received on settlements of natural gas derivative instruments (4,310) (17,339) (21,439)Net change in fair value of commodity derivative instruments 11,691 (81,253) 27,063Ending fair value of commodity derivative instruments $(5,028) $(16,719) $64,534F-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, 2017: Volume (Bbl) Weighted Average Price(per Bbl) Range (per Bbl)Period and Type of Contract Low HighOil Swap Contracts: 2018 First quarter 729,000 $54.36 $52.09 $57.15Second quarter 736,000 54.33 52.09 56.75Third quarter 744,000 54.35 51.85 55.87Fourth quarter 749,000 54.24 51.85 55.872019 First quarter 165,000 $53.58 $52.82 $54.02Second quarter 165,000 53.58 52.82 54.02Third quarter 165,000 53.58 52.82 54.02Fourth quarter 165,000 53.58 52.82 54.02The Partnership had the following open derivative contracts for natural gas as of December 31, 2017: Volume (MMBtu) Weighted Average Price(per MMBtu) Range (per MMBtu)Period and Type of Contract Low HighNatural Gas Swap Contracts: 2018 First quarter 13,590,000 $3.06 $2.96 $3.45Second quarter 13,660,000 3.02 2.86 3.23Third quarter 13,600,000 3.01 2.90 3.23Fourth quarter 13,630,000 3.01 2.90 3.232019 First quarter 3,600,000 2.91 2.90 2.93Second quarter 3,600,000 2.91 2.90 2.93Third quarter 3,600,000 2.91 2.90 2.93Fourth quarter 3,600,000 2.91 2.90 2.93 Subsequent to December 31, 2017, the Partnership entered into oil derivative contracts for 35,000 barrels per month beginning February 2018 throughDecember 2018 and 60,000 barrels per month in 2019 at weighted average prices of $61.85 and $57.58, respectively.NOTE 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.F-21BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSLevel 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, 2017 and 2016.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, 2017 and 2016 approximated the fair value due to variable market rates of interest. These debt fairvalues, which are Level 3 measurements, were estimated based on the Partnership’s incremental borrowing rates for similar types of borrowing arrangements,when quoted market prices were not available. The estimated fair values of the Partnership’s financial instruments are not necessarily indicative of theamounts 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, 2017 Financial Assets Commodity derivative instruments $— $12,105 $— $(11,648) $457Financial Liabilities Commodity derivative instruments — 17,133 — (11,648) 5,485As of December 31, 2016 Financial Assets Commodity derivative instruments $— $3,879 $— $(3,879) $—Financial Liabilities Commodity derivative instruments — 20,598 — (3,879) 16,719Assets 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 prepared by estimating discounted cashflow projections. The factors used to determine fair value include estimates of economic reserves, future operating and development costs, future commodityprices, and a risk-adjusted discount rate. The Partnership has designated these measurements as Level 3. The Partnership's fair value assessments for recentacquisitions are included in Note 4 — Oil and Natural Gas Properties Acquisitions.F-22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, 2017 and 2016.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, 2017 Impaired oil and natural gas properties $— $— $— $— $—Year Ended December 31, 2016 Impaired oil and natural gas properties $— $— $3,042 $9,817 $6,775Year Ended December 31, 2015 Impaired oil and natural gas properties $— $— $156,689 $406,258 $249,569 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., a subsidiary of Exxon Mobil Corporation ("Exxon"), represented approximately 21% of total revenue for the yearended December 31, 2017. Exxon represented approximately 11% of total revenue for the year ended December 31, 2016. No customer represented 10% ormore of total revenue for the year ended December 31, 2015.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 secured revolving credit agreement, as amended, (the “Credit Facility”). The Credit Facility has a maximum credit amount 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 the lendersyndicate 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 April 15,2016, the borrowing base was $450.0 million. The Partnership's fall 2016 borrowing base redetermination process resulted in an increase in the borrowingbase to $500.0 million, which became effective October 31, 2016. 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 swingline facility that permits short-term borrowings on same-day notice, and make other changes to the hedging and restrictive covenants. Therewas no change to the borrowing base. The Credit Facility now terminates on November 1, 2022.Prior to October 31, 2016, borrowings under the Credit Facility bore interest at LIBOR plus a margin between 1.50% and 2.50%, or Prime Rate plus amargin between 0.50% and 1.50%, with the margin depending on the borrowing base utilization percentage of the loan. The Prime Rate was determined to bethe higher of the financial institution’s prime rate or the federal funds effective rate plus 0.50% per annum.F-23BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSEffective 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. The weighted-average interest rate of the Credit Facility was 4.06% and 3.26% as of December 31, 2017 and 2016, 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, 2017, the Partnership was in compliance with all financial covenants in theCredit Facility.The aggregate principal balance outstanding was $388.0 million and $316.0 million at December 31, 2017 and 2016, respectively. The unused portionof the available borrowings under the Credit Facility were $162.0 million and $184.0 million at December 31, 2017 and 2016, 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 common units in the Predecessor outstanding as of the date of the IPO were converted into restricted common and subordinated units of thePartnership in connection with the IPO. The converted restricted units awarded are subject to restrictions on transferability, customary forfeiture provisions,and time vesting provisions. Award recipients have all the rights of a unitholder in the Partnership with respect to the converted restricted units, including theright to receive distributions thereon, if and when made by the Partnership. Non-employee directors of the Partnership’s general partner receive compensationunder the 2015 LTIP in the form of fully vested common units granted after each year of service.F-24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 of 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") approved a grant of awards to each of the executive officers of thePartnership's general partner and certain other employees. The grant includes restricted common units subject to limitations on transferability, customaryforfeiture provisions, and service-based graded vesting requirements through January 7, 2020. Holders of restricted common unit awards have all of the rightsof 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.In April 2016, the Compensation Committee approved a resolution to change the form of settlement of certain employee long-term incentivecompensation plans from cash to equity. As a result of the modification, $10.1 million of cash-settled liabilities were reclassified to equity-settled liabilitiesduring the second quarter of 2016 and the remaining unamortized expense of the awards will be amortized as equity-settled liabilities.Additionally, in January of each year, non-employee directors on the Board receive fully vested common units for their service in the previous year.The following table summarizes information about restricted units for the year ended December 31, 2017. Units Weighted-Average Grant-Date Fair Value per Unit Common Subordinated Common SubordinatedUnvested at December 31, 2016 1,271,215 163,041 $15.29 $18.97Granted 901,910 — 18.48 —Vested (602,764) (103,912) 15.13 19.35Converted — — — —Forfeited (28,303) — 17.64 —Unvested at December 31, 2017 1,542,058 59,129 16.72 18.30The weighted-average grant-date fair value per unit for unit-based awards was $18.48, $10.09, and $18.79 for the years ended December 31, 2017, 2016,and 2015, respectively. Unrecognized compensation cost associated with restricted common and subordinated unit awards was $15.7 million and $0.2million, respectively, as of December 31, 2017, which the Partnership expects to recognize over a weighted-average period of 1.65 years and 0.2 years forcommon units and subordinated units, respectively. The fair value of units vested for the years ended December 31, 2017, 2016, and 2015 was $25.1 million,$11.9 million, and $9.4 million, respectively. There were no cash payments made for vested units during the years ended December 31, 2017, 2016 and 2015.Performance Unit AwardsThe Compensation Committee also approved 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-25BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSThe Compensation Committee also approved dollar-value targets for performance-based short-term incentive compensation for executive officers andcertain other employees of the Partnership. The Partnership expects to ultimately settle the authorized awards, at the end of the annual performance period, incommon units.The following table summarizes information about performance units for the year ended December 31, 2017. Performance units Number of Units Weighted-Average Grant-DateFair Value per UnitUnvested at December 31, 2016 1,156,419 $14.94Granted 438,288 17.99Vested — —Forfeited (137,351) 18.60Unvested at December 31, 2017 1,457,356 15.51 Unrecognized compensation cost associated with performance unit awards was $10.1 million as of December 31, 2017, which the Partnership expects torecognize over a weighted-average period of 1.54 years.Incentive Compensation SummaryThe table below summarizes incentive compensation expense recorded in general and administrative expenses in the consolidated statements ofoperations for the years ended December 31, 2017, 2016, and 2015. Year Ended December 31,Incentive compensation expense 2017 2016 2015 (In thousands)Cash — long-term incentive plan $1,412 $2,725 $15,064Equity-based compensation — restricted common and subordinated units 13,476 13,408 10,137Equity-based compensation — restricted performance units 17,367 18,518 4,743Board of Directors incentive plan 2,202 2,012 3,120Total incentive compensation expense $34,457 $36,663 $33,064NOTE 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 100% 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 employment with thePartnership. Following three years of employment, future Partnership matching contributions vest immediately. The Partnership’s contributions were $0.6million, $0.5 million, and $0.6 million for the years ended December 31, 2017, 2016, and 2015, respectively.F-26BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSNOTE 11 — COMMITMENTS AND CONTINGENCIESLeasesThe Partnership leases certain office space and equipment under cancelable and non-cancelable operating leases that end at various dates through 2021.The Partnership recognizes rent expense on a straight-line basis over the lease term. Rent expense under such arrangements was $2.5 million, $1.9 million,and $1.8 million for the years ended December 31, 2017, 2016, and 2015, respectively. Such amounts are included in general and administrative expense onthe consolidated statements of operations.Future minimum lease commitments under non-cancelable leases are as follows as of December 31, 2017:Year Ending December 31,(in thousands)2018$1,6542019382020162021—Total$1,708Environmental 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 made.Put Option Related to Noble AcquisitionBy acquiring 100% of the issued and outstanding securities of Samedan, now NAMP Holdings, LLC, the Partnership acquired a 100% interest in Comin-Termin, LLC, now NAMP GP, LLC ("Holdings"), Comin 1989 Partnership LLLP, now NAMP 1, LP ("Comin"), and Temin 1987 Partnership LLLP, nowNAMP 2, LP ("Temin"). Pursuant to certain co-ownership agreements, various co-owners hold undivided beneficial ownership interests in 47.34% and44.39% of the minerals interests held of record by Holdings and Temin, respectively. Based on the terms of the co-ownership agreements, the co-owners eachhave an unconditional option to require Comin or Temin, as applicable, to purchase their beneficial ownership interest in the mineral interests held of recordby Holdings or Temin, as applicable, at any time within 30 days of receiving such repurchase notice. The purchase price of the beneficial ownership interestshall be based on an evaluation performed by Comin or Temin, as applicable, in good faith. As of December 31, 2017, the Partnership had not received noticefrom any co-owner to exercise their repurchase option, 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, 2017 will be resolved without material adverse effect on the Partnership’s financial condition or results of operations. F-27BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSNOTE 12 — PREFERRED UNITSSeries A Redeemable Preferred UnitsThe Partnership had 26,363 and 52,691 Series A redeemable preferred units outstanding with a carrying value of $27.0 million and $54.0 million as ofDecember 31, 2017 and 2016, respectively. The aforementioned amounts include accrued distributions of $0.7 million and $1.3 million as of December 31,2017 and 2016, respectively. The Series A redeemable preferred units are classified as mezzanine equity on the consolidated balance sheets since redemptionis outside the control of the Partnership. The Series A redeemable preferred units are entitled to an annual distribution of 10%, payable on a quarterly basis inarrears.Prior to liquidation of the Partnership, and while any of the Series A redeemable preferred units remain outstanding, cash or other property of thePartnership will be 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 has been reduced to zero. Distributions inexcess of the aggregate Unpaid Preferred Yield will be distributed 100% to common and subordinated unitholders, until there has 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 shall be 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 are convertible into common and subordinated units at the option of the Series A redeemable preferredunitholders. The Series A redeemable preferred units have an adjusted conversion price of $14.2683 and an adjusted conversion rate of 30.3431 commonunits and 39.7427 subordinated units per redeemable preferred unit, which reflects the reverse split described in Note 1 – Business and Basis of Presentationand the capital restructuring related to the IPO. The Series A redeemable preferred unitholders can elect to have the Partnership redeem, at face value, up to26,363 redeemable preferred units as of December 31, 2017.The Partnership shall have the right, at its sole option, to redeem an amount of Series A redeemable preferred units equal to the units being redeemed byan owner of Series A redeemable preferred units on each December 31. Any amount of a given year’s Series A redeemable preferred units eligible forredemption not redeemed on December 31 shall automatically convert to common and subordinated units on January 1 in the following year. All Series Aredeemable preferred units not redeemed by March 31, 2018 automatically convert to common and subordinated units effective as of January 1, 2018 or assoon as practicable thereafter.F-28BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSFor 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 $6.6 million were converted into 200,996 common units and263,247 subordinated units as a result of the mandatory conversion subsequent to December 31, 2016. For the year ended December 31, 2016, 18,461 SeriesA redeemable preferred units were redeemed for $19.0 million, including accrued unpaid yield. For the year ended December 31, 2016, 6,064 Series Aredeemable preferred units totaling $6.1 million were converted into the equivalent of 184,006 common units and 240,986 subordinated units on an adjustedbasis. For the year ended December 31, 2015, 39,240 Series A redeemable preferred units totaling $39.2 million were converted into the equivalent of1,190,664 common units and 1,559,502 subordinated units on an adjusted basis.On November 6, 2015, the Partnership commenced a tender offer to purchase up to 100% of the then outstanding Series A redeemable preferred units atpar value plus unpaid accrued yield. The tender offer expired on December 10, 2015. The Partnership purchased and canceled 40,747 Series A redeemablepreferred units for $1,019.45 per unit for a total cost of $41.5 million, excluding fees and expenses related to the tender offer.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 $295.4 million, including accrued distributions of $1.9 million, as ofDecember 31, 2017. The Series B cumulative convertible preferred units are classified as mezzanine equity on the consolidated balance sheet sinceredemption is 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. The Series A redeemable preferred units could be converted into 0.8million common units and 1.1 million subordinated units as of December 31, 2017. The Series B cumulative convertible preferred units could be convertedinto 1.6 million weighted average common units as of December 31, 2017.At December 31, 2017, if the outstanding Series A redeemable preferred units were converted to common and subordinated units, and the outstandingSeries B cumulative convertible preferred units were converted to common units, the effect would be anti-dilutive. Therefore, the Series A redeemablepreferred units and the Series B cumulative convertible preferred units are not included in the diluted EPU calculations.F-29BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSThe 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. As of December 31, 2017, there were no units related to the Partnership’s restricted performance unit awards included in thecalculation of diluted EPU as the inclusion of these units would be anti-dilutive.The following table sets forth the computation of basic and diluted earnings per unit: For the Year Ended December 31, 2017 2016 2015 (in thousands, except per unit amounts)NET INCOME (LOSS) $157,153 $20,188 $(101,305)Net loss attributable to Predecessor — — (450)Net income attributable to noncontrolling interests subsequent to initial public offering 34 12 1,260Distributions on Series A redeemable preferred units subsequent to initial public offering (3,117) (5,763) (7,522)Distributions on Series B cumulative convertible preferred units $(1,925) — —NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON ANDSUBORDINATED UNITS SUBSEQUENT TO INITIAL PUBLIC OFFERING $152,145 $14,437 $(108,017)ALLOCATION OF NET INCOME (LOSS) SUBSEQUENT TO INITIAL PUBLIC OFFERINGATTRIBUTABLE TO: General partner interest $— $— $—Common units 98,389 24,669 (54,326)Subordinated units 53,756 (10,232) (53,691) $152,145 $14,437 $(108,017)NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON ANDSUBORDINATED UNIT: Per common unit (basic) $1.01 $0.26 $(0.56)Weighted average common units outstanding (basic) 97,400 96,073 96,182Per subordinated unit (basic) $0.56 $(0.11) $(0.56)Weighted average subordinated units outstanding (basic) 95,149 95,138 95,057Per common unit (diluted) $1.01 $0.26 $(0.56)Weighted average common units outstanding (diluted) 97,400 96,243 96,182Per subordinated unit (diluted) $0.56 $(0.11) $(0.56)Weighted average subordinated units outstanding (diluted) 95,149 95,138 95,057NOTE 14 — COMMON AND SUBORDINATED UNITSCommon and Subordinated UnitsThe common units and subordinated units represent limited partner interests in the Partnership. The holders of common units, subordinated units, SeriesA redeemable preferred units, and Series B cumulative convertible preferred units are holders of separate classes of limited partner interests in the Partnership.The 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 the Partnership's general partner, holders of Series B cumulative convertible preferred units in connection with any vote, consentor approval of the Series B cumulative convertible preferred units as a separate class, and persons who own 15% or more of any class as a result of anyredemption or purchase of any other person's units or similar action by the Partnership or any conversion of the Series B cumulative convertible preferredunits at the Partnership's option or in connection with a change of control may not vote on any matter.F-30BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSThe 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 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.If the distributions to common and subordinated unitholders exceed the applicable minimum quarterly distribution per unit, then such excess amountswill be distributed pro rata on the common and subordinated units as if they were a single class.Common Unit Repurchase ProgramOn 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. The Partnership repurchased atotal of 1.3 million common units for an aggregate cost of $20.2 million. The repurchase program was funded from the Partnership's cash on hand oravailability on the Credit Facility. Repurchased common units were canceled.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 price 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.Under 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.Through December 31, 2017, the Partnership sold 2.0 million common units under the ATM Program for net proceeds of $32.5 million.F-31BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSNOTE 16 — SUBSEQUENT EVENTSOn February 9, 2018, the Board approved a distribution for the period October 1, 2017 to December 31, 2017 of $0.3125 per common unit and $0.20875per subordinated unit. Distributions were paid on February 27, 2018 to unitholders of record at the close of business on February 20, 2018.Subsequent to December 31, 2017, the Partnership entered into oil derivative contracts for 35,000 barrels per month beginning February 2018 throughDecember 2018 and 60,000 barrels per month in 2019 at weighted average prices of $61.85 and $57.58, respectively.F-32BLACK STONE MINERALS, L.P. AND SUBSIDIARIESSUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES—UNAUDITEDGeographic Area of Operation All of the Partnership’s proved reserves are located within the continental U.S., with the majority concentrated in Kentucky, Louisiana, North Dakota,Oklahoma, Pennsylvania, Texas, West Virginia, and Wyoming. However, the Partnership also owns mineral and royalty interests and non-operated workinginterests in various producing and non-producing oil and natural gas properties in several other areas throughout the U.S. Therefore, the following disclosuresabout the Partnership’s costs incurred and proved reserves are presented 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, 2017 2016 2015 (in thousands)Acquisition Costs of Properties:1 Proved $96,596 $40,242 $2,302Unproved 383,535 100,888 60,994Exploration Costs 618 645 2,592Development Costs 81,056 73,316 60,056Total $561,805 $215,091 $125,944 1. See Note 4 – Oil and Natural Gas Properties Acquisitions for further discussion. Unproved properties also include purchases of leasehold prospects.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, 2017 2016 (in thousands)Proved properties $2,258,893 $2,091,337Unproved properties 988,720 605,736Total 3,247,613 2,697,073Accumulated depreciation, depletion, amortization, and impairment (1,766,842) (1,652,930)Oil and natural gas properties, net $1,480,771 $1,044,143F-33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, 2014 17,067 204,256 51,109Revisions of previous estimates1 (197) (17,043) (3,037)Purchases of minerals in place2 8 367 69Extensions, discoveries and other additions3 2,529 57,484 12,110Production (3,565) (41,389) (10,463)Net proved reserves at December 31, 2015 15,842 203,675 49,788Revisions of previous estimates1 3,007 29,024 7,844Purchases of minerals in place4 1,322 5,683 2,269Extensions, discoveries and other additions5 1,877 79,455 15,120Production (3,680) (47,498) (11,596)Net proved reserves at December 31, 2016 18,368 270,339 63,425Revisions of previous estimates1 (1,234) 21,067 2,277Purchases of minerals in place6 2,267 30,250 7,309Extensions, discoveries and other additions7 2,050 38,397 8,449Production (3,552) (59,779) (13,515)Net proved reserves at December 31, 2017 17,899 300,274 67,945Net Proved Developed Reserves8 December 31, 2015 15,497 174,555 44,590December 31, 2016 18,150 223,057 55,327December 31, 2017 17,891 233,017 56,727Net Proved Undeveloped Reserves9 December 31, 2015 345 29,120 5,198December 31, 2016 218 47,282 8,098December 31, 2017 8 67,257 11,2181 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.2 Includes the acquisition of mineral-and-royalty reserves primarily located throughout Texas, including in the Eagle Ford Shale and Wolfcamp plays andworking interest reserves, the substantial majority of which is located in the Haynesville/Bossier play in San Augustine County, Texas.3 Includes discoveries and additions primarily related to active drilling in the Haynesville/Bossier, Bakken/Three Forks, Eagle Ford Shale, Wilcox, GraniteWash, and Fayetteville plays.4 Includes the acquisition of mineral-and-royalty reserves primarily in the Marcellus and Wolfcamp plays.5Includes discoveries and additions primarily related to active drilling in the Haynesville/Bossier, Bakken/Three Forks, Wilcox, Eagle Ford, andFayetteville plays.6 Includes the acquisition of mineral-and-royalty reserves primarily in East Texas and the Permian and Williston basins.7 Includes extensions and additions related to drilling activities within multiple basins.8Proved developed reserves of 61 MBoe, 74 MBoe, and 84 MBoe as of December 31, 2017, 2016, and 2015, respectively, were attributable tononcontrolling interests in the Partnership’s consolidated subsidiaries.9As of December 31, 2017, 2016, and 2015, no proved undeveloped reserves were attributable to noncontrolling interests. F-34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, 2017 2016 2015 (in thousands)Future cash inflows $1,643,582 $1,267,179 $1,211,290Future production costs (211,064) (193,749) (205,861)Future development costs (70,111) (36,509) (84,746)Future income tax expense (2,655) (3,516) —Future net cash flows (undiscounted) 1,359,752 1,033,405 920,683Annual discount 10% for estimated timing (497,103) (430,390) (365,711)Total1 $862,649 $603,015 $554,972 1 Includes standardized measure of discounted future net cash flows of approximately $0.5 million, $0.6 million, and $0.7 million for December 31, 2017,2016, and 2015, attributable 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, 2017 2016 2015 (in thousands)Standardized measure, beginning of year $603,015 $554,972 $1,143,094Sales, net of production costs (295,941) (210,354) (222,206)Net changes in prices and production costs related to future production 169,608 (81,456) (621,065)Extensions, discoveries and improved recovery, net of future production anddevelopment costs 113,199 86,606 165,020Previously estimated development costs incurred during the period 11,118 28,909 7,084Revisions of estimated future development costs 2,653 — 669Revisions of previous quantity estimates, net of related costs 86,228 147,507 (67,911)Accretion of discount 60,512 55,662 114,309Purchases of reserves in place, less related costs 107,891 34,751 584Other 4,366 (13,582) 35,394Net increase (decrease) in standardized measures 259,634 48,043 (588,122)Standardized measure, end of year $862,649 $603,015 $554,972 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-35Selected Quarterly Financial Information—UnauditedQuarterly financial data was as follows for the periods indicated. FirstQuarter Second Quarter Third Quarter Fourth Quarter2 (In thousands, except for per unit data)2017 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 27,092 322,4222016 Total revenue $64,381 $40,569 $99,171 $56,712Net income (loss) 11,610 (19,478) 39,316 (3,979)Income (loss) from operations 10,749 (20,810) 37,535 (7,286)Net income (loss) attributable to the general partner and common andsubordinated units 8,943 (22,111) 36,219 (8,614)Net income (loss) attributable to common and subordinated units per unit (basic)1 Per common unit (basic) 0.09 (0.08) 0.24 0.01Per subordinated unit (basic) 0.01 (0.15) 0.14 (0.11)Net income (loss) attributable to common and subordinated units per unit(diluted)1 Per common unit (diluted) 0.09 (0.08) 0.24 0.01Per subordinated unit (diluted) 0.01 (0.15) 0.14 (0.11)Cash distributions declared per limited partner unit Per common unit $0.2625 $0.2625 $0.2875 $0.2875Per subordinated unit $0.1838 $0.1838 $0.1838 $0.1838Total assets 1,045,843 1,126,830 1,137,232 1,128,827Long-term debt 116,000 285,000 299,000 316,000Total mezzanine equity 54,001 54,001 54,015 54,015 1 See Note 13 – Earnings Per Unit in the consolidated financial statements.2 Reported volumes in the fourth quarter of 2016 were negatively impacted by production shut-ins estimated at 1.0 MBoe/d for the quarter related to offsetcompletion work and processing plant downtime in the Haynesville Shale.F-36Exhibit 10.4EXECUTION COPYFIRST AMENDMENTTOFOURTH AMENDED AND RESTATEDCREDIT AGREEMENTDATED AS OF FEBRUARY 7, 2018AMONGBLACK STONE MINERALS COMPANY, L.P.,AS BORROWER,BLACK STONE MINERALS, L.P.,AS PARENT MLP,WELLS FARGO BANK, NATIONAL ASSOCIATION,AS ADMINISTRATIVE AGENT,ANDTHE LENDERS PARTY HERETOSOLE BOOK RUNNER AND SOLE LEAD ARRANGERWELLS FARGO SECURITIES, LLCFIRST AMENDMENT TO FOURTH AMENDEDAND RESTATED CREDIT AGREEMENTTHIS FIRST AMENDMENT TO FOURTH AMENDED AND RESTATED CREDIT AGREEMENT (this “First Amendment”) dated as ofFebruary 7, 2018, is among: BLACK STONE MINERALS COMPANY, L.P., a Delaware limited partnership (the “Borrower”); BLACK STONE MINERALS,L.P., a Delaware limited partnership (the “Parent MLP”); each of the lenders party to the Credit Agreement referred to below (collectively, the “Lenders”); andWELLS FARGO BANK, NATIONAL ASSOCIATION, as administrative agent for the Lenders (in such capacity, together with its successors in such capacity,the “Administrative Agent”).R E C I T A L SA. The Borrower, the Parent MLP, the Administrative Agent and the Lenders are parties to that certain Fourth Amended and Restated Credit Agreementdated as of November 1, 2017 (as amended, modified or supplemented to date, the “Credit Agreement”), pursuant to which the Lenders have made certaincredit available to and on behalf of the Borrower.B. The Borrower, the Parent MLP, the Administrative Agent and the Lenders desire to amend the Credit Agreement in connection with Parent MLP’sissuance of Series B Preferred Stock as provided herein.C. Now, therefore, to induce the Administrative Agent and the Lenders to enter into this First Amendment and in consideration of the premises and themutual covenants herein contained, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties heretoagree as follows:Section 1. Defined Terms. Each capitalized term used herein but not otherwise defined herein has the meaning given such term in the Credit Agreement,as amended by this First Amendment. Unless otherwise indicated, all section references in this First Amendment refer to sections of the Credit Agreement.Section 2. Amendments to Credit Agreement.2.1 Amendments to Section 1.02. Section 1.02 is hereby amended by deleting the following definitions in their entirety and replacing them with thefollowing:“Agreement” means this Fourth Amended and Restated Credit Agreement, as amended by the First Amendment to Fourth Amended and RestatedCredit Agreement dated as of February 7, 2018, as the same may be amended or supplemented from time to time.“Change of Control” means:(i) the Parent MLP shall cease to own, directly or indirectly, all of the outstanding equity interests of (a) the Borrower and (b) the General Partner;(ii) any Person or two or more Persons acting as a group (as defined in Section113(d)(3) of the Securities Exchange Act of 1934), other than the Parent MLP or any Wholly-Owned Subsidiary of the Parent MLP, shall have acquiredbeneficial ownership (within the meaning of Rule 13d-3 of the SEC under the Securities Exchange Act of 1934) of 35% or more of the outstandingmembership interests of the Parent MLP GP; (iii) individuals who, as of the Closing Date, constitute the board of directors of the Parent MLP GP (the “ParentMLP GP Incumbent Board”) cease for any reason to constitute at least a majority of the board of directors of the Parent MLP GP; provided, however, that anyindividual becoming a director of the Parent MLP GP subsequent to such date whose election, or nomination for election by the Parent MLP GP’s board ofdirectors or committee thereof, was approved by a vote of at least a majority of the directors then comprising the Parent MLP GP Incumbent Board, shall beconsidered as though such individual were a member of the Parent MLP GP Incumbent Board; or (iv) a Series B Change of Control occurs pursuant to theterms of the Series B Preferred Stock.Section 1.02 is hereby amended by adding the following definitions where alphabetically appropriate to read as follows:“Parent MLP LPA” shall mean that certain First Amended and Restated Agreement of Limited Partnership Agreement, dated as of May 6, 2015, asamended by Amendment No. 1 thereto, effective as of May 6, 2015, and by Amendment No. 2 thereto, effective November 28, 2017, and as may be furtheramended, restated, amended and restated, supplemented or otherwise modified from time to time.“Series B Change of Control Cash Redemption Election” shall mean a notice issued in connection with a Series B Change of Control by a holderof Series B Preferred Stock to Parent MLP pursuant to paragraph 11(b) of Annex B of the Parent MLP LPA electing to require Parent MLP to redeem suchholder’s Series B Preferred Stock for cash pursuant to paragraph 11(b)(iv) of such Annex B of the Parent MLP LPA.“Series B Change of Control” shall have the meaning assigned such term in the Parent MLP LPA.“Series B Change of Control Notice” shall mean a notice issued by Parent MLP to the holders of Series B Preferred Stock pursuant to paragraph11(b) of Annex B of the Parent MLP LPA) of a Series B Change of Control.“Series B Preferred Stock” shall mean (i) (x) $300,000,000 of Parent MLP’s Series B Cumulative Convertible Preferred Units (as defined in theParent MLP LPA) issued pursuant to Amendment No. 2 to the Parent MLP LPA and (y) any Series B PIK Units (as defined in the Parent MLP LPA) issued inconnection with the same and (ii) (x) up to $200,000,000 of Series B Parity Securities (as defined in the Parent MLP LPA) and (y) any equity interests of thesame type as the Series B Parity Securities issued as “payment-in-kind” with respect to such Series B Parity Securities.22.2 Amendment to Section 8.01(i). Section 8.01(i) is hereby amended to read as follows:(i) Series B Preferred Stock. (i) contemporaneous with the issuance thereof by Parent MLP (and in any event not less than ten (10) Business Daysprior to any Series B Change of Control), any Series B Change of Control Notice and (ii) promptly upon receipt thereof by Parent MLP, a copy of any SeriesB Change of Control Cash Redemption Election.2.3 Amendment to Section 9.01(a). The parenthetical in Section 9.01(a) is hereby amended to read as follows:(excluding the Preferred Stock and the Series B Preferred Stock)2.4 Amendment to Section 9.02(m). Section 9.02(m) is hereby amended to read as follows: (m)the Preferred Stock and the Series B Preferred Stock.2.5 Amendments to Section 9.04. Section 9.04 is hereby amended to read as follows:Section 9.04. Dividends, Distributions and Redemptions. The Parent MLP and the Borrower will not, and will not permit any RestrictedSubsidiary to, declare or pay any dividend, purchase, redeem or otherwise acquire for value any of its capital or partnership interests now or hereafteroutstanding, return any capital to its Partners or make any distribution of its assets to its Partners, except for any such dividend, distribution or redemption(collectively, “Distributions”)(a) by any Restricted Subsidiary to the Parent MLP or to any other Restricted Subsidiary;(b) by the Parent MLP, other than a redemption of the Preferred Stock or the Series B Preferred Stock, so long as no Default, Event of Default orDeficiency has occurred and is continuing or would result therefrom;(c) by the Parent MLP of a redemption of the Preferred Stock, so long as (i) no Default, Event of Default or Deficiency has occurred and iscontinuing or would result therefrom, (ii) after giving effect to such redemption of Preferred Stock on a pro forma basis, the Parent MLP shall be incompliance with the covenants set forth in Section 9.01 as of the last day of the applicable period covered by the certificate most recently delivered pursuantto Section 8.01(f) (for purposes of Section 9.01, as if such redemption of the Preferred Stock, and all other redemption of Preferred Stock and Series BPreferred Stock since the first day of such applicable period, had been redeemed on the first day of such applicable period), and (iii) after giving effect to suchredemption of Preferred Stock, the Parent MLP shall have demonstrated that it will have unrestricted cash3liquidity (including, for purposes of this computation, the Unused Amount that is then available for borrowing) in an amount not less than 10% of theAggregate Elected Revolving Commitment Amount;(d) by the Parent MLP of a redemption of the Series B Preferred Stock in connection with a mandatory redemption upon a Series B Change ofControl, so long as all Loans, all interest thereon and all other amounts payable by the Borrower hereunder and under the other Loan Documents that havebecome due and payable as a result of such Series B Change of Control have first been paid in full or such required payments have been waived inaccordance with Section 12.04; and(e) by the Parent MLP of a redemption of the Series B Preferred Stock (other than a redemption described in clause (d) above), so long as (i) noDefault, Event of Default or Deficiency has occurred and is continuing or would result therefrom, (ii) after giving effect to such redemption of Series BPreferred Stock on a pro forma basis (x) the Parent MLP shall be in compliance with the covenant set forth in Section 9.01(b) and (y) the ratio of Total Debt(excluding the Preferred Stock and the Series B Preferred Stock) as of such time to EBITDAX for the four fiscal quarters ending on the last day of the fiscalquarter immediately preceding the date of determination for which financial statements are available shall be less than or equal to 2.5 to 1.0, in each case asof the last day of the applicable period covered by the certificate most recently delivered pursuant to Section 8.01(f) (for purposes hereof, as if suchredemption of the Series B Preferred Stock, and all other redemption of Preferred Stock and Series B Preferred Stock since the first day of such applicableperiod, had been redeemed on the first day of such applicable period), and (iii) after giving effect to such redemption of Series B Preferred Stock, the ParentMLP shall have demonstrated that it will have unrestricted cash liquidity (including, for purposes of this computation, the Unused Amount that is thenavailable for borrowing) in an amount not less than 20% of the Aggregate Elected Revolving Commitment Amount.Parent MLP shall not amend or modify the terms of Annex B of the Parent MLP LPA, if such amendment or modification would (x) amend or modifythe requirement set forth in paragraph 11(b)(iv) of such Annex B such that any redemption payable in cash pursuant thereto shall be subject to the priorpayment of any Indebtedness then due as a result of the event resulting in the Series B Change of Control triggering such redemption or (y) provide for themandatory redemption of the Series B Preferred Stock for any consideration other than capital stock or other equity interests upon the happening of any eventother than a Series B Change of Control.2.6 Amendments to Section 10.02. Section 10.02(a) is hereby amended to read as follows:(a) In the case of an Event of Default other than one referred to in Section 10.01 (e), (f) or (g) (or in Section 10.01(j) that is a Series B Change ofControl pursuant to which a holder of Series B Preferred Stock has issued a Series B Change of Control Cash Redemption Notice), the Administrative Agentshall, upon request of the Majority Lenders, by notice to the Borrower, cancel the Revolving Commitments and/or declare the principal amount thenoutstanding of, and the accrued interest on, the Loans and all4other amounts payable by the Borrower hereunder and under the Notes (including, without limitation, the payment of cash collateral to secure the LCExposure as provided in Section 2.10(b)) to be forthwith due and payable, whereupon such amounts shall be immediately due and payable withoutpresentment, demand, protest, notice of intent to accelerate, notice of acceleration or other formalities of any kind, all of which are hereby expressly waivedby the Borrower.Section 10.02(b) is hereby amended by adding a new sentence at the end thereof, to read as follows:In the case of an Event of Default referred to in Section 10.01(j) that is a Series B Change of Control pursuant to which a holder of Series B PreferredStock has issued a Series B Change of Control Cash Redemption Notice, the principal amount then outstanding of, and the accrued interest on, the Loans andall other amounts payable by the Borrower hereunder and under the Notes (including, without limitation, the payment of cash collateral to secure the LCExposure as provided in Section 2.10(b)) shall become automatically immediately due and payable upon the consummation of such Series B Change ofControl, without presentment, demand, protest, notice of intent to accelerate, notice of acceleration or other formalities of any kind, all of which are herebyexpressly waived by the Borrower; provided, such acceleration may at any time prior to the payment in full of such amounts by the Borrower be rescinded byMajority Lenders.2.7 Amendments to Section 12.04. Section 12.04(a) is hereby amended by adding the following at the end thereof:; provided, the rescission of any acceleration of the Loans and other amounts payable by the Borrower hereunder and under the Notes pursuant to thelast sentence of Section 10.02(b) shall as provided therein be effective upon consent of Majority Lenders:Section 3. Conditions Precedent. This First Amendment shall become effective on the date (such date, the “First Amendment Effective Date”), wheneach of the following conditions is satisfied (or waived in accordance with Section 12.04):3.1 The Administrative Agent shall have received from the Majority Lenders, the Parent MLP, and the Borrower, counterparts (in such number as maybe requested by the Administrative Agent) of this First Amendment signed on behalf of such Person.3.2 The Administrative Agent shall have received the Consent and Agreement attached to this First Amendment executed by the Guarantors (in suchnumbers as may be requested by the Administrative Agent).3.3 The Administrative Agent and the Lenders shall have received all fees and other amounts due and payable on or prior to the date hereof, including,to the extent invoiced, reimbursement or payment of all documented out-of-pocket expenses required to be reimbursed or paid by the Borrower under theCredit Agreement.3.4 No Default or Event of Default shall have occurred and be continuing as of the date hereof, immediately after giving effect to the terms of this FirstAmendment.5The Administrative Agent is hereby authorized and directed to declare this First Amendment to be effective when it has received documents confirmingor certifying, to the satisfaction of the Administrative Agent, compliance with the conditions set forth in this Section 3 of this Amendment or the waiver ofsuch conditions as permitted in Section 12.04. Such declaration shall be final, conclusive and binding upon all parties to the Credit Agreement for allpurposes.Section 4. Miscellaneous.4.1 Confirmation. The provisions of the Credit Agreement, as amended and waived by this First Amendment, shall remain in full force and effectfollowing the effectiveness of this First Amendment.4.2 Ratification and Affirmation; Representations and Warranties. Each of the Borrower and the Parent MLP hereby (a) ratifies and affirms itsobligations under, and acknowledges its continued liability under, each Loan Document to which it is a party and agrees that each Loan Document to whichit is a party remains in full force and effect as expressly amended or waived hereby and (b) represents and warrants to the Lenders that as of the date hereof,after giving effect to the terms of this First Amendment:(i) all of the representations and warranties contained in each Loan Document to which it is a party are true and correct in all materialrespects, except to the extent any such representations and warranties are expressly limited to an earlier date, in which case, such representations andwarranties shall continue to be true and correct as of such specified earlier date,(ii) no Default or Event of Default has occurred and is continuing, and(iii) no event or events have occurred which individually or in the aggregate could reasonably be expected to have a Material AdverseEffect.4.3 Counterparts. This First Amendment may be executed by one or more of the parties hereto in any number of separate counterparts, and all of suchcounterparts taken together shall be deemed to constitute one and the same instrument. Delivery of this First Amendment by facsimile transmission shall beeffective as delivery of a manually executed counterpart hereof.4.4 NO ORAL AGREEMENT. THIS FIRST AMENDMENT, THE CREDIT AGREEMENT AND THE OTHER LOAN DOCUMENTSEXECUTED IN CONNECTION HEREWITH AND THEREWITH REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAYNOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT UNWRITTEN ORAL AGREEMENTS OF THEPARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.4.5 GOVERNING LAW. THIS FIRST AMENDMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OFTHE STATE OF TEXAS.64.6 Payment of Expenses. In accordance with Section 12.03, the Borrower agrees to pay or reimburse the Administrative Agent for all of its reasonableout-of-pocket expenses incurred in connection with this First Amendment, any other documents prepared in connection herewith and the transactionscontemplated hereby, including, without limitation, the reasonable fees, charges and disbursements of counsel to the Administrative Agent.4.7 Severability. Any provision of this First Amendment which is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, beineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof, and any such prohibition orunenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.4.8 Successors and Assigns. This First Amendment shall be binding upon and inure to the benefit of the parties hereto and their respective successorsand assigns.4.9 Loan Document. This First Amendment is a Loan Document.[SIGNATURES BEGIN NEXT PAGE]7IN WITNESS WHEREOF, the parties hereto have caused this First Amendment to be duly executed as of the date first written above. BLACK STONE MINERALS COMPANY, L.P., asBorrower By: BSMC GP, L.L.C.,its General Partner By: Black Stone Minerals, L.P.,its Sole Member By: Black Stone Minerals GP, L.L.C.,its General Partner By: /s/ Jeffrey P. Wood Jeffrey P. Wood Senior Vice President andChief Financial Officer BLACK STONE MINERALS, L.P., as Parent MLP By: Black Stone Minerals GP, L.L.C.,its General Partner By: /s/ Jeffrey P. Wood Jeffrey P. Wood Senior Vice Presidentand Chief Financial Officer SIGNATURE PAGEFIRST AMENDMENT TO CREDIT AGREEMENT WELLS FARGO BANK, NATIONAL ASSOCIATION, as Administrative Agent, Issuing Bank and a Lender By: /s/ Lila Jordan Name: Lila Jordan Title: Managing Director SIGNATURE PAGEFIRST AMENDMENT TO CREDIT AGREEMENT BANK OF AMERICA, N.A.,as a Lender By: /s/ Alia Qaddumi Name: Alia Qaddumi Title: Director SIGNATURE PAGEFIRST AMENDMENT TO CREDIT AGREEMENT COMPASS BANK,as a Lender By: /s/ Gabriela Azcarate Name: Gabriela Azcarate Title: Vice President SIGNATURE PAGEFIRST AMENDMENT TO CREDIT AGREEMENT JPMORGAN CHASE BANK N.A.,as a Lender By: /s/ Theresa M. Benson Name: Theresa M. Benson Title: Authorized Officer SIGNATURE PAGEFIRST AMENDMENT TO CREDIT AGREEMENT NATIXIS, NEW YORK BRANCH,as a Lender By: /s/ Brice Le Foyer Name: Brice Le Foyer Title: Director By: /s/ Ajay Prakash Name: Ajay Prakash Title: Vice President SIGNATURE PAGEFIRST AMENDMENT TO CREDIT AGREEMENT ZB, N.A. DBA AMEGY BANK,as a Lender By: /s/ Sam Trail Name: Sam Trail Title: Senior Vice President SIGNATURE PAGEFIRST AMENDMENT TO CREDIT AGREEMENT THE BANK OF NOVA SCOTIA, HOUSTONBRANCH, as a Lender By: /s/ Alan Dawson Name: Alan Dawson Title: Director SIGNATURE PAGEFIRST AMENDMENT TO CREDIT AGREEMENT IBERIABANK, as a Lender By: /s/ Blake Norris Name: Blake Norris Title: Vice President SIGNATURE PAGEFIRST AMENDMENT TO CREDIT AGREEMENT ABN AMRO CAPITAL USA LLC, as a Lender By: /s/ Darrell Holley Name: Darrell Holley Title: Managing Director By: /s/ Michaela Braun Name: Michaela Braun Title: Director SIGNATURE PAGEFIRST AMENDMENT TO CREDIT AGREEMENT KEYBANK, NATIONAL ASSOCIATION, as a Lender By: /s/ George E. McKean Name: George E. McKean Title: Senior Vice President SIGNATURE PAGEFIRST AMENDMENT TO CREDIT AGREEMENT TEXAS CAPITAL BANK, N.A., as a Lender By: /s/ James E. Hibbert, Jr. Name: James E. Hibbert, Jr. Title: Assistant Vice President SIGNATURE PAGEFIRST AMENDMENT TO CREDIT AGREEMENT BOKF, N.A. DBA BANK OF TEXAS., as a Lender By: /s/ Marisol Salazar Name: Marisol Salazar Title: SVP SIGNATURE PAGEFIRST AMENDMENT TO CREDIT AGREEMENT[First Amendment]CONSENT AND AGREEMENTEach of the undersigned hereby (i) consents to the provisions of this First Amendment and the transactions contemplated herein, (ii) ratifies andconfirms the Fifth Amended and Restated Guaranty and Collateral Agreement dated as of November 1, 2017, as amended, modified or supplemented to date,made by it for the benefit of Administrative Agent and Lenders executed pursuant to the Credit Agreement and the other Loan Documents, (iii) ratifies andconfirms all other Loan Documents made by it for the benefit of Administrative Agent and Lenders, (iv) agrees that all of its respective obligations andcovenants thereunder, except as may be amended or modified hereby, shall remain unimpaired by the execution and delivery of this First Amendment and theother documents and instruments executed in connection herewith, and (v) agrees that such Fifth Amended and Restated Guaranty and such other LoanDocuments shall remain in full force and effect.[SIGNATURES BEGIN NEXT PAGE]IN WITNESS WHEREOF, the parties hereto have caused this Consent and Agreement to be duly executed as of the date first written above. BLACK STONE ENERGY COMPANY, L.L.C. By: Black Stone Minerals Company, L.P., its Sole Member By: BSMC GP, L.L.C., its General Partner By: Black Stone Minerals, L.P., its Sole Member By: Black Stone Minerals GP, L.L.C., its General Partner By: /s/ Jeffrey P. Wood Jeffrey P. Wood Senior Vice President and Chief FinancialOfficer BLACK STONE NATURAL RESOURCES, L.L.C. By: Black Stone Minerals Company, L.P., its Sole Member By: BSMC GP, L.L.C., its General Partner By: Black Stone Minerals, L.P., its Sole Member By: Black Stone Minerals GP, L.L.C., its General Partner By: /s/ Jeffrey P. Wood Jeffrey P. Wood Senior Vice President and Chief FinancialOfficer SIGNATURE PAGECONSENT TO FIRST AMENDMENT TO CREDIT AGREEMENT TLW INVESTMENTS, L.L.C. By: Black Stone Energy Company, L.L.C., its Manager By: Black Stone Minerals Company, L.P., its Sole Member By: BSMC GP, L.L.C., its General Partner By: Black Stone Minerals, L.P., its Sole Member By: Black Stone Minerals GP, L.L.C., its General Partner By: /s/ Jeffrey P. Wood Jeffrey P. Wood Senior Vice President and Chief FinancialOfficer BSAP II GP, L.L.C. By: Black Stone Minerals Company, L.P., its Sole Member By: BSMC GP, L.L.C., its General Partner By: Black Stone Minerals, L.P., its Sole Member By: Black Stone Minerals GP, L.L.C., its General Partner By: /s/ Jeffrey P. Wood Jeffrey P. Wood Senior Vice President and Chief FinancialOfficer SIGNATURE PAGECONSENT TO FIRST AMENDMENT TO CREDIT AGREEMENT BLACK STONE MINERALS, L.P. By: Black Stone Minerals GP, L.L.C., its General Partner By: /s/ Jeffrey P. Wood Jeffrey P. Wood Senior Vice President and Chief FinancialOfficer BSMC GP, L.L.C. By: Black Stone Minerals, L.P., its Sole Member By: Black Stone Minerals GP, L.L.C., its General Partner By: /s/ Jeffrey P. Wood Jeffrey P. Wood Senior Vice President and Chief FinancialOfficer SIGNATURE PAGECONSENT TO FIRST AMENDMENT TO CREDIT AGREEMENTExhibit 10.17STI Award Agreement – STI Award(Leadership)[Black Stone Letterhead][DATE]By [delivery method]Dear [EMPLOYEE],Black Stone Minerals GP, L.L.C., a Delaware limited liability company (the “General Partner”) is pleased to inform you thatyou are eligible to earn a short-term incentive award (the “STI Award”) on the terms and conditions set forth herein and in the BlackStone Minerals, L.P. Long-Term Incentive Plan, as amended from time to time (the “Plan”), which is incorporated herein by reference.Capitalized terms used but not defined herein shall have the meanings set forth in the Plan.Target STI Award:$[●] (the “Target Amount”)Performance Period:January 1, 2018 through December 31, 2018A. Earning of STI AwardSubject to the terms and conditions set forth herein and in the Plan, the STI Award shall become earned in the manner set forthbelow so long as you remain continuously employed by Black Stone Natural Resources Management Company, the General Partner,Black Stone Minerals, L.P., a Delaware limited partnership (the “Partnership”), or any of their respective Affiliates (the “Employer”)from the date hereof through the end of the Performance Period. The extent to which the STI Award becomes earned will bedetermined based on the Partnership’s EBITDAX (as defined below) for the Performance Period determined in accordance with thefollowing table (the “Performance Goals”); provided, however, that notwithstanding any provision herein, the Committee may, in itssole discretion, reduce or increase the amount of the STI Award that actually becomes earned and payable based on individual or teamperformance during the Performance Period. Following the end of the Performance Period, the Committee will determine the level ofachievement of the Performance Goals for the Performance Period. The amount of the STI Award, if any, that actually becomesearned for the Performance Period will be determined by the Committee (and any portion of the STI Award that does not become soearned shall be automatically forfeited). BelowThresholdThresholdTargetMaximumPartnership’s EBITDAX for the PerformancePeriod˂ $[●]$[●]$[●]≥$[●]Percentage of Target Amount that is Earned*0%50%100%200%*If the Partnership’s EBITDAX for the Performance Period is between the amount in the Threshold and Target columns set forth inthe first row of the table above, then the percentage of the Target Amount that is earned shall be determined by linear interpolationbetween Threshold (50%) and Target (100%) based on the Partnership’s EBITDAX for the Performance Period. If the Partnership’sEBITDAX for the Performance Period is between the amount in the Target and Maximum columns set forth in the first row of thetable above, then the percentage of the Target Amount that is earned shall be determined by linear interpolation between Target(100%) and Maximum (200%) based on the Partnership’s EBITDAX for the Performance Period. Each percentage of the TargetAmount that is earned as determined by linear interpolation shall be rounded to four decimal places.As used herein, the term “EBITDAX” means net income or net loss for the Performance Period, determined in accordancewith generally accepted accounting principles in the United States, plus the following expenses or charges to the extent deductedtherefrom: interest, taxes, depreciation, depletion, amortization, impairments and other noncash charges, exploration expenses, delayrental expenses, dry hole expenses, gains/losses on sales of assets, and certain adjustments as determined by the Committee.B. Termination of EmploymentIn the event of a termination of your employment prior to the end of the Performance Period (i) by the Employer without Cause(as defined below), (ii) as a result of your resignation for Good Reason (as defined below), or (iii) as a result of your death or Disability(as defined below), then, subject to your execution of, and non-revocation of, a release in a form acceptable to the General Partner(which release will be provided to you within seven days following the termination of your employment), a portion of the unearnedSTI Award equal to the Target Amount multiplied by a fraction, the numerator of which is the number of days you were employed bythe Employer during the Performance Period and the denominator of which is the number of days in the Performance Period shallbecome earned as of the date on which the Committee makes the determination of the level of achievement of the Performance Goals,as described under “Earning of STI Award” above.As used herein “Cause” has the meaning assigned to such term in your severance agreement with the General Partner or one ofits Affiliates; provided, however, that if you do not have a severance agreement with the General Partner or one of its Affiliates or ifsuch agreement does not define the term “Cause,” then “Cause” means a determination by two-thirds of the Board that you: (i)willfully and continually failed to substantially perform your duties to the Partnership and its Affiliates (other than a failure resultingfrom your Disability); (ii) willfully engaged in conduct that is demonstrably and materially injurious to the Partnership, the GeneralPartner or any of their respective Affiliates, monetarily or otherwise; (iii) have been convicted of, or has plead guilty or nolocontendere to, a misdemeanor involving moral turpitude or a felony; (iv) have committed an act of fraud, or material2embezzlement or material theft, in each case, in the course of you employment relationship with the Employer or one of its Affiliates,or (v) have materially breached any of your obligations under any written agreement (including any non-compete, non-solicitation orconfidentiality covenants) entered into between you and the Partnership, the General Partner or any of their respective Affiliates.Notwithstanding the foregoing, except for a failure, breach or refusal that, by its nature, cannot reasonably be expected to be cured,you shall have 30 days following the delivery of written notice by the Employer or one of its Affiliates within which to cure anyactions or omissions described in clauses (i), (ii), (iv) or (v) constituting Cause; provided, however, that, if the Employer reasonablyexpects irreparable injury from a delay of 30 days, the Employer or one of its Affiliates may give you notice of such shorter periodwithin which to cure as is reasonable under the circumstances, which may include the termination of you employment without noticeand with immediate effect.As used herein, “Disability” means your incapacity, due to accident, sickness or another circumstance that renders you unableto perform the essential functions of your job function, after accounting for reasonable accommodation, for a period of at least 90consecutive days or 120 days in any 12-month period.As used herein, “Good Reason” has the meaning assigned to such term in your severance agreement with the General Partneror one of its Affiliates; provided, however, that if you do not have a severance agreement with the General Partner or one of itsAffiliates or if such agreement does not define the term “Good Reason,” then “Good Reason” means the occurrence of any of thefollowing events without your written consent: (i) a reduction in your total compensation other than a general reduction incompensation that affects all similarly situated employees in substantially the same proportions; (ii) a relocation of your principal placeof employment by more than 50 miles from the location of your principal place of employment as of the date hereof; (iii) any materialbreach by the Partnership or the General Partner of any material provision of this letter; (iv) a material, adverse change in your title,authority, duties or responsibilities (other than due to a Disability); (v) a material adverse change in the reporting structure applicable toyou; or (vi) following a Change of Control, either (x) a failure of the General Partner or one of its Affiliates to continue in effect anybenefit plan or compensation arrangement in which you were participating immediately prior to such Change of Control or (y) thetaking of any action by the General Partner or one of its Affiliates that adversely affects your participation in, or materially reducesyour benefits or compensation under, any such benefit plan or compensation arrangement, unless, in the case of either clause (x) or (y),there is substituted a comparable benefit plan or compensation arrangement that is at least economically equivalent to the benefit planor compensation arrangement being terminated or in which your participation is being adversely affected or your benefits orcompensation are being materially reduced. Notwithstanding the foregoing provisions of this definition or any other provision of theAgreement to the contrary, any assertion by you of a termination for Good Reason shall not be effective unless all of the followingconditions are satisfied: (A) you must provide written notice to the General Partner of the existence of the condition(s) providinggrounds for termination for Good Reason within 30 days of the initial existence of such grounds; (B) the condition(s) specified in suchnotice must remain uncorrected for 30 days following the General Partner’s receipt of such written notice; and (C) the date of yourtermination of employment must occur within 60 days after the initial existence of the condition(s) specified in such notice.3C. SettlementAs soon as administratively practicable following the Committee’s determination of the level of achievement of thePerformance Goals for the Performance Period, but in no event later than March 15 following the end of the Performance Period, theGeneral Partner shall pay or cause to be paid to you a lump-sum cash amount equal to the portion of the STI Award that becomesearned based on the level of achievement of the Performance Goals as determined by the Committee, less any applicable taxwithholding.If you have any questions regarding your STI Award please contact [Kristin Wiggs at (713) 445-3241].Sincerely,BLACK STONE MINERALS GP, L.L.C.By: Name: Steve PutmanTitle:Senior Vice President, General Counsel, and Secretary4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 TexasBSAP II GP, L.L.C. DelawareBSMC GP, L.L.C. DelawareO’Connell Holdings, L.L.C. DelawareO’Connell Partners, L.P. DelawareTLW Investments, L.L.C. 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 28, 2018, 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) of BlackStone Minerals, L.P. for the year ended December 31, 2017./s/ Ernst & Young LLP Houston, TexasFebruary 28, 2018 Exhibit 23.2 Consent of Independent Registered Public Accounting Firm Black Stone Minerals, L.P.Houston, TexasWe hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (No. 333-203909), and Form S-3 (Nos. 333-211426 and 333-215857) of Black Stone Minerals, L.P. of our report dated March 8, 2016, relating to the 2015 consolidated financial statements, which appears in this Form10-K./s/ BDO USA, LLPHouston, TexasFebruary 28, 2018Exhibit 23.3 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, 2017, and the inclusion of our corresponding report letter, dated January 24, 2018, inthe 2017 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 28, 2018 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 28, 2018 /s/ Thomas L. Carter, Jr. Thomas L. Carter, Jr. President, 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 28, 2018 /s/ Jeff Wood Jeff Wood Senior Vice 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 28, 2018 /s/ Thomas L. Carter, Jr. Thomas L. Carter, Jr. President, Chief Executive Officer and Chairman Black Stone Minerals GP, L.L.C.,the general partner of Black Stone Minerals, L.P. Date:February 28, 2018 /s/ Jeff Wood Jeff Wood Senior Vice President and Chief Financial Officer Black Stone Minerals GP, L.L.C.,the general partner of Black Stone Minerals, L.P. Exhibit 99.1January 24, 2018Mr. 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, 2017, to the Black Stone Minerals, L.P. (BlackStone) interest in certain oil and gas properties located in the United States. We completed our evaluation on or about the date of this letter. It is ourunderstanding that the proved reserves estimated in this report constitute all of the proved reserves owned by Black Stone. The estimates in this report havebeen prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of theexclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions arepresented immediately following this letter. This report has been prepared for Black Stone's use in filing with the SEC; in our opinion the assumptions, data,methods, and procedures used in the preparation of this report are appropriate for such purpose.We estimate the net reserves and future net revenue to the Black Stone interest in these properties, as of December 31, 2017, to be: Net Reserves Future Net Revenue (M$) Oil Gas Present WorthCategory (MBBL) (MMCF) Total at 10%Proved Developed Producing 17,779.8 229,339.8 1,206,542.4 757,843.0Proved Developed Non-Producing 111.4 3,676.7 18,846.9 13,131.1Proved Undeveloped 7.9 67,257.5 137,017.2 93,436.2Total Proved 17,899.2 300,274.0 1,362,406.6 864,410.3Totals 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 42 UnitedStates 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. No study wasmade to determine whether probable or possible reserves might be established for these properties. The estimates of reserves and future revenue includedherein have not been adjusted for risk. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tractsfor 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 after deductions forBlack Stone's share of production taxes, ad valorem taxes, capital costs, abandonment costs, and operating expenses but before consideration of any incometaxes. 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 timeon the value of money. Future netrevenue presented in this report, whether discounted or undiscounted, 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 period Januarythrough December 2017. For oil volumes, the average West Texas Intermediate spot price of $51.34 per barrel is adjusted for quality, transportation fees, andmarket differentials. For gas volumes, the average Henry Hub spot price of $2.976 per MMBTU is adjusted for energy content, transportation fees, and marketdifferentials. When applicable, gas prices have been adjusted to include the value for natural gas liquids. All prices are held constant throughout the lives ofthe properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $46.59 per barrel of oil and $2.697per MCF of gas.Operating costs used in this report are based on operating expense records of Black Stone, where available. For other properties, we have estimated operatingcosts based on our knowledge of similar operations in the area. Operating costs include the per-well overhead expenses allowed under joint operatingagreements along with estimates of costs to be incurred at and below the district and field levels. Operating costs have been divided into per-well costs andper-unit-of-production costs. Since all properties are nonoperated, headquarters general and administrative overhead expenses of Black Stone are notincluded. 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 recent activity. Capitalcosts are included as required for workovers, new development wells, and production equipment. Based on our understanding of future development plans, areview of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Abandonment costsused 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 andabandonment 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 condition of thewells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs dueto 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 are based onBlack Stone receiving its net revenue interest share of estimated future gross production. Additionally, we have been informed by Black Stone that they arenot aware of any firm transportation contracts to which Black Stone is a party that contain volume commitments which might represent a liability to thecompany; 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 oil and gas which,by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves arethose additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result ofmarket conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussedherein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with currentdevelopment plans as provided to us by Black Stone, that the properties will be operated in a prudent manner, that no governmental regulations or controlswill be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will proveconsistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimatedamounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred inrecovering such reserves may vary from 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 priceand cost information, and property ownership interests. The reserves in this report have beenestimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oiland Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods,or a combination of methods, including performance analysis, analogy, and material balance, that we considered to be appropriate and necessary tocategorize and estimate reserves in accordance with SEC definitions and regulations. As in all aspects of oil and gas evaluation, there are uncertaintiesinherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed 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 the properties or independentlyconfirmed the actual degree or type of interest owned. The technical person primarily responsible for preparing the estimates presented herein meets therequirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. J. Carter Henson, Jr., a LicensedProfessional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 1989 and has over 8 years of prior industryexperience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are weemployed on a contingent basis. Sincerely, NETHERLAND, SEWELL & ASSOCIATES, INC. Texas Registered Engineering Firm F-2699 /s/ C.H. (Scott) Rees III By: C.H. (Scott) Rees III, P.E. Chairman and Chief Executive Officer /s/ J. Carter Henson, Jr. By: J. Carter Henson, Jr., P.E. 73964 Senior Vice President Date Signed: January 24, 2018 JCH: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 stated in theoriginal document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.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 issupplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASBAccounting Standards 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 the geoscience,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 comparedto the 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 involvinga well.Supplemental definitions from the 2007 Petroleum Resources Management System:Developed Producing Reserves - Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing atthe time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.Developed Non-Producing Reserves - Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected tobe recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which wereshut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves areexpected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start ofDefinitions - Page 1 of 8DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)production. In all cases, production can be initiated or restored with relatively low expenditure compared 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 developmentdrilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developingthe proved 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.(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 oil andgas 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 other expensesof geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical 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 orgas in 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 wellas those items are defined in this section.(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.Definitions - Page 2 of 8DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)(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 operational field.The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader termsof 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); and(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 onthe lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for theproduction function 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 purchaser priorto 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 beDefinitions - Page 3 of 8DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reservesestimates.(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 are lesscertain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reservesmay be assigned to areas that are structurally higher than the proved area if these 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 in placethan 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.Definitions - Page 4 of 8DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)(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, canbe 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)are included 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.(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.Definitions - Page 5 of 8DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)(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 asof the end of the year: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 entityparticipates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (seeparagraph 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 reportingpurposes.932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities aredisclosed in accordance with 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 theyear-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements inexistence at year-end.b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developingand producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economicconditions. If estimated development expenditures 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, withconsideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less thetax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating tothe 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 taxexpenses from future cash inflows.Definitions - Page 6 of 8DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)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 cashflows relating to proved oil and gas reserves.f. Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.(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 estimated tobe 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 geologiccondition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes testsidentified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if notdrilled in a known area or "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 environmentallysensitive locations - by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination mustalways take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extensionbeyond 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 extendpast five years include, but are not limited to, the following:•The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number ofwells necessary to maintain the lease generally would not constitute significant development activities);•The company's historical record at completing development of comparable long-term projects;•The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;•The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its developmentplan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would notbe appropriate); andDefinitions - Page 7 of 8DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)•The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictionson development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources todevelop properties with higher 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 8 of 8

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