Black Stone Minerals Annual Report 2016

Plain-text annual report

UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549FORM 10-K(Mark One)xANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the fiscal year ended December 31, 2016OR¨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 x No ¨ Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No xIndicate 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 x No ¨Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and 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 x No ¨Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to 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, or a smaller reporting company. See the definitions of “largeaccelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check One):Large Accelerated Filer x Accelerated Filer ¨ Non-Accelerated Filer ¨(Do not check if a smaller reporting company) Smaller Reporting Company ¨ Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No xThe aggregate market value of the common units held by non-affiliates was $1,064,853,317 on June 30, 2016, the last business day of the registrant’s most recently completed secondfiscal quarter, based on a closing price of $15.50 per unit as reported by the New York Stock Exchange on such date. As of February 22, 2017, 97,113,310 common units,95,149,984 subordinated units, and 52,691 preferred units of the registrant were outstanding.Documents Incorporated by Reference: Certain information called for in Items 10, 11, 12, 13, and 14 of Part III are incorporated by reference from the registrant’s definitive proxystatement for the annual meeting of unitholders to be held on June 8, 2017. BLACK STONE MINERALS, L.P.TABLE OF CONTENTS PAGEPART I ITEMS 1 AND 2BUSINESS AND PROPERTIES2ITEM 1A.RISK FACTORS29ITEM 1B.UNRESOLVED STAFF COMMENTS47ITEM 3.LEGAL PROCEEDINGS47ITEM 4.MINE SAFETY DISCLOSURES47PART II ITEM 5.MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASESOF EQUITY SECURITIES48ITEM 6.SELECTED FINANCIAL DATA54ITEM 7.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS55ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK72ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA72ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE72ITEM 9A.CONTROLS AND PROCEDURES73ITEM 9B.OTHER INFORMATION73PART III ITEM 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE74ITEM 11.EXECUTIVE COMPENSATION74ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDERMATTERS74ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE74ITEM 14.PRINCIPAL ACCOUNTANT FEES AND SERVICES74PART IV ITEM 15.EXHIBITS AND FINANCIAL STATEMENT SCHEDULES75iiGLOSSARY 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.Electrical log. An analysis that provides information on porosity, hydraulic conductivity, and fluid content of formations drilled in fluid-filled boreholes.Exploitation. A drilling or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has alower risk than that associated with exploration projects.iiiGLOSSARY OF TERMSExploratory well. A well drilled to find and produce natural gas or oil reserves not classified as proved to find a new reservoir in a field previously found tobe productive of natural gas or oil in another reservoir or to extend a known reservoir.Extension well. A well drilled to extend the limits of a known reservoir.Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural featureand/or stratigraphic condition.Formation. A layer of rock which has distinct characteristics that differs from nearby rock.Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.Horizontal drilling. A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle 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.MBbls. One thousand barrels of oil or other liquid hydrocarbons.MBoe. One thousand barrels of oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of oil.MBoe/d. MBoe per day.Mcf. Thousand cubic feet of natural gas.Mineral interests. Real-property interests that grant ownership of the oil and natural gas under a tract of land and the rights to explore for, drill for, 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 working interest owned in gross acres or gross wells, respectively.Net revenue interest. An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty, overriding royalty, and other non-cost-bearing interests.Natural gas. A combination of light hydrocarbons that, in average pressure and temperature conditions, is found in a gaseous state. In nature, it is found inunderground accumulations, and may potentially be dissolved in oil or may also be found in its gaseous state.NGLs. Natural gas liquids.Nonparticipating royalty interest (NPRI). A type of non-cost-bearing royalty interest, which is carved out of the mineral interest and represents the right,which is typically perpetual, to receive a fixed cost-free percentage of production or revenue from production, without an associated right to lease.NYMEX. New York Mercantile Exchange.ivGLOSSARY OF TERMSOil. 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.Reserves. 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). vGLOSSARY OF TERMSReservoir. 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 and is often established by regulatory agencies.Standardized measure. The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordancewith the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, production and income taxexpenses, and discounted at 10% per annum to reflect the timing of future net revenue. Because we are a limited partnership, we are generally not subject tofederal or state income taxes and thus make no provision for federal or state income taxes in the calculation of our standardized measure. Standardizedmeasure does not give effect to derivative transactions.Tight formation. A formation with low permeability that produces natural gas with low flow rates for long periods of time.Trend. A region of oil and/or natural gas production, the geographic limits of which have not been fully defined, having geological characteristics that 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 weight percent that is used as a benchmark for the other crude oils. viCAUTIONARY 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, whichare generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developmentsand their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be noassurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operatingresults are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-lookingstatements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differmaterially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materiallyfrom those in the forward-looking statements include, but are not limited to, those summarized below:•our ability to execute our business strategies;•the volatility of realized oil and natural gas prices;•the level of production on our properties;•regional supply and demand factors, delays, or interruptions of production;•our ability to replace our oil and natural gas reserves;•our ability to identify, complete, and integrate acquisitions;•general economic, business, or industry conditions;•competition in the oil and natural gas industry;•the ability of our operators to obtain capital or financing needed for development and exploration operations;•title defects in the properties in which we invest;•the availability or cost of rigs, equipment, raw materials, supplies, oilfield services, or personnel;•restrictions on the use of water;•the availability of transportation facilities;•the ability of our operators to comply with applicable governmental laws and regulations and to obtain permits and governmental approvals;•federal and state legislative and regulatory initiatives relating to hydraulic fracturing;•future operating results;•future cash flows and liquidity, including our ability to generate sufficient cash to pay quarterly distributions;•exploration and development drilling prospects, inventories, projects, and programs;•operating hazards faced by our operators;•the ability of our operators to keep pace with technological advancements; and•certain factors discussed elsewhere in this Annual Report.For additional information regarding known material factors that could cause our actual results to differ from our projected results, please read Part I,Item 1A. “Risk Factors.”Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligationto publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events, or otherwise.1PART 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 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 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 15.5 million acres, with an average 45.7% ownership interest in that acreage. We also ownnonparticipating royalty interests in 1.5 million acres and overriding royalty interests in 1.5 million acres. These non-cost-bearing interests, which we refer tocollectively as our “mineral and royalty interests,” include ownership in approximately 50,000 producing wells. Our mineral and royalty interests are locatedin 41 states and in 64 onshore basins in the continental United States. Many of these interests are in active resource plays, including the Bakken/Three Forksin the Williston Basin, the Eagle Ford Shale in South Texas, the Wolfcamp/Spraberry/Bone Spring in the Permian Basin, the Niobrara/Codell Shales in the DJbasin, the Haynesville/Bossier Shales in East Texas/Western Louisiana, and the Fayetteville Shale in the Arkoma Basin, as well as emerging plays such as theLower Wilcox play in East Texas and the Canyon Lime play in the Texas Panhandle. The combination of the breadth of our asset base and the long-lived,non-cost-bearing nature of our mineral and royalty interests exposes us to potential additional production and reserves from new and existing plays 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 tothese reports with the U.S. Securities and Exchange Commission (“SEC”). Through our website, http://www.blackstoneminerals.com, we make availableelectronic copies of the documents we file or furnish to the SEC. Access to these electronic filings is available free of charge as soon as reasonably practicableafter filing or furnishing them to the SEC.Our AssetsAs of December 31, 2016, our total estimated proved oil and natural gas reserves were 63,425 MBoe based on a reserve report prepared by Netherland,Sewell & Associates, Inc. (“NSAI”), an independent third-party petroleum engineering firm. Of the reserves as of December 31, 2016, approximately 87.2%were proved developed reserves (approximately 78.2% proved developed producing and 9.0% proved developed non-producing) and approximately 12.8%were proved undeveloped reserves. At December 31, 2016, our estimated proved reserves were 29.0% oil and 71.0% natural gas.The locations of our oil and natural gas properties are presented on the following map. Additional information related to these properties follows thismap. 2 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 therights to explore for, drill for, and produce oil and natural gas on that land or to lease those exploration and development rights to a third party. When thoserights are leased, usually for a three-year term, we typically receive an upfront cash payment, known as lease bonus, and we retain a mineral royalty, whichentitles us to a cost-free percentage (usually ranging from 20% to 25%) of production or revenue from production. A lessee can extend the lease beyond theinitial lease term with continuous drilling, production, or other operating activities. When production or drilling ceases, the lease terminates, allowing us tolease the exploration and development rights to another party. Mineral interests generate the substantial majority of our revenue and are also the assets thatwe 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; and•overriding royalty interests (“ORRIs”), which are royalty interests that burden working interests and represent the right to receive a fixed, cost-freepercentage of production or revenue from production from a lease. ORRIs remain in effect until the associated leases expire.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 we3believe the probability of achieving attractive economic returns is high. A small portion of our working interests, unrelated to our mineral and royalty assets,were acquired because of the attractive working-interest investment opportunities on those properties. The majority of these assets are focused in theAnadarko Basin, and to a lesser extent, in the Permian and Powder River Basins.We collectively refer to these working interests as our “working-interest participation program.” When we participate in non-operated working-interestopportunities, we are required to pay our portion of the costs associated with drilling and operating these wells. Our 2017 drilling capital expenditure budgetassociated with our working-interest participation program is expected to range between $50 and $60 million. Approximately 90% of our 2017 drillingcapital budget will be spent in the Haynesville/Bossier play with the remainder spent in various plays including the Bakken/Three Forks and Wolfcampplays. As of December 31, 2016, we owned non-operated working interests in over 8,500 gross (328 net) wells.Working interest production represented 35.0% of our total production volumes during the year ended December 31, 2016.4Our 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 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 is 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, 2016 Average DailyProduction (Boe/d)For the Year EndedDecember 31, 2016 Mineral and Royalty Interests Working Interests1 USGS Petroleum Province2 Mineral Interests NPRIs ORRIs Gross Net Louisiana-Mississippi Salt Basins 5,446,455 162,199 18,846 49,170 6,203 5,053Western Gulf (onshore) 1,597,765 213,111 98,752 116,134 17,394 6,191Williston Basin 1,323,172 62,133 31,884 54,734 7,741 4,061Palo Duro Basin 1,016,847 22,791 1,120 — — 24Permian Basin 1,016,197 587,167 177,275 8,113 4,731 1,441Anadarko Basin 550,740 13,723 180,157 31,313 21,294 1,909Appalachian Basin 490,274 416 14,836 — — 874East Texas Basin 456,110 44,429 30,640 151,811 51,589 6,906Arkoma Basin 338,767 9,087 37,957 9,045 2,333 1,614Bend Arch-Fort Worth Basin 144,246 55,205 40,249 53,606 13,585 427Southwestern Wyoming 22,338 — 75,577 15,336 2,477 454Other 3,113,014 310,992 798,542 39,408 8,924 2,729Total 15,515,925 1,481,253 1,505,835 528,670 136,271 31,6831 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 throughsouth central 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 thisregion. Approximately half of the Haynesville/Bossier plays’ prospective acreage is within the Louisiana-Mississippi Salt Basins region, where weown significant mineral and royalty interests and working interests. There are a number of additional conventional and unconventional plays in thisregion in which we hold considerable mineral and royalty interests, including the Brown Dense, Cotton Valley, Hosston, Norphlet, Smackover,Tuscaloosa Marine Shale, and Wilcox plays.•Western Gulf (onshore). The Western Gulf region, which ranges from South Texas through southeastern Louisiana, includes a variety of bothconventional and unconventional plays. We have extensive exposure to the Eagle Ford Shale in South Texas, where we are experiencing asignificant level of development drilling on our mineral interests within the oil and rich-gas and condensate areas of the play. In addition to theEagle Ford Shale play, there are a number of other conventional and unconventional plays to which we have exposure to in the region, including theAustin Chalk, Buda, Eaglebine (or Maness) Shale, Frio, Glenrose, Olmos, Woodbine, Vicksburg, Wilcox, and Yegua plays.•Williston Basin. The Williston Basin stretches through the western half of North Dakota, the northwest part of South Dakota, and eastern Montanaand includes plays such as the Bakken/Three Forks plays, where we have significant exposure through our mineral and royalty interests as well asthrough our working interests. We are also exposed to5other well-known plays in the basin, including the Duperow, Mission Canyon, Madison, Ratcliff, Red River, and Spearfish plays.•Palo Duro Basin. The Palo Duro Basin covers much of the Texas Panhandle but also occupies a small portion of the Oklahoma Panhandle andextends partially into New Mexico to the west. We have a significant acreage position in the Palo Duro Basin, much of which underlies anunconventional oil play in the Canyon Lime. We are also well positioned relative to a number of other conventional and unconventional plays in thePalo Duro Basin, including the Brown Dolomite, Canyon Wash, Cisco Sand, and Strawn Wash plays. •Permian Basin. The Permian Basin ranges from southeastern New Mexico into West Texas and is currently one of the most active areas for drilling 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.In addition to these plays, we own mineral and royalty interests that are prospective for a number of other conventional and unconventional plays inthe Permian Basin, including the Atoka, Clearfork, Ellenberger, San Andres, Strawn, and Wichita Albany plays.•Anadarko Basin. The Anadarko Basin encompasses the Texas Panhandle, southeastern Colorado, southwestern Kansas, and western Oklahoma. 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,Big Injun, Devonian, Huron, Rhinestreet, and Utica plays.•East Texas Basin. The East Texas Basin ranges from central East Texas to northeast Texas and includes the Haynesville/Bossier plays and theCotton Valley play, which are among the most prolific natural gas plays in the basin. We own a material acreage position in the southern ShelbyTrough area of the Haynesville/Bossier plays located in San Augustine, Nacogdoches, and Angelina Counties, which is one of the most active areasbeing drilled today for that play in the East Texas Basin. There are other active plays to which we have significant exposure, including the BossierSand, Goodland Lime, James Lime, Pettit, Travis Peak, Smackover, and Woodbine plays. •Arkoma Basin. The Arkoma Basin stretches from southeast Oklahoma through central Arkansas. The Fayetteville Shale play is one of the basin’smost significant unconventional natural gas plays. We own material mineral and royalty interests within the prospective area of the FayettevilleShale. In addition, we have exposure to a number of other conventional and unconventional plays in the basin, including the Atoka, Cromwell,Dunn, Hale, and Woodford Shale plays.•Bend Arch-Fort Worth Basin. The Bend Arch-Fort Worth Basin covers much of north central Texas and includes the Barnett Shale play as its 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.6Interests by USGS Petroleum ProvinceThe following tables present information about our mineral-and-royalty-interest and non-operated working-interest acreage, production, and wellcount by USGS petroleum province.Mineral InterestsThe following table sets forth information about our mineral interests: Average Daily Production (Boe/d) As of December 31, 2016 For the Year Ended December 31,USGS Petroleum Province1 Acres AverageOwnershipInterest2 AverageOwnershipLeased3 2016 2015 2014Louisiana-Mississippi Salt Basins 5,446,455 53.4% 9.6% 3,415 3,384 4,061Western Gulf (onshore) 1,597,765 55.0% 34.7% 4,526 5,021 4,099Williston Basin 1,323,172 14.8% 35.4% 2,534 2,430 1,989Palo Duro Basin 1,016,847 46.5% 7.2% 24 23 16Permian Basin 1,016,197 14.0% 66.6% 1,035 585 566Black Warrior Basin 592,968 54.6% 2.3% — 39 41Eastern Great Basin 567,749 96.7% 0.1% 39 — —Anadarko Basin 550,740 32.7% 59.6% 673 959 790Appalachian Basin 490,274 39.8% 22.1% 163 80 89East Texas Basin 456,110 52.7% 39.4% 1,854 884 793Arkoma Basin 338,767 53.7% 27.6% 1,302 1,458 1,646Western Great Basin 338,303 90.5% – — — —Piedmont 179,879 67.8% – — — —North-Central Montana 171,026 13.7% 27.8% 9 4 7Atlantic Coastal Plain 164,670 12.8% 28.8% 199 — —Bend Arch-Fort Worth Basin 144,246 20.5% 33.3% — 392 252Cherokee Platform 111,027 13.8% 32.4% 34 41 46Florida Peninsula 90,744 12.1% 47.6% 2 — —Illinois Basin 80,864 53.1% 8.0% 3 2 1Powder River Basin 67,055 11.3% 12.3% — 56 3Other 771,067 32.1% 20.4% 1,295 301 317Total 15,515,925 45.7% 22.0% 17,107 15,659 14,7161 The basins and regions shown in the table are consistent with USGS petroleum-province delineations.2 Ownership interest is equal to the percentage that our undivided ownership interest in a tract bears to the entire tract. The average ownership interests shownreflects the weighted averages of our ownership interests in all tracts in the basin or region. Our weighted-average mineral royalty for all of our mineralinterests is approximately 20%, which may be multiplied by our ownership interest to approximate the average royalty interest in our mineral and royaltyinterests.3 The average percent leased reflects the weighted average of our leased acres relative to our total acreage on a tract-by-tract basis in the basin or region. 7NPRIsThe following table sets forth information about our NPRIs: Average Daily Production (Boe/d) As of December 31, 2016 For the Year Ended December 31,USGS Petroleum Province1 Acres AverageRoyaltyInterest2 AveragePercentLeased3 2016 2015 2014Permian Basin 587,167 2.1% 47.5% 19 31 11Western Gulf (onshore) 213,111 4.6% 46.0% 14 10 14Louisiana-Mississippi Salt Basins 162,199 4.9% 48.3% 1 — <1North-Central Montana 134,559 3.0% 9.3% — — —Marathon Thrust Belt 117,442 4.9% 1.6% — — —Williston Basin 62,133 2.6% 33.0% 92 106 64Bend Arch-Fort Worth Basin 55,205 4.1% 12.1% 1 — 3East Texas Basin 44,429 2.7% 80.3% 179 381 2Powder River Basin 33,467 6.1% 7.2% — — —Palo Duro Basin 22,791 3.8% 1.7% — — —Anadarko Basin 13,723 3.6% 94.3% 18 8 2Arkoma Basin 9,087 2.6% 83.8% 13 21 —Cambridge Arch-Central Kansas Uplift 8,903 5.5% 83.7% — — —Southwest Montana 4,367 6.2% 7.3% — — —Cherokee Platform 2,635 4.6% 33.4% — — —Nemaha Uplift 2,334 1.6% 41.4% — — —Montana Thrust Belt 2,242 4.1% – — — —Sedgwick Basin 1,850 2.5% 82.2% — — —Black Warrior Basin 1,500 0.3% 100.0% — — —Uinta-Piceance Basin 560 1.0% – — — —Other 1,549 5.7% 22.6% 180 185 151Total 1,481,253 3.4% 38.4% 518 742 2471 The basins and regions shown in the table are consistent with USGS petroleum-province delineations.2 Average royalty interest is equal to the weighted-average percentage of production or revenues (before operating costs) that we are entitled to on a tract-by-tract basis in the basin or region. NPRIs may be denominated as a “fractional royalty,” which entitles the owner to the stated fraction ofgross production, or a “fraction of royalty,” where the stated fraction is multiplied by the lease royalty. In cases where our landdocumentation does not specify the form of NPRI, we have assumed a fractional royalty for purposes of the average royalty interestsshown above.3 The average percent leased reflects the weighted average of our leased acres relative to our total acreage on a tract-by-tract basis in the basin or region.8ORRIsThe following table sets forth information about our ORRIs: Average Daily Production (Boe/d) As of December 31, 2016 For the Year Ended December 31,USGS Petroleum Province1 Acres AverageRoyaltyInterest2 2016 2015 2014North-Central Montana 457,897 2.5% 13 35 36Anadarko Basin 180,157 2.4% 200 232 253Permian Basin 177,275 0.8% 64 72 60Western Gulf (onshore) 98,752 1.7% 157 262 166Powder River Basin 85,078 3.6% 45 98 50Southwestern Wyoming 75,577 2.0% 451 529 530Uinta-Piceance Basin 63,503 1.6% 24 37 32Michigan Basin 56,512 1.0% 18 21 21Bend Arch-Fort Worth Basin 40,249 4.7% 108 160 166Arkoma Basin 37,957 3.0% 23 29 23San Juan Basin 36,239 1.1% 6 3 3Williston Basin 31,884 2.1% 59 76 54East Texas Basin 30,640 3.6% 96 81 100Northern Alaska 20,039 1.7% 28 32 27Paradox Basin 19,269 1.1% — 2 2Louisiana-Mississippi Salt Basins 18,846 3.3% 705 1,185 903Denver Basin 15,880 3.2% 117 83 91Appalachian Basin 14,836 2.6% 693 — —Wind River Basin 7,090 1.3% 27 33 31Cambridge Arch-Central Kansas Uplift 5,762 3.8% 3 5 4Other 32,393 1.6% 156 911 884Total 1,505,835 2.2% 2,993 3,886 3,4361 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. 9Working InterestsThe following table sets forth information about our non-operated working interests: Average Daily Production (Boe/d) As of December 31, 2016 For the Year Ended December 31,USGS Petroleum Province1 Gross Acres2 Net Acres2 2016 2015 2014East Texas Basin 151,811 51,589 4,776 2,341 1,564Western Gulf (onshore) 116,134 17,394 1,494 1,234 786Williston Basin 54,734 7,741 1,377 1,425 1,386Bend Arch-Fort Worth Basin 53,606 13,585 118 108 129Louisiana-Mississippi Salt Basins 49,170 6,203 932 1,007 2,077Anadarko Basin 31,313 21,294 1,018 1,205 1,402Southwestern Wyoming 15,336 2,477 11 1 6Michigan Basin 13,287 1,330 6 6 6Powder River Basin 13,016 3,389 103 169 121Arkoma Basin 9,045 2,333 277 341 360Permian Basin 8,113 4,731 323 214 204Denver Basin 4,923 1,040 130 5 4Paradox Basin 2,602 1,281 4 5 5North-Central Montana 2,080 605 1 1 1Uinta-Piceance Basin 1,005 482 68 — —San Juan Basin 960 334 15 11 9Wind River Basin 440 43 — — —Southern Oklahoma 390 92 132 174 141Cherokee Platform 328 137 1 5 9Illinois Basin 200 16 — — —Other 177 176 279 128 109Total 528,670 136,272 11,065 8,380 8,3191 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. 10WellsThe following table sets forth information about our mineral-and-royalty-interest and working-interest wells as of December 31, 2016: Mineral and Royalty Interests Working InterestsUSGS Petroleum Province1 Gross Well Count2 USGS Petroleum Province1 Gross Well Count2Permian Basin 21,887 Anadarko Basin 2,777Anadarko Basin 3,672 Uinta-Piceance Basin 1,037Williston Basin 3,034 Permian Basin 796Louisiana-Mississippi Salt Basin 2,981 Arkoma Basin 727East Texas Basin 2,925 Western Gulf (onshore) 595Western Gulf (onshore) 2,887 East Texas Basin 567Arkoma Basin 1,889 Williston Basin 541Uinta-Piceance Basin 1,321 Louisiana-Mississippi Salt Basin 433Bend Arch - Fort Worth Basin 1,173 Southern Oklahoma 408Michigan Basin 971 Bend Arch - Fort Worth Basin 198Appalachian Basin 826 Appalachian Basin 192Southwestern Wyoming 684 Nemaha Uplift 105Cherokee Platform 664 Powder River Basin 66Denver Basin 558 Michigan Basin 62North-Central Montana 532 Denver Basin 21San Juan Basin 530 Cherokee Platform 14Nemaha Uplift 502 North-Central Montana 10San Joaquin Basin 465 Paradox Basin 8Powder River Basin 399 Black Warrior Basin 5Southern Oklahoma 376 Southwestern Wyoming 5Other 1,666 Other 10Total 49,942 Total 8,5771 The basins and regions shown in the table are consistent with USGS petroleum-province delineations.2 We own both mineral and royalty interests and working interests in 3,259 of the wells shown in each column above. 11Material 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 is 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 for63% of our aggregate production for the year ended December 31, 2016. Acreage as of December 31, 20161 Mineral and Royalty Interests Working InterestsResource Play2 Mineral Interests NPRIs ORRIs Gross NetBakken Shale 309,892 36,341 13,210 50,159 7,105Three Forks 296,343 33,522 12,530 50,361 6,732Haynesville Shale 283,401 7,255 14,719 183,337 53,546Bossier Shale 252,458 1,816 8,642 170,716 52,130Marcellus Shale 240,784 — 13,356 — —Canyon Lime 219,279 — — — —Wolfcamp - Midland 187,152 97,860 125,817 160 4Tuscaloosa Marine Shale 181,497 23,397 689 — —Granite Wash 102,786 5,031 86,556 4,840 1,254Fayetteville Shale 71,089 3,918 11,708 — —Barnett Shale 62,732 4,164 36,155 13,417 7,747Eagle Ford Shale 60,743 86,152 48,920 1,147 87Wolfcamp - Delaware 44,520 28,061 4,643 2,642 9711 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. 12Interests by Resource PlayThe following tables present information about our mineral-and-royalty-interest and non-operated working-interest acreage, and production byresource play. As with the acreage shown for the basins and regions above, we may own more than one type of interest in the same tract of land.Consequently, some of the acreage shown for one type of interest below may also be included in the acreage shown for another type of interest.Mineral InterestsThe following table sets forth information about our mineral interests: Average Daily Production (Boe/d) As of December 31, 2016 For the Year Ended December 31,Resource Play1 Acres AverageOwnershipInterest2 AverageOwnershipLeased3 2016 2015 2014Bakken Shale 309,892 18.1% 72.0% 1,659 1,746 1,275Three Forks 296,343 17.7% 73.4% 968 823 626Haynesville Shale 283,401 63.6% 66.7% 3,727 2,728 3,152Bossier Shale 252,458 69.0% 64.6% 330 351 548Marcellus Shale 240,784 14.5% 34.8% 111 71 74Canyon Lime 219,279 30.6% 20.8% 16 8 1Wolfcamp - Midland 187,152 4.8% 97.3% 136 76 27Tuscaloosa Marine Shale 181,497 60.8% 68.0% 52 46 6Granite Wash 102,786 15.2% 57.7% 167 194 241Fayetteville Shale 71,089 55.8% 77.6% 1,181 1,349 1,529Barnett Shale 62,732 15.5% 58.0% 181 239 228Eagle Ford Shale 60,743 15.5% 83.8% 2,095 2,355 1,595Wolfcamp - Delaware 44,520 19.2% 94.9% 437 148 1321 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. 13NPRIsThe following table sets forth information about our NPRIs: Average Daily Production (Boe/d) As of December 31, 2016 For the Year Ended December 31,Resource Play1 Acres AverageRoyaltyInterest2 AveragePercentLeased3 2016 2015 2014Wolfcamp - Midland 97,860 0.7% 75.3% 11 22 5Eagle Ford Shale 86,152 1.5% 28.4% 14 3 7Bakken Shale 36,341 1.4% 51.3% 63 56 37Three Forks 33,522 1.2% 54.8% 36 50 27Wolfcamp - Delaware 28,061 0.4% 83.1% 4 1 2Tuscaloosa Marine Shale 23,397 0.5% 93.2% — — —Haynesville Shale 7,255 4.1% 97.1% 167 325 —Granite Wash 5,031 0.8% 100.0% 16 5 <1Barnett Shale 4,164 2.7% 86.9% 1 — 2Fayetteville Shale 3,918 0.1% 100.0% 13 — —Bossier Shale 1,816 2.8% 54.1% 11 53 —Canyon Lime — – – — — —Marcellus Shale — – – — — —1 The plays above have been delineated based on information from the EIA, the USGS, or state agencies, or according to areas of the most active 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 grossproduction, or a “fraction of royalty,” where the stated fraction is multiplied by the lease royalty. In cases where our landdocumentation does not specify the form of NPRI, we have assumed a fractional royalty for purposes of the average royalty interestsshown above.3 The average percent leased reflects the weighted average of our leased acres relative to our total acreage on a tract-by-tract basis in the play. 14ORRIsThe following table sets forth information about our ORRIs: Average Daily Production (Boe/d) As of December 31, 2016 For the Year Ended December 31,Resource Play1 Acres AverageRoyaltyInterest2 2016 2015 2014Wolfcamp - Midland 125,817 0.3% <1 5 3Granite Wash 86,556 1.2% 155 115 191Eagle Ford Shale 48,920 2.2% 95 204 96Barnett Shale 36,155 4.9% 109 158 163Haynesville Shale 14,719 4.4% 686 1,111 816Marcellus Shale 13,356 2.3% 37 6 —Bakken Shale 13,210 1.2% 34 41 27Three Forks 12,530 1.2% 21 27 18Fayetteville Shale 11,708 4.1% — — —Bossier Shale 8,642 4.7% 28 57 60Wolfcamp - Delaware 4,643 2.1% — — —Tuscaloosa Marine Shale 689 7.8% <1 — <1Canyon 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.2 Average royalty interest is equal to the weighted-average percentage of production or revenues (before operating costs) that we are entitled to on a tract-by-tract basis in this play. 15Working InterestsThe following table sets forth information about our working interests. Average Daily Production (Boe/d) As of December 31, 2016 For the Year Ended December 31,Resource Play1 Gross Acres2 Net Acres2 2016 2015 2014Haynesville Shale 183,337 53,546 5,077 2,909 3,136Bossier Shale 170,716 52,130 309 135 199Three Forks 50,361 6,732 491 551 491Bakken Shale 50,159 7,105 864 792 855Barnett Shale 13,417 7,747 87 104 124Granite Wash 4,840 1,254 429 537 647Wolfcamp - Delaware 2,642 971 150 23 33Eagle Ford Shale 1,147 87 76 11 —Wolfcamp - Midland 160 4 1 — 1Canyon Lime — — — — —Fayetteville Shale — — 23 — —Marcellus Shale — — <1 — —Tuscaloosa Marine Shale — — — — —1 The plays above have been delineated based on information from the EIA, the USGS, or state agencies, or according to areas of the most active industrydevelopment.2 Excludes acreage that is not quantifiable due to incomplete seller records.Estimated Proved ReservesEvaluation and Review of Estimated Proved ReservesThe information included in this Annual Report on Form 10-K relating to our estimated proved oil and natural gas reserves is based upon a reservereport prepared by NSAI, a third-party petroleum engineering firm, as of December 31, 2016.NSAI provides worldwide petroleum property analysis services for energy clients, financial organizations, and government agencies. NSAI was founded in1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, thetechnical person primarily responsible for preparing the estimates set forth in the NSAI summary reserve report incorporated herein is Mr. J. Carter Henson, Jr.Mr. Henson, a Licensed Professional Engineer in the State of Texas (License No. 73964), has been practicing consulting petroleum engineering at NSAI since1989 and has over 8 years of prior industry experience. He graduated from Rice University in 1981 with a Bachelor of Science Degree in MechanicalEngineering. As technical principal, Mr. Henson meets or exceeds the education, training, and experience requirements set forth in the Standards Pertainingto the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in judiciouslyapplying industry standard practices to engineering evaluations as well as applying SEC and other industry reserves definitions and guidelines. NSAI doesnot own an interest in us or any of our properties, nor is it employed by us on a contingent basis. A copy of NSAI’s estimated proved reserve report as ofDecember 31, 2016 is attached as an exhibit to this Annual Report.We maintain an internal staff of petroleum engineers and geoscience professionals who worked closely with our third-party reserve engineers to 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 gas16production, well test data, realized commodity prices, and operating and development costs. We also provided ownership interest information with respect toour properties. 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 31 years of reservoir-engineering and operations experience.Our historical proved reserve estimates were prepared in accordance with our internal control procedures. Throughout the year, our technical team 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 ("AFE") estimates received;•Review of actual historical production volumes compared to projections in the reserve report;•Discussion of material reserve variances among our internal reservoir engineers and our Senior Vice President, Engineering and Geology; and•Review of preliminary reserve estimates by our President and Chief Executive Officer with our internal technical staff.Estimation of Proved 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, 2016 are based on deterministic methods. Reasonable certainty can be established using techniques that have been proved effective byactual production from projects in the same reservoir or an analogous reservoir or by using reliable technology. Reliable technology is a grouping of one ormore technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results withconsistency and repeatability in the formation being evaluated or in an analogous formation.In order to establish reasonable certainty with respect to our estimated net proved reserves NSAI employed technologies including, but not limited to,electrical logs, radioactivity logs, core analysis, geologic maps, and available down hole pressure and production data, seismic data, and well test data.Reserves attributable to producing wells with sufficient production history were estimated using appropriate decline curves or other performancerelationships. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using performance fromanalogous wells in the surrounding area and geologic data to assess the reservoir continuity. In addition to assessing reservoir continuity, geologic data fromwell logs, core analyses, and seismic data were used to estimate original oil and natural gas in place.17Summary of Estimated Proved ReservesThe following table presents our estimated proved oil and natural gas reserves: As ofDecember 31, 20161As ofDecember 31, 2015 (Unaudited)(Unaudited)Estimated proved developed reserves2: Oil (MBbls)18,15015,497Natural gas (MMcf)223,057174,555Total (MBoe)55,32744,590Estimated proved undeveloped reserves3: Oil (MBbls)218345Natural gas (MMcf)47,28229,120Total (MBoe)8,0985,198Estimated proved reserves: Oil (MBbls)18,36815,842Natural gas (MMcf)270,339203,675Total (MBoe)63,42549,788Percent proved developed87.2%89.6%1 Estimates of reserves as of December 31, 2016 were prepared using oil and natural gas prices equal to the unweighted arithmetic average of the first-day-of-the-month market price for each month in the period January through December 2016. For oil volumes, the average WTI spot oil price of $42.75 per 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. Reserve estimates do not include any value for probable or possible reserves thatmay exist. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual futureproduction, cash flows, taxes, development expenditures, operating expenses, and quantities of recoverable oil and natural gas may vary substantially fromthese estimates.2 Proved developed reserves of 74 MBoe as of December 31, 2016 were attributable to noncontrolling interests in our consolidated subsidiaries.3 As of December 31, 2016, no proved undeveloped reserves were attributable to noncontrolling interests in our consolidated subsidiaries.Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas thatcannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and 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.”18Additional information regarding our estimated proved reserves can be found in the notes to our consolidated financial statements included elsewherein this Annual Report and the estimated proved reserve report as of December 31, 2016, which are included as exhibits to this Annual Report.Estimated Proved Undeveloped ReservesAs of December 31, 2016, our PUDs comprised 218 MBbls of oil and 47,282 MMcf of natural gas, for a total of 8,098 MBoe. PUDs will be convertedfrom undeveloped to developed as the applicable wells begin production.The following tables summarizes our changes in PUDs during the year ended December 31, 2016 (in MBoe): Proved Undeveloped Reserves (Unaudited)Balance as of December 31, 20155,198Acquisitions of reserves—Extensions and discoveries7,403Revisions of previous estimates548Transfers to estimated proved developed(5,051)Balance as of December 31, 20168,098 There were no PUD reserves acquired during the year ended December 31, 2016. New PUD reserves totaling 7,403 MBoe were added during the yearended December 31, 2016, resulting primarily from development activities in the Haynesville/Bossier and Bakken plays, and proposals for new wells fromour operators in those plays.During the year ended December 31, 2016, we had reductions of 69 Mboe related to wells removed from PUD status as a result of stale permits orupdated operator information. This was offset by increases in previous estimates of 617 Mboe based on performance from offset and analog production. Thisresulted in a total upward revision of 548 Mboe comprised of an increase of 3,507 MMcf natural gas reserves and a decrease of 36 Mbbl of oil reserves.Costs incurred relating to the development of locations that were classified as PUDs at December 31, 2015 were $28.9 million during the year endedDecember 31, 2016. Additionally, during the year ended December 31, 2016, we incurred $42.9 million drilling and completing other wells which were notclassified as PUDs as of December 31, 2015. Estimated future development costs during the year ended December 31, 2017 relating to the development ofPUD reserves at December 31, 2016 are projected to be approximately $35.9 million. All of our PUD drilling locations as of December 31, 2016 are scheduledto be drilled within five years or less from the date the reserves were initially booked as proved undeveloped reserves.We generally do not have evidence of approval of our operators’ development plans. As a result, our proved undeveloped reserve estimates are limitedto those relatively few locations for which we have received and approved an authorization for expenditure and which remained undrilled as of December 31,2016. As of December 31, 2016, approximately 12.8% of our total proved reserves were classified as PUDs.19Oil and Natural Gas Production Prices and Production CostsProduction and Price HistoryFor the year ended December 31, 2016, 31.7% of our production and 53.7% of our oil and natural gas revenues were related to oil and condensateproduction and sales. During the same period, natural gas and natural gas liquids were 68.3% of our production and 46.3% of our oil and natural 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, 2016 2015 2014Production: Oil and condensate (MBbls)1 3,680 3,565 3,005Natural gas (MMcf)1 47,498 41,389 42,273Total (MBoe) 11,596 10,463 10,051Average daily production (MBoe/d) 31.7 28.7 27.5Realized Prices2: Oil and condensate (per Bbl) $38.69 $45.87 $85.65Natural gas and natural gas liquids (per Mcf)1 $2.59 $2.80 $4.91Unit Cost per Boe: Production costs and ad valorem taxes $3.06 $3.42 $4.931 As a mineral-and-royalty interest owner, we are often provided insufficient and inconsistent data by our operators related to NGLs. As a result, we are unableto reliably determine the total volumes of NGLs associated with the production of natural gas on our acreage. As such, the realized prices for natural gasaccount for all value attributable to NGLs. The oil and condensate production volumes and natural gas production volumes do not include NGL volumes.2 Excludes 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. Asof December 31, 2016, we owned mineral and royalty interests or working interests in 55,260 productive wells, which consisted of 34,645 oil wells and20,615 natural gas wells. As of December 31, 2016, we owned mineral and royalty interests in 49,942 productive wells, which consisted of 33,799 oil wellsand 16,143 natural gas wells, and working interests in 8,577 gross productive wells and 328 net productive wells, which consisted of 2,981 gross (58net) productive oil wells and 5,596 gross (270 net) productive natural gas wells. We own both mineral and royalty interests and working interests in 3,259 ofthese wells.20AcreageMineral and Royalty InterestsThe following table sets forth information relating to our acreage for our mineral interests as of December 31, 2016: State Developed Acreage Undeveloped Acreage Total AcreageTexas 345,935 3,942,268 4,288,203Mississippi 4,816 2,389,431 2,394,247Alabama 2,699 2,045,661 2,048,360Arkansas 4,767 1,264,324 1,269,091North Dakota 16,041 994,028 1,010,069Nevada — 792,428 792,428Florida — 744,341 744,341Louisiana 35,354 518,604 553,958Montana 20,765 479,028 499,793Oklahoma 117,952 367,857 485,809Other 81,557 1,348,069 1,429,626Total 629,886 14,886,039 15,515,925 The following table sets forth information relating to our acreage for our NPRIs as of December 31, 2016: State Developed Acreage Undeveloped Acreage Total AcreageTexas 203,655 818,363 1,022,018Montana 11,684 169,409 181,093Mississippi 10,506 62,798 73,304Louisiana 10,508 62,203 72,711North Dakota 18,540 18,616 37,156Arkansas 3,974 29,070 33,044Wyoming 1,360 17,160 18,520New Mexico 14,289 960 15,249Oklahoma 6,976 5,749 12,725Kansas 9,042 2,983 12,025Other 367 3,041 3,408Total 290,901 1,190,352 1,481,253 21The following table sets forth information relating to our acreage for our ORRIs as of December 31, 2016: State Developed Acreage Undeveloped Acreage Total AcreageMontana 295,401 165,496 460,897Texas 292,352 57,002 349,354Wyoming 133,702 40,045 173,747Oklahoma 157,339 2,006 159,345Utah 40,510 26,163 66,673New Mexico 46,151 13,868 60,019Michigan 55,272 1,239 56,511Colorado 27,108 9,899 37,007Louisiana 15,264 17,886 33,150Alaska 7,664 12,375 20,039Other 74,448 14,641 89,089Total 1,145,211 360,620 1,505,831Working InterestsThe following table sets forth information relating to our acreage for our non-operated working interests as of December 31, 2016: Developed Acreage Undeveloped Acreage Total AcreageState Gross Net Gross Net Gross NetTexas 196,818 53,438 148,661 44,391 345,479 97,829North Dakota 43,369 6,381 7,564 763 50,933 7,144Louisiana 31,608 4,114 14,408 1,436 46,016 5,550Wyoming 22,290 4,168 6,358 1,596 28,648 5,764Michigan 13,208 1,330 79 — 13,287 1,330Oklahoma 11,703 3,070 10 3 11,713 3,073Colorado 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 6,536 2,146 1,494 361 8,030 2,507Total 348,135 87,587 180,535 48,685 528,670 136,272 The following table lists the net undeveloped acres, the net acres expiring in the years ending December 31, 2017, 2018, and 2019, and, whereapplicable, the net acres expiring that are subject to extension options: 2017 Expirations 2018 Expirations 2019 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.48,685 17,204 151 12,491 — 1,652 281 22Drilling 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. Theinformation should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the numberof productive wells drilled, the quantities of reserves found, and the economic value. Productive wells are those that produce commercial quantities ofhydrocarbons, whether or not they produce a reasonable rate of return. For the Year Ended December 31, 2016 2015 2014Gross development wells: Productive 47.0 74.0 222.0Dry — 1.0 1.0Total 47.0 75.0 223.0Net development wells: Productive 4.7 2.9 7.3Dry — <0.1 —Total 4.7 2.9 7.3Gross exploratory wells: Productive — — 1.0Dry — — 1.0Total — — 2.0Net exploratory wells: Productive — — <0.1Dry — — —Total — — <0.1 As of December 31, 2016, we had 20 wells in the process of drilling, completing or dewatering, or shut in awaiting infrastructure that are not reflectedin the above table.23Environmental 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 mayrequire the acquisition of a permit before drilling commences, restrict the types, quantities, and concentrations of various substances that can be releasedinto the environment 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 severalliability nature of such laws and regulations could impose liability upon our operators, or us as working-interest owners if the operator fails to perform,regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damageallegedly caused by the release of hazardous substances, hydrocarbons, or other waste products into the environment. In addition, many environmentalstatues contain citizen suit provisions, and environmental groups frequently use these provisions to oppose oil and natural gas exploration anddevelopment activities and related projects. Changes in environmental laws and regulations occur frequently, and any changes that impact our operatorsand result in more stringent and costly pollution control or waste handling, storage, transport, disposal, or cleanup requirements could materially adverselyaffect our business and prospects. Below is a summary of environmental laws applicable to our operators.Waste HandlingThe Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes and regulations promulgated thereunder,affect oil and natural gas exploration, development, and production activities by imposing requirements regarding the generation, transportation, treatment,storage, disposal, and cleanup of hazardous and non- hazardous wastes. With federal approval, the individual states administer some or all of the provisionsof RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development, andproduction of oil and natural gas are exempt from regulation as hazardous wastes under RCRA, these wastes typically constitute “solid wastes” that aresubject to less stringent non-hazardous waste requirements. However, it is possible that RCRA could be amended or the EPA or state environmental agenciescould adopt policies to require oil and natural gas exploration, development, and production wastes to become subject to more stringent waste handlingrequirements. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address EPA’s alleged failure to timelyassess its RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and natural gas wastes from regulation as hazardouswastes under RCRA. The consent decree requires EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteriaregulations pertaining to oil and natural gas wastes or to sign a determination that revision of the regulations is not necessary. Removal of RCRA’sexemption for exploration and production wastes has the potential to significantly increase waste disposal costs, which in turn will result in increasedoperating costs and could adversely impact production on our properties. Administrative, civil, and criminal penalties can be imposed for failure to complywith waste handling requirements. Any changes in the laws and regulations could have a material adverse effect on our operators’ capital expenditures andoperating expenses, which in turn could affect production from our properties and 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 analogousstate laws generally impose strict, joint, and several liability, without regard to fault or legality of the original conduct, on classes of persons who areconsidered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of acontaminated facility (which can include working-interest owners), a former owner or operator of the facility at the time of contamination and those personsthat disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed“responsible parties” may be subject to strict and joint and several liability for the costs of removing or remediating previously disposed wastes (includingwastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to naturalresources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims forpersonal injury and property damage allegedly caused by the hazardous substances released into the environment. Oil and natural gas exploration andproduction activities on our properties use materials that, if released, would be subject to CERCLA and comparable state statutes. Therefore, governmentalagencies or third parties may seek to hold our operators, or24us as working-interest owners if the operator fails to perform, responsible under CERCLA and comparable state statutes for all or part of the costs to clean-upsites 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 theunauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as statewaters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. TheClean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, includingjurisdictional wetlands, unless authorized by an appropriately issued permit. In September 2015, new EPA and U.S. Army Corps of Engineers rules definingthe scope of the EPA’s and the Corps’ jurisdiction became effective. To the extent the rule expands the scope of the CWA’s jurisdiction, our operators couldface increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. The rule has been challenged in court on thegrounds that it unlawfully expands the reach of CWA programs, and implementation of the rule has been stayed pending resolution of the court challenge. Inaddition, spill prevention, control, and countermeasure plan requirements under federal law require appropriate containment berms and similar structures tohelp prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture, or leak. The EPA has also adoptedregulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits forstorm 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 issued 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 operations.Moreover, the SDWA also regulates saltwater disposal wells under the Underground Injection Control Program. Recent concerns related to the operation ofsaltwater disposal wells and induced seismicity have led some states to impose limits on the total volume of produced water such wells can dispose of, orderdisposal wells to cease operations, or limited the construction of new wells. These seismic events have also resulted in environmental groups and localresidents filing lawsuits against operators in areas where the events occur seeking damages and injunctions limiting or prohibiting saltwater disposal wellconstruction activities and operations. A lack of saltwater disposal wells in production areas could result in increased disposal costs for our operators if theyare forced to transport produced water by truck, pipeline, or other method over long distances.Noncompliance with the Clean Water Act, SDWA, or the OPA may result in substantial administrative, civil, and criminal penalties, as well asinjunctive obligations, all of which could affect production from our properties and adversely affect our business and prospects.Air EmissionsThe federal Clean Air Act and comparable state laws and regulations regulate emissions of various air pollutants through the issuance of permits andthe imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants atspecified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permitsand incur capital costs in order to remain in compliance. For example, in August 2012, the EPA adopted new regulations under the Clean Air Act thatestablished new emission control requirements for oil and natural gas production and processing operations. In addition, in October 2015, the EPA loweredthe National Ambient Air Quality Standard, (“NAAQS”) for ozone from 75 to 70 parts per billion for both the 8- hour primary and secondary standards. Stateimplementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit the ability of our operators to obtain such permits,and result in increased expenditures for pollution control equipment, the costs of which could be significant. More recently, in June 2016, the EPA finalizedrules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable25to the oil and natural gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering morestringent air permitting processes and requirements. These laws and regulations may increase the costs of compliance for oil and natural gas producers andimpact production on our properties, and federal and state regulatory agencies can impose administrative, civil, and criminal penalties for non-compliancewith air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. Moreover, obtaining or renewing permits has thepotential to delay the development of oil and natural gas exploration and development projects. All of these factors could impact production on ourproperties 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 healthand the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, requirepreconstruction and operating permits for certain large stationary sources. Facilities required to obtain preconstruction permits for their GHG emissionsalso will be required to meet “best available control technology” standards that will be established on a case-by-case basis. These EPA rulemakings couldadversely affect operations on our properties and restrict or delay the ability of our operators to obtain air permits for new or modified sources. In addition,the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas productionsources in the United States on an annual basis, which include gathering and boosting facilities as well as GHG emissions from completions and workoversof hydraulically fractured wells. Also, in June 2016, the EPA finalized rules that establish new air emission controls for methane emissions from certain new,modified or reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission and storageactivities. The Bureau of Land Management (“BLM”) finalized similar rules in November 2016 that seek to limit methane emissions from oil and natural gasdevelopment on federal and tribal lands through limitations on venting and flaring activities. However, both the U.S. House of Representatives and theSenate have introduced resolutions seeking to repeal the BLM methane rules under the Congressional Review Act and future implementation of the BLMmethane rules is uncertain. In any event, the BLM and the EPA methane rules have substantial similarities with respect to pollution control equipment andleak detection and repair (“LDAR”) requirements. These rules could result in increased compliance costs for our operators and require them to makeexpenditures to purchase pollution control equipment and hire additional personnel to assist with complying with LDAR requirements, such as increasedfrequency of inspections and repairs for certain processes and equipment. Consequently, these and other regulations related to controlling GHG emissionscould have an adverse impact on 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 ofadopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of federal climate legislation, a number of state andregional GHG cap and trade programs have emerged. These programs typically require major sources of GHG emissions to acquire and surrender emissionallowances in return for emitting those GHGs. Although it is not possible at this predict how legislation or new regulations that may be adopted to addressGHG emissions would impact our business, future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, ouroperators’ equipment and operations could require them to incur costs to reduce emissions of GHGs associated with their operations. In addition, substantiallimitations on GHG emissions could adversely affect demand for the oil and natural gas produced from our properties and lower the value of our reserves.Restrictions on emissions of methane or carbon dioxide that may be imposed in various states, as well as state and local climate change initiatives, couldadversely affect the oil and natural gas industry, and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressingGHG emissions would impact our business. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in theEarth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts,and other extreme climatic events; if any of these effects were to occur, they could have a material adverse effect on our properties and operations.26Hydraulic FracturingOur operators engage in hydraulic fracturing. Hydraulic fracturing is a common practice that is used to stimulate production of hydrocarbons fromtight formations, including shales. The process involves the injection of water, sand, and chemicals under pressure into formations to fracture thesurrounding rock and stimulate production. The process is typically regulated by state oil and natural gas commissions, but recently the EPA and otherfederal agencies have asserted jurisdiction over certain aspects of hydraulic fracturing. For example, the EPA has issued final regulations under the federalClean Air Act governing performance standards, including standards for the capture of air released during hydraulic fracturing; proposed in April 2015 toprohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants; and issued in May 2014 anAdvanced Notice of Proposed Rulemaking seeking comment on its intent to develop regulations under the Toxic Substances Control Act to requirecompanies to disclose information regarding the chemicals used in hydraulic fracturing. Also, the BLM finalized rules in March 2015 that impose new ormore stringent standards for performing hydraulic fracturing on federal and tribal lands including, for example, notice to and pre approval by BLM of theproposed hydraulic fracturing activities; development and pre approval by BLM of a plan for managing and containing flowback fluids and produced waterrecovered during the hydraulic fracturing process; implementation of measures designed to protect usable water from hydraulic fracturing activities; andpublic disclosure of the chemicals used in the hydraulic fracturing fluid. The U.S. District Court of Wyoming has temporarily stayed implementation of thisrule. A final decision has not yet been issued.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 thatthe following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or moresevere impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids,chemicals, or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly intogroundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlinedpits. The EPA has not proposed to take any action in response to the report’s findings.Several states where we own interests in oil and gas producing properties, including Colorado, North Dakota, Louisiana, Oklahoma, and Texas, haveadopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances or require the disclosure of thecomposition of hydraulic-fracturing fluids. For example, in Texas, the Texas Railroad Commission (“RRC”) published a final rule in October 2014 governingpermitting or re-permitting of disposal wells that requires, among other things, the submission of information on seismic events occurring within a specifiedradius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or anapplicant of a disposal well permit fails to demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates such a disposalwell is likely to be or determined to be contributing to seismic activity, then the RRC may deny, modify, suspend or terminate the permit application orexisting operating permit for that well. These existing or any new legal requirements establishing seismic permitting requirements or similar restrictions onthe construction or operation of disposal wells for the injection of produced water likely will result in added costs to comply and affect our operators’ rate ofproduction, which in turn could have a material adverse effect on our results of operations and financial position. In addition to state laws, local land userestrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general or hydraulic fracturing in particular. In the event state,local, or municipal legal restrictions are adopted in areas where our operators conduct operations, our operators may incur substantial costs to comply withthese requirements, which may be significant in nature, experience delays, or curtailment in the pursuit of exploration, development, or production activitiesand 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. 27Occupational Safety and Health ActThe OSHA and comparable state laws and regulations govern the protection of the health and safety of employees. In addition, OSHA’s hazardcommunication standard, the Emergency Planning and Community Right to Know Act and implementing regulations, and similar state statutes andregulations require that information be maintained about hazardous materials used or produced in operations on our properties and that this information beprovided 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.Some of our properties may be located in areas that are or may be designated as habitats for endangered or threatened species, and previously unprotectedspecies may later be designated as threatened or endangered in areas where we hold mineral interests. This could cause our operators to incur increased costsarising from species protection measures, delay the completion of exploration and production activities, and/or result in limitations on operating activitiesthat 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 toconfirm quantum of oil and natural gas properties being acquired, lease status, and royalties as well as encumbrances and other related burdens. Dependingon the materiality of properties, we may obtain a title opinion if we believe additional title due diligence is necessary. As a result, title examinations havebeen obtained on a significant portion of our properties. After an acquisition, we review the assignments from the seller for scrivener’s and other errors andexecute and record corrective assignments as necessary.In addition to our initial title work, our operators conduct a thorough title examination prior to leasing and drilling a well. Should our operators’ 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.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: For the Year Ended December 31, 2016 2015 2014Exxon Mobil 11.0% * *Chesapeake Energy Corporation * * 10.0%*Accounted for less than 10% of total revenues for the period indicated.28CompetitionThe oil and natural gas business is highly competitive in the exploration for and acquisition of reserves, the acquisition - of minerals and oil andnatural gas leases, and personnel required to find and produce reserves. Many companies not only explore for and produce oil and natural gas, but alsoconduct midstream and refining operations and market petroleum and other products on a regional, national, or worldwide basis. Certain of our competitorsmay possess financial or other resources substantially larger than we possess. Our ability to acquire additional minerals and properties and to discoverreserves in the future will be dependent upon our ability to identify and evaluate suitable acquisition prospects and to consummate transactions in a highlycompetitive environment. Oil and natural gas products compete with other sources of energy available to customers, primarily based on price. These alternatesources of energy include coal, nuclear, solar and wind. Changes in the availability or price of oil and natural gas or other sources of energy, as well asbusiness conditions, conservation, legislation, regulations, and the ability to convert to alternate fuels and other sources of energy may affect the demand foroil and natural 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.Demand for natural gas is typically higher during the winter, resulting in higher natural gas prices for our natural gas production during our first and fourthquarters. Certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, whichcan lessen seasonal demand fluctuations. Seasonal weather conditions can limit drilling and producing activities and other oil and natural gas operations in aportion of our operating areas. Due to these seasonal fluctuations, our results of operations for individual quarterly periods may not be indicative of theresults that we may 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, 2016, Black StoneManagement had 108 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. 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, our preferred unitholders have priority with respect to rights to share in those distributions over ourcommon and subordinated unitholders for so long as our preferred units are outstanding.We may not generate sufficient cash from operations each quarter to pay the full minimum quarterly distribution to our common and subordinatedunitholders. Our preferred unitholders have priority with respect to rights to share in distributions over our common and subordinated unitholders.Furthermore, our partnership agreement does not require us to pay distributions to our common and subordinated unitholders on a quarterly basis orotherwise. The amount of cash to be distributed each quarter will be determined by the board of directors of our general partner.The amount of cash we have to distribute each quarter principally depends upon the amount of revenues we generate, which are largely dependentupon the prices that our operators realize from the sale of oil and natural gas. The actual amount of cash we will have to distribute each quarter will bereduced by principal and interest payments on our outstanding debt, working-capital requirements, and other cash needs. In addition, we may restrictdistributions, in whole or in part, to fund29replacement capital expenditures, acquisitions, and participation in working interests. If over the long term we do not retain cash for replacement capitalexpenditures in amounts necessary to maintain our asset base, a portion of future distributions will represent a return of capital and the value of our commonunits will be adversely affected, which will eventually cause our cash distributions per unit to decrease. Withholding cash for our capital expenditures mayhave an adverse impact on the cash distributions in the quarter in which amounts are withheld.For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read Part II, Item 5. “Market 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, which mayprevent 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 significantlyupon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response tochanges in supply and demand, market uncertainty, and a variety of additional factors that are beyond our control, including:•the domestic and foreign supply of and demand for oil and natural gas;•market expectations about future prices of oil and natural gas;•the level of global oil and natural gas exploration and production;•the cost of exploring for, developing, producing, and delivering oil and natural gas;•the price and quantity of foreign imports;•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 anycertainty. For example, during the five years prior to December 31, 2016, the spot price for West Texas Intermediate light sweet crude oil, which we refer to asWTI has ranged from a high of $110.62 per Bbl in 2013 to a low of $26.19 per Bbl in 2016. During the same period, the Henry Hub spot market price ofnatural gas has ranged from a low of $1.49 in 2016 to a high of $8.15 per MMBtu in 2014. During 2016, the WTI spot price of oil ranged from $26.19 to$54.01 per Bbl and the Henry Hub spot market price of natural gas ranged from $1.49 to $3.80 per MMBtu. On December 31, 2014, the WTI spot price for oilwas $53.45 per Bbl and the Henry Hub spot market price of natural gas was $3.14 per MMBtu. On December 31, 2015, the WTI spot price for oil was $37.13per Bbl and the Henry Hub spot market price of natural gas was $2.28 per MMBtu. On December 31, 2016, the WTI spot price for oil was $53.75 per Bbl, andthe Henry Hub spot market price of natural gas was $3.71 per MMBtu.30Any 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.This scenario may result in our having to make substantial downward adjustments to our estimated proved reserves, which could negatively impact ourborrowing base and our ability to fund our operations. If this occurs or if production estimates change or exploration or development results deteriorate,successful efforts method of accounting principles may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and 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 have declined substantially from historical highs and may remain depressed for the foreseeable future. Approximately 53.7% of our 2016 oiland natural 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 $53.75 per Bbl on December 31, 2016.The reduction 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 continue to remain depressed for lengthy periods, we may be required to further write down the value of our oiland natural gas properties in addition to impairments taken during 2015 and 2016, and some of our undeveloped locations may no longer be economicallyviable. In addition, sustained low prices for oil will continue to negatively impact the value of our estimated proved reserves and the amount that we areallowed to borrow under our bank credit facility and reduce the amounts of cash we would otherwise have available to pay expenses, fund capitalexpenditures, make distributions to our unitholders, and service our indebtedness.Natural gas prices have declined substantially from historical highs and are expected to remain depressed for the foreseeable future. Approximately68.3% of our 2016 total production was natural gas, on a “Btu-equivalent” basis. Any additional 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 nine years prior to December 31, 2016, natural gas prices at Henry Hub have ranged from a high of $13.31 per MMBtu in 2008 to a low of$1.49 per MMBtu in 2016. On December 31, 2016, the Henry Hub spot market price of natural gas was $3.71 per MMBtu. The reduction in prices has beencaused by many factors, including increases in natural gas production from unconventional (shale) reservoirs, without an offsetting increase in demand. Theexpected increase in natural gas production, based on reports from the EIA, could cause the prices for natural gas to remain at current levels or fall to lowerlevels. If prices for natural gas continue to remain depressed for lengthy periods, we may be required to further write down the value of our oil and natural gasproperties 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 will continue to negatively impact the value of our estimated proved reserves and the amount that we areallowed to borrow under our bank credit facility and reduce the amounts of cash we would otherwise have available to pay expenses, make distributions toour unitholders, and service our indebtedness.Our failure to successfully identify, complete, and integrate acquisitions could adversely affect our growth, results of operations, and cash distributionsto 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;31•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.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, assetdevaluation, 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 on ouracreage by these operators or the failure of our operators to adequately and efficiently develop and operate our acreage could have an adverse effecton our results of operations.Our assets consist of mineral and royalty interests and non-operated working interests. For the year ended December 31, 2016, we received revenuefrom over 1,000 operators. The failure of our operators to adequately or efficiently perform operations or an operator’s failure to act in ways that are in ourbest interests could reduce production and revenues. Our operators are often not obligated to undertake any development activities other than those requiredto maintain their leases on our acreage. In the absence of a specific contractual obligation, any development and production activities will be subject to32their reasonable discretion. Our operators could determine to drill and complete fewer wells on our acreage than is currently expected. The success and timingof drilling 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.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, and the issuance of equity securities.In the future, we may restrict distributions to fund acquisitions and participation in our working interests but eventually we may need capital in excessof the amounts we retain in our business or borrow under our credit facility. We cannot assure you that we will be able to access external capital on 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.33Producing oil and natural gas wells are characterized by declining production rates that vary depending upon reservoir characteristics and otherfactors. Our future oil and natural gas reserves and our operators’ production thereof and our cash generated from operations and ability to make distributionsare highly dependent on the successful development and exploitation of our current reserves. The production decline rates of our properties may besignificantly higher than currently estimated if the wells on our properties do not produce as expected. We may also not be able to find, acquire, or developadditional reserves to replace the current and future production of our properties at economically acceptable terms, which would adversely affect ourbusiness, financial condition, results of operations, and cash distributions to our common and subordinated unitholders.We either have little or no control over the timing of future drilling with respect to our mineral and royalty interests and non-operated workinginterests.Our proved undeveloped reserves may not be developed or produced. Recovery of proved undeveloped reserves requires significant capitalexpenditures and successful drilling operations, and the decision to pursue development of a proved undeveloped drilling location will be made by theoperator and not by us. The reserve data included in the reserve report of our engineer assume that substantial capital expenditures are required to develop thereserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled, or that theresults of the development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop our reserves, or decreases 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, fracking34and completion services, and production equipment could delay or restrict our operators’ exploration and development operations, which in turn could havea material adverse effect on our financial condition, results of operations, and cash distributions to unitholders.The marketability of oil and natural gas production is dependent upon transportation, pipelines, and refining facilities, which neither we nor many 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 gasand assumptions concerning future oil and natural gas prices, production levels, ultimate recoveries, and operating and development costs. As a result,estimated quantities of proved reserves, projections of future production rates, and the timing of development expenditures may be incorrect. Our estimates ofproved reserves and related valuations as of December 31, 2016 were prepared by NSAI, a third-party petroleum engineering firm, which conducted a detailedreview of all of our properties for the period covered by its reserve report using information provided by us. Over time, we may make material changes toreserve estimates taking into account the results of actual drilling, testing, and production. Also, certain assumptions regarding future oil and natural gasprices, production levels, and operating and development costs may prove incorrect. Any significant variance from these assumptions to actual figures couldgreatly affect our estimates of reserves and future cash generated from operations. Numerous changes over time to the assumptions on which our reserveestimates are based, as described above, often result in the actual quantities of oil and natural gas that are ultimately recovered being different from ourreserve estimates.The estimates of reserves as of December 31, 2016 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbonprices received on a field-by-field basis on the first day of each month within the year ended December 31, 2016 in accordance with the SEC guidelinesapplicable to reserve estimates for those periods. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do theyinclude any value for unproved undeveloped acreage.Conservation measures and technological advances could reduce demand for oil and natural gas.Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advancesin fuel 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.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 affectour business. In particular, the loss of the services of one or more members of our executive team could disrupt our business. Further, we do not maintain “keyperson” life insurance policies on any of our executive team or other key personnel. As a result, we are not insured against any losses resulting from the deathof these key individuals.The results of exploratory drilling in shale plays will be subject to risks associated with drilling and completion techniques and drilling results may notmeet our expectations for reserves or production.35Our 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 profilesare established 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 continually imposed increasingly strict requirements for water and air pollution control and solid waste management.Laws and regulations governing exploration and production may also affect production levels. Our operators must comply with federal and state lawsand regulations governing conservation matters, including:•provisions related to the unitization or pooling of the oil and natural gas properties;•the establishment of maximum rates of production from wells;•the spacing of wells;•the plugging and abandonment of wells; and•the removal of related production equipment.Additionally, federal and state regulatory authorities may expand or alter applicable pipeline-safety laws and regulations, compliance with which mayrequire increased capital costs for third-party oil and natural gas transporters. These transporters may attempt to pass on such costs to our operators, which inturn could affect profitability on the properties in which we own mineral and royalty interests.Our operators must also comply with laws and regulations prohibiting fraud and market manipulations in energy markets. To the extent the operatorsof our properties are shippers on interstate pipelines, they must comply with the tariffs of those pipelines and with federal policies related to the use ofinterstate capacity.Our operators may be required to make significant expenditures to comply with the governmental laws and regulations described above. We believethe trend of more expansive and stricter environmental legislation and regulations will continue.36Please read Part I, Items 1 and 2. “Business and Properties—Environmental Matters” for a description of the laws and regulations that affect our operators andthat may affect us. These and other potential regulations could increase the operating costs of our operators and delay production, which could reduce theamount 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 rightsare separated 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 operating restrictionsor 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,particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand, and chemicals under pressure intoformations to fracture the surrounding rock and stimulate production. The federal Safe Drinking Water Act (“SDWA”) regulates the undergroundinjection of substances through the Underground Injection Control (“UIC”) program. Hydraulic fracturing is generally exempt from regulation under theUIC program, and the hydraulic-fracturing process is typically regulated by state oil and natural gas commissions. The U.S. Environmental ProtectionAgency (“EPA”), however, has recently taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UICprogram and issued guidance in February 2014 applicable to hydraulic fracturing involving the use of diesel fuel. The EPA has also issued final regulationsunder the federal Clean Air Act governing performance standards, including standards for the capture of air emissions released during hydraulic fracturing;finalized rules in June 2016 to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants; andissued in May 2015 an Advanced Notice of Proposed Rulemaking seeking comment on its intent to develop regulations under the Toxic SubstancesControl Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. Also, the Bureau of Land Management(“BLM”) finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and tribal landsincluding, for example, notice to and by BLM of the proposed hydraulic fracturing activities; development and by BLM of a plan for managing andcontaining flowback fluids and produced water recovered during the hydraulic fracturing process; implementation of measures designed to protect usablewater from hydraulic fracturing activities; and public disclosure of the chemicals used in the hydraulic fracturing fluid. The U.S. District Court of Wyominghas temporarily stayed implementation of this rule. A final decision has not yet been issued.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. TheEPA has 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 producingproperties, have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances or require thedisclosure of the composition of hydraulic-fracturing fluids. For example, in Texas, the Texas Railroad Commission (“RRC”) published a final rule inOctober 2014 governing permitting or re-permitting of disposal wells that require, among other things, the submission of information on seismic eventsoccurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area inquestion. If the permittee or an applicant of a disposal well permit fails to demonstrate that the injected fluids are confined to the disposal zone or ifscientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the RRC may deny, modify, suspend,or terminate the permit application or existing operating permit for that well. These existing or any new legal requirements establishing seismic permittingrequirements or similar restrictions on the construction or operation of disposal wells for the injection of produced water likely will result37in added costs to comply and affect our operators’ rate of production, which in turn could have a material adverse effect on our results of operations andfinancial position. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling ingeneral or hydraulic fracturing in particular. In the event state, local, or municipal legal restrictions are adopted in areas where our operators conductoperations, our operators may incur substantial costs to comply with these requirements, which may be significant in nature, experience delays, orcurtailment in the pursuit of exploration, development, or production activities and perhaps even be precluded from the drilling of wells.There has been increasing public controversy regarding hydraulic fracturing with regard to increased risks of induced seismicity, the use of 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 further decreased as a result of such redeterminations. Decreases in the available borrowing amount could result from declines in oil and natural gasprices, operating difficulties or increased costs, declines in reserves, lending requirements, or regulations or certain other circumstances. As of December 31,2016, we had outstanding borrowings of $316.0 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 2016 is $500.0 million and the next semi-annual redetermination is scheduled for April 2017.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 abilityto finance 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.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 immediately38due and payable, our ability to make distributions will be inhibited, and our lenders’ commitment to make further loans to us may terminate. We might nothave, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our credit facility are secured bysubstantially all of our assets, and if we are unable to repay our indebtedness under our credit facility, the lenders can seek to foreclose on our assets.The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the oil and natural gas thatour operators produce.In response to findings that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”) present an endangerment to public healthand the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, requirepreconstruction and operating permits for certain large stationary sources. Facilities required to obtain preconstruction permits for their GHG emissions alsowill be required to meet “best available control technology” standards that will be established on a case-by-case basis. These EPA rulemakings couldadversely affect operations on our properties and restrict or delay the ability of our operators to obtain air permits for new or modified sources. In addition,the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas productionsources in the United States on an annual basis, which include gathering and boosting facilities as well as GHG emissions from completions and workoversof hydraulically fractured wells. Also, in June 2016, the EPA finalized rules that establish new air emission controls for methane emissions from certain new,modified, or reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission, and storageactivities. The BLM finalized similar rules in November 2016 that seek to limit methane emissions from oil and natural gas development on federal andtribal lands through limitations on venting and flaring activities. However, both the U.S. House of Representatives and the Senate have introducedresolutions seeking to repeal the BLM methane rules under the Congressional Review Act and future implementation of the BLM methane rules isuncertain. In any event, the BLM and the EPA methane rules have substantial similarities with respect to pollution control equipment and “LDAR”requirements. These rules could result in increased compliance costs for our operators and require them to make expenditures to purchase pollution controlequipment 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 on ourbusiness 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 ofadopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of federal climate legislation, a number of state andregional cap and trade programs have emerged. These programs typically require major sources of GHG emissions to acquire and surrender emissionallowances in return for emitting those GHGs. Although it is not possible at this time to predict how legislation or new regulations that may be adopted toaddress GHG emissions would impact our business, any future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from,our operators’ equipment and operations could require them to incur costs to reduce emissions of GHGs associated with their operations. In addition,substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas produced from our properties and lower the value of ourreserves. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states, as well as state and local climate change initiatives,could adversely affect the oil and natural gas industry, and, at this time, it is not possible to accurately estimate how potential future laws or regulationsaddressing GHG emissions would impact our business. Finally, it should be noted that some scientists have concluded that increasing concentrations ofGHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms,floods, droughts, and other extreme climatic events; if any of these effects were to occur, they could have a material adverse effect on our properties andoperations.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 thehazards and operating risks associated with drilling for and production of oil and natural gas, including the risk of fire, explosions, blowouts, surfacecratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses, andenvironmental hazards such as oil spills, natural gas leaks and ruptures, or discharges of toxic gases. In addition, their operations will be subject to risksassociated with hydraulic fracturing, including any mishandling, surface spillage, or potential underground migration of fracturing fluids, including chemicaladditives. The occurrence of any of these events could result in substantial losses to our operators due to injury or loss of life, severe damage to or destructionof property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties,suspension of operations, and repairs required to resume operations.39In 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 insurancecompany within the time frame required under our insurance policy. We do not have, and do not intend to obtain, coverage for gradual, long-term pollutionevents. In addition, these policies do not provide coverage for all liabilities, and we cannot assure our unitholders that the insurance coverage will beadequate to cover claims that may arise or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered byinsurance could have a material adverse effect on our financial position, results of operations, and cash distributions to unitholders.Title to the properties in which we have an interest may be impaired by title defects.No assurance can be given that we will not suffer a monetary loss from title defects or title failure. Additionally, undeveloped acreage has greater riskof title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, 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 generatedfrom operations to reinvest in our business or to fund acquisitions, and we will rely primarily upon external financing sources, including commercial bankborrowings and the issuance of debt and equity securities, to fund our acquisitions and growth capital expenditures. If we are unable to finance growthexternally, our distribution policy will significantly impair our ability to grow.If we issue additional units in connection with any acquisitions or growth capital expenditures, the payment of distributions on those additional unitsmay increase the risk that we will be unable to maintain or increase our per unit distribution level. Other than limitations restricting our ability to issue unitsranking senior or on parity with our preferred units, there are no limitations in our partnership agreement on our ability to issue additional units, includingunits ranking senior to the common units with respect to distributions. The incurrence of additional commercial borrowings or other debt to finance ourgrowth would result in increased interest expense and required principal repayments, which, in turn, may reduce the cash that we have available to distributeto our unitholders. Please read Part II, Item 5. “Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities—Cash Distribution Policy.”The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion. Our partnership agreementdoes not require us to pay any distributions at all. If we make distributions, our preferred unitholders have priority with respect to rights to share inthose distributions over our common and subordinated unitholders for so long as our 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 preferred units in an amount of approximately $25.00 per preferred unit, (ii) second, to theholders of common units, until each common unit has received the applicable minimum quarterly distribution plus any arrearages from prior quarters, and(iii) third, to the holders of subordinated units, until each subordinated unit has received the applicable minimum quarterly distribution. If the distributions toour common and subordinated unitholders exceed the applicable minimum quarterly distribution per unit, then such excess amounts will be distributed prorata on the common and subordinated units as if they were a single class. The preferred units have a right to further participate (on an as-converted basis) inquarterly distributions in excess of the quarterly preferred distribution40amount under certain circumstances that we do not expect to occur. Even if those additional distributions do occur, considering that the outstandingpreferred units are convertible into only a relatively small number of our total outstanding common and subordinated units, we believe these additionaldistributions payable under those circumstances would not materially adversely affect the per unit distribution rate we would otherwise pay on our commonand subordinated units. Our minimum quarterly distribution is $1.15 per common and subordinated unit on an annualized basis (or $0.26875 per unit on aquarterly basis) for the four quarters ending March 31, 2017. The minimum quarterly distribution will be $1.25 per common and subordinated unit on anannualized basis (or $0.3125 per unit on a quarterly basis) for the four quarters ending March 31, 2018. We expect that we will distribute a substantialmajority of the cash we generate from operations each quarter. However, the board of directors of our general partner could elect not to pay distributions forone or more quarters or at all. Please read Part II, Item 5. “Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of EquitySecurities—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 preferred unitholders havepriority with respect to rights to share in those distributions over our common and subordinated unitholders for so long as our preferred units are outstanding.Please read Part II, Item 5. “Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities—CashDistribution Policy—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 aminimum quarterly distribution merely provides the common unitholders with a specified priority right to distributions before the subordinated unitholdersreceive distributions, if distributions are made with respect to the common and subordinated units.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 anyclass of units then outstanding, other than the limited partners in BSMC prior to the IPO, their transferees, and persons who acquired such units with the priorapproval of the board of directors of our general partner, may not vote on any matter.41Actions 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 havethe purpose or effect of:•enabling holders of subordinated units to receive distributions; or•hastening the expiration of the subordination period.In addition, our general partner may use an initial amount, equal to $137.6 million, which would not otherwise constitute cash generated 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 unitsand our subordinated units, our partnership agreement permits us to borrow funds, which would enable us to make such distribution on all outstanding units.We have a call right that may require common unitholders to sell their common units at an undesirable time or price.If at any point in time prior to the end of the subordination period we have acquired more than 80% of the total number of common units outstanding,we have the right, but not the obligation, to purchase all of the remaining common units at a price equal to the greater of (1) the average of the daily 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 preferred units are outstanding, or at any time after the subordination period has ended.Unitholders may have liability to repay distributions.Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of theDelaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delawarelaw provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew atthe time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Liabilities to partners onaccount of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distributionis permitted.Increases in interest rates may cause the market price of our common units to decline.An increase in interest rates may cause a corresponding decline in demand for equity investments in general, and in particular, for yield-based 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, our partnership agreement does not authorize us to issue units ranking senior to or at parity with ourpreferred units without preferred unitholder approval.Under our partnership agreement, we are authorized to issue an unlimited number of additional interests, including common units, without a vote ofthe unitholders 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;42•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, our partnership agreement does not authorize us to issue securities having preferences or rights with priority over or on a parity with thepreferred units with respect to rights to share in distributions, redemption obligations, or redemption rights without preferred unitholder approval.The market price of our common units could be adversely affected by sales of substantial amounts of our common units in the public or private markets.As of December 31, 2016, we had 95,720,686 common units and 95,164,204 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 elsewherein these risk factors.We have and will continue to incur increased costs as a result of being a publicly traded partnership.As a publicly traded partnership, we have and will continue to incur significant legal, accounting, and other expenses that we did not incur prior to 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 boardof directors or to establish a compensation committee or a nominating and corporate governance committee. In addition, because we are a publicly tradedpartnership, the NYSE does not require us to obtain unitholder approval prior to certain unit issuances. Accordingly, unitholders will not have the sameprotections afforded to stockholders of certain corporations that are subject to all of the NYSE’s corporate governance requirements.Our partnership agreement includes exclusive forum, venue, and jurisdiction provisions. By purchasing a common unit, a limited partner is irrevocablyconsenting to these provisions regarding claims, suits, actions, or proceedings, and submitting to the exclusive jurisdiction of Delaware courts.43Our 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, as well as our not being subject to a material amount ofentity-level taxation by individual states. If the Internal Revenue Service (“IRS”) were to treat us as a corporation for federal income tax purposes orwe were to become subject to entity-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.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 ofthe Code (the “Final Regulations”) were published in the Federal Register. The Final Regulations apply to taxable years beginning on or after January 19,2017 and generally treat income from passive mineral interests (such as44royalty income) as qualifying income. However, there can be no assurance that there will not be further changes to the Treasury Department's interpretation ofthe qualifying income rules in a manner that could impact our ability to qualify as a partnership 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 theexception for certain publicly traded partnerships to be treated as partnerships for federal income tax purposes. We are unable to predict whether any of thesechanges or other proposals will ultimately be enacted or adopted. Any such changes could negatively impact the value of an investment in our commonunits.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;(iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological andgeophysical expenditures. Congress could consider, and could include, some or all of these proposals as part of tax reform legislation, to accompany lowerfederal income tax rates. Moreover, other more general features of tax reform legislation including changes to cost recovery rules and to the deductibility ofinterest expense may be developed that also would change the taxation of oil and gas companies. It is unclear whether these or similar changes will beenacted and, if enacted, how soon any such changes could take effect. The passage of any legislation as a result of these proposals or any similar changes inU.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development, orincrease costs, and any such changes could have an adverse effect on the Company’s financial position, results of operations and cash flows.If the IRS were to contest the 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 matteraffecting us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustainsome or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adverselyaffect the market for our common units and the price at which they trade. Moreover, the costs of any contest between us and the IRS will result in a reductionin cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess andcollect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case our cashavailable for distribution to our unitholders might be substantially reduced.Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our incometax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustmentdirectly from us. To the extent possible under the new rules, our general partner may elect to either pay the taxes (including any appliable penalties andinterest) 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 ourgeneral partner may elect to have our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year underaudit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current unitholders may bearsome or 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 aresult of any such audit adjustment, we are required to make payments of taxes, penalties or interest, our cash available for distribution to our unitholdersmight be substantially reduced. These rules are not applicable for tax years beginning on or prior to December 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 ornot you receive cash distributions from us. For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, you may beallocated taxable income and gain resulting from the sale and our cash45available for distribution would not increase. Similarly, taking advantage of opportunities to reduce our existing debt, such as debt exchanges, debtrepurchases, or modifications of our existing debt could result in “cancellation of indebtedness income” being allocated to our unitholders as taxable incomewithout any increase in our cash available for distribution. You may not receive cash distributions from us equal to your share of our taxable income or evenequal 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 thosecommon units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, ifany, of prior 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 thanyour tax basis in those units, even if the price you receive is less than your original cost. In addition, because the amount realized includes a unitholder’sshare of our nonrecourse liabilities, if you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale.A substantial portion of the amount realized from the sale of your units, whether or not representing gain, may be taxed as ordinary income to youdue to potential recapture items, including depreciation recapture. Thus, you may recognize both ordinary income and capital loss from the sale of your unitsif the amount 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 and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, a portion of our income allocated to organizations that are exempt from federal income tax, includingIRAs and other retirement plans, may be unrelated business taxable income and may be taxable to them. Distributions to non-U.S. persons will be subject towithholding taxes imposed at the highest effective tax rate applicable to such non-U.S. persons, and each non-U.S. person may be required to file UnitedStates federal tax returns and pay tax on their share of our taxable income if it is treated as effectively connected income. If you are a tax-exempt entity or anon-U.S. person, you should consult your 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 andamortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adverselyaffect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common unitsand could have a negative impact on the value of our common units or result in audit adjustments to your tax returns.We generally prorate our items of income, gain, loss, and deduction between transferors and transferees of our common units each month based 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.46A 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.The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of ourpartnership for federal income tax purposes.We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in ourcapital and profits within a twelve-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders,which would result in us filing two tax returns for one calendar year and could result in a significant deferral of depreciation deductions allowable incomputing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may alsoresult in more than twelve months of our taxable income or loss being includable in taxable income for the unitholder’s taxable year that includes ourtermination. Our termination would not affect our classification as a partnership for federal income tax purposes, but it would result in our being treated as anew partnership for federal income tax purposes following the termination. If we were treated as a new partnership, we would be required to make new taxelections and could be subject to penalties if we were unable to determine that a termination occurred. The IRS has announced a relief procedure whereby if apublicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership may be permitted toprovide only a single Schedule K‑1 to unitholders for the two short tax periods included in the year in which the termination occurs.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 andestate, inheritance, or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, evenif you do not live in any of those jurisdictions. We will initially own assets and conduct business in several states, many of which impose a personal incometax and also impose income taxes on corporations and other entities. You may be required to file state and local income tax returns and pay state and localincome taxes in these jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. As we make acquisitions orexpand our business, we may own assets or conduct business in additional states or foreign jurisdictions that impose a personal income tax. It is yourresponsibility to file all 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 notbelieve that 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.47PART 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 initialpublic offering 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 theNYSE, as well as the quarterly distributions per common and subordinated unit paid subsequent to the completion of our initial public offering on May 6,2015. Price Range of Common Units Distributions1 High Low Per Common Unit Per SubordinatedUnit2015 Second Quarter2 $19.00 $16.59 $0.1615 $0.1615Third Quarter $17.50 $13.27 $0.2625 $0.2625Fourth Quarter $16.50 $12.03 $0.2625 $0.18375 2016 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 $0.183751 Represents cash distributions attributable to the quarter. Cash distributions declared in respect of a quarter are paid in the following quarter.2 The price range of our common units includes our $19.00 per common unit initial public offering price on April 30, 2015. Distributions wereprorated for the period from the completion of our initial public offering on May 6, 2015 through June 30, 2015.As of February 22, 2017, there were 97,113,310 common units outstanding held by 462 holders of record. Because many of our common units areheld by brokers and other institutions on behalf of unitholders, we are unable to estimate the total number of unitholders represented by these holders ofrecord. As of February 22, 2017, we had also outstanding 95,149,984 subordinated units, and 52,691 preferred units. There is no established public market inwhich the subordinated units or the preferred units are traded.48Common 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, 2016 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 As of December 31,2016Black Stone Minerals, L.P. $100.00 $78.22 $109.07S&P 500 Index 100.00 99.47 111.37Alerian MLP Index 100.00 66.99 79.25The information in this 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.49Securities 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 January 10, 2017, we closed on the purchase of certain mineral interests using 625,098 common units valued at $11.8 million to fund a portion ofthe purchase price. The remaining portion of the purchase price was funded with cash. The issuance of the common units pursuant to the purchase and saleagreement was made in reliance upon an exemption from the registration requirements of the Securities Act of 1933 pursuant to Section 4(a)(2) thereof. Purchases of Equity Securities by the Issuer and Affiliated PurchasersThe following tables set forth our purchases of our common and subordinated, units during the three months ended December 31, 2016:Purchases of Common UnitsPeriod Total Number ofCommon UnitsPurchased Average PricePaid Per Unit Total Number of CommonUnits Purchased as Part ofPublicly Announced Plans orPrograms Maximum Dollar Value ofCommon Units That May Yet BePurchased Under the Plans orProgramsNovember 1 – November 30, 2016 110,8781 $18.91 — $—December 1 – December 31, 2016 29,0441 $18.55 — $— Purchases of Subordinated UnitsPeriod Total Number ofCommon UnitsPurchased Average PricePaid Per Unit Total Number of CommonUnits Purchased as Part ofPublicly Announced Plans orPrograms Maximum Dollar Value ofCommon Units That May Yet BePurchased Under the Plans orProgramsNovember 1 – November 30, 2016 7,1951 $14.66 — $—1 Includes units withheld to satisfy tax withholding obligations upon the vesting of certain restricted common and subordinated units held by our executiveofficers and certain 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 preferred units in an amount of approximately $25.00 per preferred unit;•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 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 preferred units have a right to further participate(on an as-converted basis) in quarterly distributions in excess of the quarterly preferred distribution amount under certain circumstances that we do not expectto occur. Even if those additional distributions do occur, considering that the outstanding preferred units are convertible into only a relatively small numberof our total outstanding common and subordinated units, we believe these additional distributions payable under those circumstances would not materiallyadversely affect the per unit distribution rate we would otherwise pay on our common and subordinated units. The applicable minimum quarterly distributionfor the periods specified below is as follows: 50 Minimum Quarterly Distribution(per unit)Four Quarters Ending March 31, Per Quarter Annualized2017 0.2875 1.152018 0.3125 1.252019 and thereafter 0.3375 1.35 After 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, and, in certain circumstances, proceeds from future equity and debt issuances. We may also borrow to makedistributions to our unitholders where, for example, we believe that the distribution level is sustainable over the long term, but short-term factors may causecash generated from operations to be insufficient to pay distributions at the applicable minimum quarterly distribution level on our common andsubordinated units. The board of directors of our general partner can change the amount of the quarterly distributions, if any, at any time and from time totime. Our partnership agreement does not require us to pay cash distributions on a quarterly or other basis. Please read Part I, Item 1A. “Risk Factors—RisksInherent in an Investment in Us—The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion.Our partnership agreement does not require us to pay any distributions at all. Therefore, the fact that our partnership agreement includes the concept of aminimum quarterly distribution does not provide any assurance that a distribution will be paid on the common units. If we make distributions, our preferredunitholders have priority with respect to rights to share in those distributions over our common and subordinated unitholders for so long as our preferredunits are outstanding.” For a description of the relative rights and privileges of our preferred units to distributions, please read “—Preferred Units.” 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 expenditures 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.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 preferred unitholders.•Our credit facility restricts our distributions if there is a default under our credit facility or if our borrowing base is lower than the outstanding loansunder our credit facility. Among other covenants, our credit facility requires we maintain a ratio of total debt to EBITDAX of 3.50:1.00 or less and acurrent ratio of 1.00:1.00 or greater. If we are unable to comply with these financial covenants or if we breach any other covenant under our creditfacility or any future debt agreements, we could be prohibited from making distributions notwithstanding our stated distribution policy.51•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 ofour assets.•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. Ifat the 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.Redeemable Preferred UnitsPrior to our liquidation, and while any of our preferred units remain outstanding, cash or other property of the partnership will be distributed 100% toour preferred unitholders until the aggregate Unpaid Preferred Yield (as defined below) of each preferred unit accrued through the last day of the immediatelypreceding calendar quarter has been reduced to zero. Distributions in excess of the aggregate Unpaid Preferred Yield will be distributed 100% to common andsubordinated unitholders, until there has been distributed an aggregate amount in respect of such calendar year equal to 10% of the aggregate Interest FairMarket Value of the outstanding common and subordinated units as of the first day of such calendar year. Any52additional distributions shall be distributed to the common and subordinated unitholders, on the one hand, and the 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 preferred units were converted into or exchanged or exercised for common units and, during the subordination period,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 Fair MarketValue equaled the Value (as defined in our partnership agreement) as of such date, adjusted to reflect any increases in equity value resulting from the deemedconversion, exchange or exercise of convertible securities, and (c) an amount equal to such Value (as defined in our partnership agreement), as so adjusted,were distributed to the unitholders in accordance with the liquidation distribution provisions of the partnership agreement.“Preferred Yield” means a yield on the outstanding preferred units equivalent to a 10% per annum interest rate (subject to adjustment following certainevents of default by the partnership) on an initial investment of $1,000, calculated based on a 365-day year and compounded quarterly.“Unpaid Preferred Yield” means, with respect to each preferred unit and as of any date of determination, an amount equal to the excess, if any, of (a)the cumulative Preferred Yield from the closing of this offering through the date established, over (b) the cumulative amount of distributions made as of thedate established in respect of the preferred unit.53ITEM 6. SELECTED FINANCIAL DATAThe financial information below should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition andResults of Operations” and “Item 8. Financial Statements and Supplementary Data” of this Annual Report. At December 31, 2016 2015 2014 2013 (In thousands, except per unit amounts)Total revenue $260,833 $392,924 $548,321 $463,559Net income (loss) 20,188 (101,305) 169,187 168,963Net income (loss) attributable to the general partner and common unitsand subordinated units subsequent to initial public offering 14,437 (108,017) * *Net income (loss) attributable to limited partners per common andsubordinated unit (basic)1 Per common unit (basic) 0.26 (0.56) * *Per subordinated unit (basic) (0.11) (0.56) * *Net income (loss) attributable to limited partners per common andsubordinated unit (diluted)1 Per common unit (diluted) 0.26 (0.56) * *Per subordinated unit (diluted) (0.11) (0.56) * *Cash distributions declared per common and subordinated unit Per common unit 1.10 0.42 * *Per subordinated unit 0.74 0.42 * *Total assets2 1,128,827 1,061,436 1,326,782 1,444,413Long-term debt 316,000 66,000 394,000 451,000Total mezzanine equity 54,015 79,162 161,165 161,392* Information is not applicable for the periods prior to our IPO.1 See Note 14 – 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.54ITEM 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 consolidated financialstatements and notes thereto presented elsewhere in this Annual Report. This discussion and analysis contains forward-looking statements that involverisks, uncertainties, and assumptions. Actual results may differ materially from those anticipated in these forward-looking statements as a result of a numberof 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 growing quarterly distribution to ourunitholders.On May 6, 2015, we completed our initial public offering of 22,500,000 common units representing limited partner interests. Our common units tradeon the New York Stock Exchange under the symbol "BSM."Our mineral and royalty interests consist of mineral interests in approximately 15.5 million acres, with an average 47.5% ownership interest in thatacreage, NPRIs in 1.5 million acres, and ORRIs in 1.5 million acres. These non-cost-bearing interests include ownership in over 50,000 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 Developments2016 Commodity PricesOil and natural gas commodity pricing generally constitutes the largest single variable that impacts our operating results. The volatility in the value ofthese commodities is reflected in the fact that the 2016 WTI oil spot price ranged from a low of $26.19 per Bbl to a high of $54.01 per Bbl and the 2016Henry Hub natural gas spot price ranged from a low of $1.49 per MMBtu to a high of $3.80 MMBtu. Despite the negative financial impacts of a lowcommodity price environment, our active marketing of mineral interests, effective commodity hedging practices, and diligent monitoring of expenses andcapital spending enabled us to generate favorable 2016 operating results.2016 AcquisitionsOn January 8, 2016, we acquired mineral and royalty interests in the Permian Basin for $10.0 million. On June 15, 2016, we acquired an oil andnatural gas mineral package primarily located in Weld County, Colorado for $34.0 million. On June 17, 2016, we acquired a diverse oil and natural gasmineral asset package from Freeport-McMoRan Oil and Gas Inc. and certain of its affiliates for $87.6 million. On August 8, 2016, we acquired mineralinterests located in Midland and Glasscock Counties of Texas for $8.3 million. Throughout 2016, we acquired certain other oil and natural gas assets forapproximately $1.2 million in the aggregate. These transactions met targeted acquisition volumes that were included in our budget and provided near termproduction and cash flow as well as future development potential that will fuel our planned distribution growth.2017 AcquisitionsDuring January 2017, the Partnership closed four mineral interest transactions in Loving County, Texas for approximately $32.0 million in cash, withborrowings from the Senior Credit facility, and $11.8 million of the Partnership's common units. Two Haynesville/Bossier Shale mineral interest transactionsclosed for $6.4 million. Two additional mineral interest acquisitions closed in Angelina County, Texas for approximately $8.6 million.55Farmout AgreementOn 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 average 50% workinginterest in the acreage and is the largest mineral owner. A total of 58 wells are anticipated to be drilled over an initial phase, beginning with wells spud afterJanuary 1, 2017. At its option, Canaan may participate in two additional phases with each phase estimated to last approximately two years. During the threephases 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 assigned80% of the Partnership's working interests in such wells (40% working interest on an 8/8ths basis). After the third phase, Canaan can earn 40% of thePartnership’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'scosts for those wells on a well-by-well basis. The Partnership will receive a base overriding royalty interest (“ORRI”) before payout and an additional ORRIafter payout on all wells drilled under the agreement. The execution of this agreement is anticipated to reduce the Partnership's future capital obligations byapproximately $30-$35 million in 2017 and by an average of $40-$50 million annually, thereafter.Common Unit Repurchase ProgramOn March 4, 2016, the Board of Directors of our general partner (the “Board”) authorized the repurchase of up to $50.0 million in common unitsthrough a program that terminated on September 15, 2016. The repurchase program authorized us to make repurchases on a discretionary basis as determinedby management, subject to market conditions, applicable legal requirements, available liquidity, and other appropriate factors. We repurchased a total of 1.3million common units for an aggregate cost of $20.2 million. The repurchase program was funded from our cash on hand or available revolving creditfacility. Repurchased common units were canceled.Business EnvironmentThe information below is designed to give a broad overview of the oil and natural gas business environment as it affects us.Commodity Prices and DemandOil and natural gas prices have been historically volatile based upon the dynamics of supply and demand. Recently, oil and natural gas prices haveremained significantly below prices seen over the past five years. The EIA expects the pace of inventory builds to slow considerably in 2017 and 2018. TheEIA also believes that continuing global inventory builds will contribute to oil prices remaining below $60 per Bbl through the end of 2018. During the yearended December 31, 2016, the WTI spot price reached a low of $26.19 per Bbl on February 11, 2016 but rebounded to a high of $54.01 per Bbl on December28, 2016.The EIA expects residential and commercial natural gas consumption to increase by 6.0% and 5.2%, respectively, in 2017; in 2018, residential andcommercial consumption are projected to be roughly unchanged from anticipated 2017 levels. Natural gas pipeline exports increased in 2016, largely due toshipments to Mexico. The EIA forecasts pipeline exports of natural gas will continue to rise due to growing demand from Mexico's electric power sector andflat natural gas production in that country. Liquified natural gas ("LNG") gross exports increased in 2016 due to the startup of Cheniere Energy, Inc's SabinePass LNG in Louisiana. LNG exports are expected to increase in 2017 as Sabine Pass ramps up capacity in the middle of the year. Growth in 2018 isanticipated to be driven by the start of Dominion Recourses, Inc.'s Cove Point facility in Maryland in December 2017 and new projects at Cameron LNG andFreeport LNG during the second half of 2018. The EIA expects natural gas inventory levels to be below the previous five-year average through much of thewinter period, putting upward pressure on natural gas prices. During the year ended December 31, 2016, Henry Hub spot natural gas prices ranged from a lowof $1.49 per MMBtu on March 4, 2016 to a high of $3.80 per MMBtu on December 7, 2016.To manage the variability in cash flows associated with the projected sale of our oil and natural gas production, we use various derivative instruments,which have recently consisted of fixed-price swap contracts. 56The following table reflects commodity prices at the end of each quarter presented: 2016Benchmark Prices FourthQuarter ThirdQuarter SecondQuarter FirstQuarterWTI spot oil ($/Bbl) $53.75 $47.72 $48.27 $36.94Henry Hub spot natural gas ($/MMBtu) $3.71 $2.84 $2.94 $1.98 Source: EIA Rig CountAs we are not an operator, drilling on our acreage is dependent upon the exploration and production companies that lease our acreage. In addition todrilling plans that we seek from our operators, we also monitor rig counts in an effort to identify existing and future leasing and drilling activity on ouracreage.The following table shows the rig count at the close of each quarter presented: 2016U.S. Rotary Rig Count FourthQuarter ThirdQuarter SecondQuarter FirstQuarterOil 525 425 330 372Natural gas 132 96 90 92Other 1 1 1 —Total 658 522 421 464 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 demandis lower, 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. According to the EIA, naturalgas inventories reached a record high of 4,047 Bcf during mid-November 2016; however, subsequent draws were larger than normal and inventories endedDecember below the previous five-year average for the first time since the end of April 2015. The EIA believes that March 2017 through October 2017inventories will build at a slower pace than the five-year average. In 2018, the EIA expects inventories to follow the typical seasonal pattern.The following table shows natural gas storage volumes by region at the close of each quarter presented: 57 2016Region FourthQuarter ThirdQuarter SecondQuarter FirstQuarter (Bcf)East 737 899 632 439Midwest 921 1,045 742 555Mountain 207 237 198 147Pacific 275 318 315 262South Central 1,171 1,181 1,253 1,065Total 3,311 3,680 3,140 2,468Source: EIAHow 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•EBITDA, Adjusted EBITDA, and cash available for distribution.Volumes of Oil and Natural Gas ProducedIn order to assess and track the performance of our assets, we monitor and analyze production volumes from the various basins and plays that compriseour extensive asset base. We also regularly compare projected volumes to actual reported volumes and investigate unexpected variations.Commodity PricesFactors Affecting the Sales Price of Oil and Natural GasThe prices we receive for oil, natural gas, and natural gas liquids (“NGLs”) vary by geographical area. The relative prices of these products aredetermined by the factors affecting global and regional supply and demand dynamics, such as economic conditions, production levels, availability oftransportation, weather cycles, and other factors. In addition, realized prices are influenced by product quality and proximity to consuming and refiningmarkets. Any differences between realized prices and NYMEX prices are referred to as differentials. All of our production is derived from properties located inthe United States. As a result of our geographic diversification, we are not exposed to concentrated differential risks associated with any single play, trend, orbasin.•Oil. The substantial majority of our oil production is sold at prevailing market prices, which fluctuate in response to many factors that areoutside of our control. NYMEX light sweet crude oil, commonly referred to as WTI, is the prevailing domestic oil pricing index. The majorityof our oil production is priced at the prevailing market price with the final realized price affected by both quality and location differentials.The chemical composition of crude oil plays an important role in its refining and subsequent sale as petroleum products. As a result,variations in chemical composition relative to the benchmark crude oil, usually WTI, will result in price adjustments, which are often referredto as quality differentials. The characteristics that most significantly affect quality differentials include the density of the oil, as characterizedby its American Petroleum Institute (“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 andmajor trading points.58•Natural Gas. The NYMEX price quoted at Henry Hub is a widely used benchmark for the pricing of natural gas in the United States. Theactual volumetric prices realized from the sale of natural gas differ from the quoted NYMEX price as a result of quality and locationdifferentials. Quality differentials result from the heating value of natural gas measured in Btus and the presence of impurities, such as hydrogen sulfide,carbon dioxide, and nitrogen. Natural gas containing ethane and heavier hydrocarbons has a higher Btu value and will realize a highervolumetric price than natural gas which is predominantly methane, which has a lower Btu value. Natural gas with a higher concentration ofimpurities will realize a lower volumetric price due to the presence of the impurities in the natural gas when sold or the cost of treating thenatural gas to meet pipeline quality specifications.Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply and demandconditions and the cost to transport natural gas to end user markets.HedgingWe enter into derivative instruments to partially mitigate the impact of commodity price volatility on our cash generated from operations. From timeto time, such instruments may include fixed-price swaps, fixed-price contracts, costless collars, and other contractual arrangements. We generally employ a“rolling hedge” strategy whereby we hedge a significant portion of our proved developed producing reserves 12 to 24 months into the future. 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 for any settlement period is less than the swapstrike price. Conversely, we are required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap strikeprice. We may employ contractual arrangements other than fixed-price swap contracts in the future to mitigate the impact of price fluctuations. If commodityprices decline in the future, our hedging contracts will partially mitigate the effect of lower prices on our future revenue.Our open oil and natural gas derivative contracts as of December 31, 2016 and as of the date of this filing are detailed in Note 5 – Derivatives andFinancial Instruments to our consolidated financial statements included elsewhere in this Annual Report. Our credit agreement limits the extent to which wecan hedge our future production. Under the terms of our credit agreement, we are able to hedge substantially all of our estimated production from our proveddeveloped producing reserves based on the most recent reserve information provided to our lenders. We do not enter into derivative instruments forspeculative purposes. Including derivative contracts entered into after December 31, 2016, we have hedged 90.3% and 97.2% of our available oil andcondensate hedge volumes and 91.1% and 60.3% of our available natural gas hedge volumes for 2017 and 2018, respectively.Non-GAAP Financial MeasuresEBITDA, Adjusted EBITDA, and cash available for distribution are supplemental non-GAAP financial measures used by our management andexternal users of our financial statements such as investors, research analysts, and others, to assess the financial performance of our assets and our ability tosustain distributions over the long term without regard to financing methods, capital structure, or historical cost basis.We define EBITDA as net income (loss) before interest expense, income taxes and depreciation, depletion, and amortization. We define AdjustedEBITDA as EBITDA adjusted for impairment of oil and natural gas properties, accretion of ARO, unrealized gains and losses on commodity derivativeinstruments, and non-cash equity-based compensation. We define cash available for distribution 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 preferredunitholders.EBITDA, Adjusted EBITDA, and cash available for distribution should not be considered an alternative to, or more meaningful than, net income (loss),income (loss) from operations, cash flows from operating activities, or any other measure of financial performance presented in accordance with GAAP asmeasures of our financial performance. EBITDA, Adjusted EBITDA, and cash available for distribution have important limitations as analytical tools becausethey exclude some but not all items that affect net income (loss), the most directly comparable GAAP financial measure. Our computation of EBITDA,Adjusted EBITDA, and cash available for distribution may differ from computations of similarly titled measures of other companies.The following table presents a reconciliation of EBITDA, Adjusted EBITDA, and cash available for distribution to net income, the most directlycomparable GAAP financial measure, for the periods indicated. 59 Year Ended December 31, 2016 2015 2014 (In thousands)Net income (loss) $20,188 $(101,305) $169,187Adjustments to reconcile to Adjusted EBITDA: Add: Depreciation, depletion and amortization 102,487 104,298 111,962Interest expense 7,547 6,418 13,509EBITDA 130,222 9,411 294,658Add: Impairment of oil and natural gas properties 6,775 249,569 117,930Accretion of asset retirement obligations 892 1,075 1,060Equity-based compensation1 43,138 18,000 11,340Unrealized loss on commodity derivative instruments 81,253 — —Less: Unrealized gain on commodity derivative instruments — (27,063) (39,283)Adjusted EBITDA 262,280 250,992 385,705Adjustments to reconcile to cash generated from operations: Add: Restructuring charges — 4,208 —Incremental general and administrative related to initial public offering — 1,303 —Loss on sales of assets, net — — 32Less: Deferred revenue (870) (660) (2,589)Cash interest expense (6,676) (5,483) (12,544)Gain on sales of assets, net (4,793) (4,873) —Estimated replacement capital expenditures2 (11,250) — —Cash generated from operations 238,691 245,487 370,604Less: Cash paid to noncontrolling interests (111) (208) (307)Redeemable preferred unit distributions (5,763) (11,562) (15,720)Cash generated from operations available for distribution on common and subordinated units and reinvestment in our business $232,817 $233,717 $354,577 1 On April 25, 2016, the Compensation Committee of the Board approved a resolution to change the settlement feature of certain employee long-term incentive compensation plansfrom cash to equity. As a result of the modification, $10.1 million of cash-settled liabilities were reclassified to equity-settled liabilities during the second quarter of 2016.2 On August 3, 2016, the Board established a replacement capital expenditures estimate of $15.0 million for the period of April 1, 2016 to March 31, 2017. There was no establishedestimate of replacement capital expenditures prior to this period. 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.60Results of OperationsYear Ended December 31, 2016 Compared to Year Ended December 31, 2015The following table shows our production, revenues, and 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)1 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 sales 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)%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 are unable to reliably determinethe total volumes of NGLs associated with the production of natural gas on our acreage. Accordingly, no NGL volumes are included in our reported production; however, revenueattributable to NGLs is included in our natural gas revenue and our calculation of realized prices for natural gas.RevenuesThe $132.1 million decrease in total revenues for the year ended December 31, 2016 compared to the year ended December 31, 2015 was due to$126.8 million of losses attributable to commodity derivative instruments and $36.7 million lower realized commodity prices, partially offset by $22.4million related 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 year endedDecember 31, 2016 and the year ended December 31, 2015, respectively. Our oil and condensate volumes increased in 2016 relative to 2015 primarily drivenby production increases from new wells in the Bakken/Three Forks, Wilcox, and Wolfcamp plays.Natural gas and natural gas liquids sales. Natural gas revenues increased for the year ended December 31, 2016 as compared to 2015. During 2016,increases in production from our Haynesville and Wilcox properties served to more than61mitigate the impact of further depressed realized natural gas and NGL prices. Mineral-and-royalty-interest production made up 59.3% and 67.3% of ournatural gas volumes for the year ended December 31, 2016 and 2015, respectively. 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 Expenses Lease operating expenses. Lease operating expense includes normally recurring expenses necessary to produce hydrocarbons from our non-operatedworking interests in oil and natural gas wells, as well as certain nonrecurring expenses, such as well repairs. Lease operating expense decreased for the yearended December 31, 2016 as compared to 2015, primarily due to lower workover expense, realized cost efficiencies resulting from the currently depressedindustry market, the plugging of certain uneconomical working interest wells, and 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, 2016, production and ad valorem taxes increased over the year ended December 31, 2015,generally as a result of higher production volumes.Exploration expense. Exploration expense typically consists of dry-hole expenses and geological and geophysical costs, including seismic costs, andis expensed as incurred under the successful efforts method of accounting. Exploration expense for the years ended December 31, 2016 and 2015 primarilyresulted from costs incurred to acquire 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, 2016 as compared to 2015, primarily due to higher production rates offset by the impact of a reduced cost basis resulting fromimpairment charges related to prior periods.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. Impairments of $250.0 million for the yearended December 31, 2015 primarily resulted from changes in reserve values due to declines in future expected realized net cash flows as a result of lowercommodity prices. Impairments of $6.8 million for 2016 were insignificant.General and administrative. General and administrative expenses are costs not directly associated with the production of oil and natural gas andinclude the cost of employee salaries and related benefits, office expenses, and fees for professional services. For the year ended December 31, 2016, generaland administrative expenses decreased compared to 2015. In 2016, personnel costs and costs attributable to our long-term incentive plans were lowerprimarily due to one-time incentive compensation awards granted in 2015 as 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 compliance project and other consulting work during 2015.62Interest expense. Interest expense increased due to higher average outstanding borrowings under our credit facility. Outstanding borrowings during2016 were higher than 2015, primarily due to additional loan proceeds for multiple acquisitions, preferred unit redemptions, and common unit repurchases.63Year Ended December 31, 2015 Compared to Year Ended December 31, 2014The following table shows our production, revenues, and expenses for the periods presented: Year Ended December 31, 2015 2014 Variance (Dollars in thousands, except for realized prices and per BOE data)Production: Oil and condensate (MBbls)1 3,565 3,005 560 18.6 %Natural gas (MMcf)1 41,389 42,273 (884) (2.1)%Equivalents (MBoe) 10,463 10,051 $412 4.1 %Revenue: Oil and condensate sales $163,538 $257,390 $(93,852) (36.5)%Natural gas and natural gas liquids sales 116,018 207,456 (91,438) (44.1)%Gain (loss) on commodity derivative instruments 90,288 37,336 52,952 141.8 %Lease bonus and other income 23,080 46,139 (23,059) (50.0)%Total revenue $392,924 $548,321 $(155,397) (28.3)%Realized prices: Oil and condensate ($/Bbl) $45.87 $85.65 $(39.78) (46.4)%Natural gas ($/Mcf)1 $2.80 $4.91 $(2.11) (43.0)%Equivalents ($/Boe) $26.72 $46.25 $(19.53) (42.2)%Operating expenses: Lease operating expense $21,583 $21,233 $350 1.6 %Production costs and ad valorem taxes 35,767 49,575 (13,808) (27.9)%Exploration expense 2,592 631 1,961 310.8 %Depreciation, depletion, and amortization 104,298 111,962 (7,664) (6.8)%Impairment of oil and natural gas properties 249,569 117,930 131,639 111.6 %General and administrative 77,175 62,765 14,410 23.0 %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 are unable to reliably determinethe total volumes of NGLs associated with the production of natural gas on our acreage. Accordingly, no NGL volumes are included in our reported production; however, revenueattributable to NGLs is included in our natural gas revenue and our calculation of realized prices for natural gas. RevenuesThe decrease in total revenues for the year ended December 31, 2015 compared to the year ended December 31, 2014 was due to a decrease of $228.9million from lower realized commodity prices and $23.1 million of reduced lease bonus activity, partially offset by $52.9 million of gains attributable tocommodity derivative instruments and $43.6 million related to higher oil and condensate production volumes.Oil and condensate sales. Oil and condensate sales during 2015 were lower than the corresponding period in 2014 primarily due to a steep decline inrealized prices. Our mineral-and-royalty-interest oil volumes accounted for 76.8% and 74.7% of total oil and condensate volumes for the year endedDecember 31, 2015 and the year ended December 31, 2014, respectively. Our mineral-and-royalty-interest oil volumes increased in 2015 relative to 2014primarily driven by production increases from new wells in the Bakken/Three Forks and Eagle Ford plays. Our working-interest oil and condensate volumesincreased during 2015 versus 2014 primarily due to volumes added from new wells in the Bakken/Three Forks and Wilcox plays.Natural gas and natural gas liquids sales. Natural gas revenues decreased for the year ended December 31, 2015 as compared to 2014. A significantdecline in the realized natural gas and NGL prices for the year ended December 31, 2015 versus the corresponding period in 2014 was primarily responsiblefor the decrease in our natural gas and NGL revenues.64Mineral-and-royalty-interest production made up 67.3% and 67.8% of our natural gas volumes for the year ended December 31, 2015 and 2014, respectively. Gain on commodity derivative instruments. In 2015, we recognized $57.7 million of gains from oil commodity contracts, of which $15.9 million wererealized, compared to $27.5 million of combined gains in 2014, virtually all of which were unrealized. In 2015, we recognized $32.6 million of gains fromnatural gas commodity contracts, of which $11.2 million were unrealized, compared to $9.8 million of net gains in 2014, of which $11.8 million wereunrealized gains.Lease bonus and other income. Lease bonus and delay rental revenue decreased for the year ended December 31, 2015 as compared to 2014. In 2014,we successfully closed several large leases in the Canyon Lime and Canyon Wash plays in north Texas, the Permian Basin in west Texas, the Austin Chalkand Woodbine play in east Texas, the Tuscaloosa Marine Shale play in Mississippi and the Bakken play in North Dakota. While we closed large leasetransactions in 2015 in Wolfcamp, Eagle Ford Shale, and various plays in East Texas and in Southern Mississippi, the total number of leases was downsignificantly from 2014.Operating Expenses Lease operating expenses. Lease operating expense increased slightly for the year ended December 31, 2015 as compared to 2014, primarily due tohigher oil and condensate production.Production costs and ad valorem taxes. For the year ended December 31, 2015, production and ad valorem taxes decreased over the year endedDecember 31, 2014, generally as a result of lower realized commodity prices and estimated mineral reserve valuations.Exploration expense. Exploration expense for the year ended December 31, 2015 increased from the year ended December 31, 2014, primarily due tocosts incurred to acquire 3-D seismic information related to our mineral and royalty interests from a third-party service provider.Depreciation, depletion, and amortization. Depreciation, depletion, and amortization expense decreased for the year ended December 31, 2015 ascompared to 2014, 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 for the years ended December 31, 2015 and 2014 primarily resulted from changes in reservevalues due to declines in future expected realized net cash flows as a result of lower commodity prices.General and administrative. For the year ended December 31, 2015, general and administrative expenses increased compared to 2014. In 2015,personnel costs and costs attributable to our long-term incentive plans were $12.3 million higher primarily due to an increase in incentive compensationawards granted subsequent to our IPO and certain restructuring costs. We also incurred an additional $2.5 million for our Sarbanes-Oxley Act complianceproject and other consulting work during 2015.Interest expense. Interest expense decreased due to lower average outstanding borrowing under our credit facility. Outstanding borrowings during2015 were lower than 2014, primarily due to payments made towards the outstanding balance of our credit facility with proceeds from our IPO.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 minimumquarterly distribution will be paid on each common and subordinated unit for each quarter to the extent we have sufficient cash generated from ouroperations after establishment of cash reserves, if any, and after we have made the65required distributions to the holders of our outstanding preferred units. However, we do not have a legal or contractual obligation to pay distributionsquarterly or on any other basis, at the applicable minimum quarterly distribution rate or at any other rate, and there is no guarantee that we will paydistributions to our unitholders in any quarter. Our minimum quarterly distribution provides the common unitholders a specified priority right todistributions over the subordinated unitholders. The board of directors of our general partner may change the foregoing distribution policy at any time andfrom time to time.We intend to finance our future acquisitions and working-interest capital needs with cash generated from operations, borrowings from our creditfacility, and proceeds from any future issuances of equity and debt. Replacement capital expenditures are expenditures necessary to replace our existing oiland natural gas reserves or otherwise maintain our asset base over the long-term. Like a number of other master limited partnerships, we are required by ourpartnership agreement to retain cash from our operations in an amount equal to our estimated replacement capital requirements. The board of directors of ourgeneral partner established a replacement capital expenditure estimate of $15.0 million for the period of April 1, 2016 to March 31, 2017.Cash FlowsThe following table shows our cash flows for the periods presented: Year Ended December 31, 2016 2015 2014 (In thousands)Cash flows provided by operating activities $196,656 $284,735 $396,125Cash flows used in investing activities (221,542) (90,998) (101,110)Cash flows provided by (used in) financing activities 21,425 (195,307) (310,335) 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, andoperating expenses. For the year ended December 31, 2016, cash flows from operating activities decreased by $88.1 million. This decrease was primarily dueto lower cash 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 collectionsrelated to the 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 mineraland property 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.Year Ended December 31, 2015 Compared to Year Ended December 31, 2014Operating Activities. For the year ended December 31, 2015, cash flows from operating activities decreased by $111.4 million. This decrease wasprimarily due to lower cash collections of $190.0 million related to oil and natural gas sales and lease bonus revenue as compared to 2014; the impact of$65.2 million in higher cash collections related to the settlement of commodity derivative instruments partially offset the decrease resulting from lower oiland natural gas sales and lease bonus.Investing Activities. The net cash used in investing activities decreased by $10.1 million in 2015 as compared to 2014 primarily due to a reduction of$26.2 million in capital expenditures for our working interests, net of proceeds from the sales of oil and natural gas properties and a contractual terminationpayment related to a leasehold prospect. An increase of $16.7 million spent on acquisitions partially offset the overall decrease in net cash used in investingactivities.Financing Activities. For the year ended December 31, 2015, the net cash used in financing activities decreased $115.0 million compared to 2014.During 2015, we used net proceeds from our IPO to repay substantially all of our outstanding indebtedness under our credit facility. The proceeds received inexcess of our net repayments resulted in a decrease in net cash used in financing activities from 2014. Monies borrowed to fund a $41.5 million cash tenderoffer for our preferred units plus unpaid accrued yield partially offset the overall decrease in net cash used in financing activities.66Capital ExpendituresAt the beginning of each calendar year, we establish a capital budget and then monitor it throughout the year. Our capital budget is created basedupon our estimate of internally-generated cash flows and the ability to borrow and raise additional capital. Actual capital expenditure levels will vary, in part,based on actual cash generated, the economics of wells proposed by our operators for our participation, and the successful closing of acquisitions. Thetiming, size, and nature of acquisitions are unpredictable.Our 2017 drilling expenditures are expected to be between $50.0 million and $60.0 million. Approximately $50 million of our drilling capital budgetwill be spent in the Haynesville/Bossier play with the remainder expected to be spent in various plays including the Bakken/Three Forks and Wolfcampplays. On February 16, 2017, we entered into a farmout agreement which will reduce our future capital requirements and will generate additional royaltyincome. The farmout covers our working interests within an approximate 34,000-acre block in San Augustine County, Texas. We expect the farmoutagreement to reduce our capital obligations by approximately $30-$35 million in 2017 and by an average of $40-$50 million annually, thereafter.During 2016, we spent $73.3 million related to drilling and completion costs. We also spent $141.1 million related to four mineral acquisitions in2016 as well as a final holdback payment from an acquisition in 2015. See Note 4 - Acquisitions in the consolidated financial statements included elsewherein this Annual Report for further discussion.During 2015, we spent approximately $62.3 million on eight acquisitions. We also incurred approximately $54.2 million related to drilling andcompletion costs, the majority of which was in the Haynesville/Bossier, Bakken/Three Forks, and Wilcox plays.Credit FacilityOn January 23, 2015, we amended and restated our $1.0 billion senior secured revolving credit agreement. Under this third amended and restatedcredit facility, the commitment of the lenders equals the lesser of the aggregate maximum credit amounts of the lenders and the borrowing base, which isdetermined based on the lenders’ estimated value of our oil and natural gas properties. On October 28, 2015, the third amended and restated credit facilitywas further amended to extend the term of the agreement from February 3, 2017 to February 4, 2019. Borrowings under the third amended and restated creditfacility may be used for the acquisition of properties, cash distributions, and other general corporate purposes. Our regular, semi-annual borrowing baseredetermination process resulted in a decrease of the borrowing base from $550.0 million to $450.0 million, effective April 15, 2016. Our fall 2016 borrowingbase redetermination process resulted in an increase in the borrowing base from $450.0 million to $500.0 million, which became effective October 31, 2016.As of December 31, 2016, we had outstanding borrowings of $316.0 million at a weighted-average interest rate of 3.26%.The borrowing base under the third amended and restated credit agreement is redetermined semi-annually, typically in April and October of each year,by the administrative agent, taking into consideration the estimated loan value of our oil and natural gas properties consistent with the administrative agent’snormal oil and natural gas lending criteria. The administrative agent’s proposed redetermined borrowing base must be approved by all lenders to increase ourexisting borrowing base, and by two-thirds of the lenders to maintain or decrease our existing borrowing base. In addition, we and the lenders (at the electionof two-thirds of the lenders) each have discretion to have the borrowing base redetermined once in between scheduled redeterminations.Outstanding borrowings under the third amended and restated credit facility bear interest at a floating rate elected by us equal to an alternative baserate (which is equal to the greatest of the Prime rate, the Federal Funds effective rate plus 0.50%, or 1-month LIBOR plus 1.00%) or LIBOR, in each case, plusthe 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% to2.50% in the case of LIBOR, in each case depending on the amount of borrowings outstanding in relation to the borrowing base. Subsequent to the closing ofour fall 2016 borrowing base redetermination, the applicable margin ranges from 1.00% to 2.00% in the case of the alternative base rate and from 2.00% to3.00 % in the 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. The third amended and restated creditfacility is secured by liens on substantially all of our producing properties.67The third amended and restated credit agreement contains various affirmative, negative, and financial maintenance covenants. These covenants,among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions withaffiliates, and entering into certain swap agreements, as well as require the maintenance of certain financial ratios. The third amended and restated creditagreement contains two financial covenants: total debt to EBITDAX of 3.5:1.0 or less; and a modified current ratio of 1.0:1.0 or greater as defined in thecredit agreement. Distributions are not permitted if there is a default under the third amended and restated credit agreement (including due to a failure tosatisfy one of the financial covenants) or during any time that our borrowing base is lower than the loans outstanding under the third amended and restatedcredit facility. The lenders have the right to accelerate all of the indebtedness under the third amended and restated credit facility upon the occurrence andduring the continuance of any event of default, and the third amended and restated 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 ofdefault due to non-payment of principal and breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmativecovenants are subject to customary cure periods. As of December 31, 2016, we were in compliance with all debt covenants.Contractual ObligationsThe following table summarizes our minimum payments as of December 31, 2016 (in thousands): Payments due by period Total Less Than 1Year 1-3 Years 3-5 Years More Than 5YearsCredit facility $316,000 $— $316,000 $— $—Operating lease obligations 3,296 1,6031,693 — —Purchase commitments 967 967 — — —Total $320,263 $2,570 $317,693 $— $— Off-Balance Sheet ArrangementsAt December 31, 2016, we did not have any material off-balance sheet arrangements.Critical Accounting Policies and Related EstimatesThe discussion and analysis of our financial condition and results of operations are based upon the consolidated financial statements, which have beenprepared in accordance with 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 use the successful efforts method of accounting for oil and natural gas operations. Under this method, costs to acquire interests in oil and naturalgas properties are capitalized. The cost of property acquisitions, successful exploratory wells, development costs, and support equipment and facilities areinitially capitalized when incurred. DD&A of producing oil and natural gas properties is recorded based on a units-of-production methodology. Acquisitioncosts of proved properties are amortized on the basis of all proved reserves, developed and undeveloped, and capitalized development costs are amortized onthe basis of proved developed reserves. Proved reserves are quantities of oil and natural gas that can be estimated with reasonable certainty to beeconomically producible from a given date forward, from known reservoirs, under existing economic68conditions, operating methods, and government regulations. A sustained low price environment could decrease our estimate of proved reserves, which wouldincrease the rate at which we record depletion expense and reduce net income. Additionally, a decline in proved reserve estimates may impact the outcome ofour assessment of producing properties for impairment. We are unable to predict future commodity prices with any greater precision than the futures market.To estimate the effect lower prices would have on our reserves, we applied a 10% discount to the commodity prices used in our December 31, 2016 reservereport. Applying this discount results in an approximate 7.0% reduction of estimated proved reserve volumes as compared to the undiscounted pricingscenario used in our December 31, 2016 reserve report prepared by NSAI.Other exploratory costs, including annual delay rentals and geological and geophysical costs, are expensed when incurred. Mineral and royaltyinterests and working interests are recorded at cost at the time of acquisition. Upon sale or retirement of depreciable or depletable property, the cost andrelated accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized.The costs of unproved leaseholds and mineral interests are capitalized as unproved properties pending the results of exploration efforts. As unprovedleaseholds are determined to be proved, the related costs are transferred to proved properties. Unproved and non-producing property costs are assessedperiodically, on a property-by-property basis, and an impairment loss is recognized to the extent, if any, the recorded value has been impaired. Mineralinterests are recorded at cost at the time of acquisition. Mineral interests are assessed for impairment when facts and circumstances indicate that their carryingvalue may not be recoverable. This assessment is performed by comparing carrying values to valuation estimates and impairment is recognized to the extentthat book value exceeds estimated recoverable value. Any impairment will generally be based on geographic or geologic data and our estimated future cashflows related to our properties.We evaluate impairment of producing properties whenever events or changes in circumstances indicate that the carrying amount of an asset may notbe recoverable. We estimate the undiscounted future cash flows expected in connection with the properties and compare such undiscounted future cash flowsto the carrying amount of the properties to determine if the carrying amount is recoverable. When the carrying amount of a property exceeds its estimatedundiscounted future cash flows, the carrying amount is reduced to its fair value. Fair value is calculated as the present value of estimated future discountedcash 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 markets for oil and natural gas have a history of significant price volatility.However, a sustained low price environment could result in lower NYMEX forward strip prices and lower estimates of future cash flows expected from ourproperties. Such decrease in cash flow estimates could result in recording additional impairment for our properties if such circumstances indicated thecarrying amount of the asset may not be recoverable.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. Whenthe liability is initially recorded, we capitalize this cost by increasing the carrying amount of the related property and equipment. Over time, the liability isaccreted for the change in its present value, and the capitalized cost in oil and natural gas properties is depleted based on units of production consistent withthe 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 issold. 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. Crude oil is priced on thedelivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. Natural gascontracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering ortransmission line, quality and heat content69of natural gas, and prevailing supply and demand conditions, so that the price of natural gas fluctuates to remain competitive with other available natural gassupplies. These market indices are determined on a monthly basis.Our other sources of revenue include mineral lease bonus and delay rentals, which are recognized as revenue according to the terms of the leaseagreements. We generate lease bonus revenue from leasing our mineral interests to exploration and production companies. The lease agreements transfer therights to any oil or natural gas discovered to the operators, grant us a right to a specified royalty interest, and require that drilling and completion operationsbe done within a specified time period. We recognize such lease bonus revenue at which time the lease agreement has been executed, payment is determinedto be collectable, and we have no furtherobligation to refund the payment. We also recognize revenue from delay rentals to the extent drilling has not started within the specified period, payment hasbeen collected, and we have no further obligation to refund the payment. Derivatives and Financial InstrumentsOur ongoing operations expose us to changes in the market price for oil and natural gas. To mitigate the given commodity price risk associated withits operations, we use derivative instruments. From time to time, such instruments may include fixed-price contracts, variable to fixed price swaps, costlesscollars, and other contractual arrangements. We do not enter into derivative instruments for speculative purposes. In addition, we currently employ a “rollinghedge” strategy whereby we generally hedge our proved developed producing reserves 12 to 24 months into the future. 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.Total compensation expense for unit-based awards is calculated based on the number of units granted 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 Note10 – Incentive Compensation within the consolidated financial statements included elsewhere in this Annual Report for additional information.Prior to our initial public offering, the board of directors of our Predecessor determined the fair value of unit-based awards by considering variousobjective and subjective factors, along with input from management, and using the same methodology as required under our Predecessor’s partnershipagreement for purposes of repurchasing Predecessor common units from those limited partners who exercise their right to annually sell a portion of their units.To determine the fair value of the unit-based awards, the board of directors of our Predecessor considered information provided by third-party consultants andrelied on generally accepted valuation techniques, which included the net asset value method under the asset approach, the guideline public companymethod under the market approach, and the dividend discount method of the income approach. Estimates of value using the net asset value method werederived using assumptions including commodity prices, estimated development timing of our acreage, and market-based discount rates. The valueconclusion using the guideline public company method was estimated by considering peer company performance metrics, comparability of the peercompany portfolio and risk profiles, and implied forward distribution yields and multiples. To estimate the value of the awards using the transaction method,publicly available data related to acquisitions of mineral properties and applied the implied deal metrics to our performance measures were reviewed. Thedividend discount method was developed based on assumptions including our projected distributions, anticipated long-term distribution growth rates, andnear- and long-term cost of capital estimates. In determining the fair value of the awards, the board of directors of our Predecessor also considered ourhistorical transactions and performance in making these estimates.70New 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. 71Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKCommodity Price RiskOur major market risk exposure is the pricing of oil, natural gas, and natural gas liquids produced by our operators. Realized prices are primarily drivenby the prevailing 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 forseveral years, and we expect this unpredictability to continue in the future. The prices that our operators receive for production depend on many factorsoutside of our or their control. To reduce the impact of fluctuations in oil and natural gas prices on our revenues, we use commodity derivative 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 – Derivatives and Financial Instruments and Note 6 – Fair Value Measurement 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 year ended December 31, 2016. Applying this discount results in an approximate 7.0% reduction of proved reserve volumes ascompared to the undiscounted December 31, 2016 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, 2016, we had nine counterparties, all of which are rated Baa3 or better byMoody’s. Six 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, 2016, we had $316.0 million of outstanding borrowings underour credit facility, bearing interest at a weighted-average interest rate of 3.26%. 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 $3.2 million for the year ended December 31,2016, 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. 72ITEM 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, 2016. 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 generalpartner’s management assessed the effectiveness of our internal control over financial reporting as of December 31, 2016, using the criteria in InternalControl-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation,our general partner’s management believes that our internal control over financial reporting was effective as of December 31, 2016.This Annual Report includes an attestation report of Ernst & Young LLP, our independent registered public accounting firm, on our internal controlover financial reporting as of December 31, 2016, 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, 2016, that have materially affected, or are reasonably likely to materially affect, our internal control overfinancial reporting. ITEM 9B. OTHER INFORMATIONNone.73PART 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 2017 Annual Meeting ofLimited Partners (“2017 Proxy Statement”), which will be filed with the SEC not later than 120 days after December 31, 2016.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 2017 Proxy Statement, which will be filed with the SEC not later than 120 daysafter December 31, 2016. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERSInformation required by this item is incorporated by reference to the 2017 Proxy Statement, which will be filed with the SEC not later than 120 daysafter December 31, 2016. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCEInformation required by this item is incorporated by reference to the 2017 Proxy Statement, which will be filed with the SEC not later than 120 daysafter December 31, 2016. ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICESInformation required by this item is incorporated by reference to the 2017 Proxy Statement, which will be filed with the SEC not later than 120 daysafter December 31, 2016.74PART 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 3.1 Certificate of Limited Partnership of Black Stone Minerals, L.P. (incorporated herein by reference to Exhibit 3.1 to Black StoneMinerals, 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 toExhibit 3.2 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., as amended (incorporated herein by reference to Exhibit 3.2 ofBlack Stone Minerals, L.P.’s Current Report on Form 8-K filed on April 19, 2016 (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)). 10.2 First Amendment to Third Amended and Restated Credit Agreement, dated as of October 28, 2015, among Black Stone MineralsCompany, L.P., as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, Black Stone Minerals, L.P., as ParentMLP, and a syndicate of lenders (incorporated herein by reference to Exhibit 10.1 of Black Stone Minerals, L.P.’s Current Report onForm 8-K filed on October 28, 2015 (SEC File No. 001-37362)). 10.3* Second Amendment to Third Amended and Restated Credit Agreement, dated as of October 31, 2016, among Black Stone MineralsCompany, L.P., as Borrower, Black Stone Minerals, L.P., as Parent MLP, Wells Fargo Bank, National Association, as AdministrativeAgent, and a syndicate of lenders. 10.4 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.and Amegy Bank National Association, as Co-Documentation Agents, and a syndicate of lenders dated as of January 23, 2015(incorporated herein 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 File No. 333-202875)). 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)). 7510.6^ 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 onMarch 19, 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.’s Registration 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 STI Award Grant Notice and STI Award Agreement (Leadership) under the Black Stone Minerals, L.P. Long-Term IncentivePlan (incorporated herein by reference to Exhibit 10.1 to Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on February 2,2016 (SEC File No. 001-37362). 10.17^ Form of LTI Award Grant Notice and LTI Award Agreement (Leadership) under the Black Stone Minerals, L.P. Long-Term IncentivePlan (incorporated herein by reference to Exhibit 10.2 to Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on February 2,2016 (SEC File No. 001-37362). 10.18^ Form of STI Award Grant Notice and STI Award Agreement (Leadership) under the Black Stone Minerals, L.P. Long-Term IncentivePlan (incorporated herein by reference to Exhibit 10.1 Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on February 19,2016 (SEC File No. 001-37362)). 10.19^ Form of LTI Award Grant Notice and LTI Award Agreement (Leadership) under the Black Stone Minerals, L.P. Long-Term IncentivePlan (incorporated herein by reference to Exhibit 10.2 Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on February 19,2016 (SEC File No. 001-37362)). 7610.20^ Separation and Consulting Agreement and General Release of Claims, dated as of November 21, 2016, by and among Marc Carroll,Black Stone Natural Resources Management Company, and Black Stone Minerals GP, L.L.C. (incorporated herein by reference toExhibit 10.1 Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on November 28, 2016 (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.^Management contract or compensatory plan or arrangement.77SIGNATURESPursuant 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 March 1, 2017 By: /s/ Thomas L. Carter, Jr. Thomas L. Carter, Jr. President, Chief Executive Officer, and Chairman 78Pursuant 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 March 1, 2017Thomas L. Carter, Jr. (Principal Executive Officer) /s/ Jeffrey P. Wood Senior Vice President and Chief Financial Officer March 1, 2017Jeffrey P. Wood (Principal Financial Officer) /s/ Dawn K. Smajstrla Vice President and Chief Accounting Officer March 1, 2017Dawn K. Smajstrla (Principal Accounting Officer) /s/ William G. Bardel Director March 1, 2017William G. Bardel /s/ Carin M. Barth Director March 1, 2017Carin M. Barth /s/ D. Mark DeWalch Director March 1, 2017D. Mark DeWalch /s/ Ricky J. Haeflinger Director March 1, 2017Ricky J. Haeflinger /s/ Jerry V. Kyle, Jr. Director March 1, 2017Jerry V. Kyle, Jr. /s/ Michael C. Linn Director March 1, 2017Michael C. Linn /s/ John H. Longmaid Director March 1, 2017John H. Longmaid /s/ William N. Mathis Director March 1, 2017William N. Mathis /s/ Alexander D. Stuart Director March 1, 2017Alexander D. Stuart /s/ Allison K. Thacker Director March 1, 2017Allison K. Thacker 79INDEX TO CONSOLIDATED FINANCIAL STATEMENTSBLACK STONE MINERALS, L.P. Reports of Independent Registered Public Accounting Firms F-2 Consolidated Balance Sheets as of December 31, 2016 and December 31, 2015 F-5 Consolidated Statements of Operations for the Years Ended December 31, 2016, 2015 and 2014 F-6 Consolidated Statements of Equity for the Years Ended December 31, 2016, 2015, and 2014 F-7 Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014 F-8 Notes to Consolidated Financial Statements F-9F-1REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMThe Audit Committee of the Board of Directors and Unitholders of Black Stone Minerals, L.P. and subsidiariesWe have audited the accompanying consolidated balance sheet of Black Stone Minerals, L.P. and subsidiaries as of December 31, 2016, and the relatedconsolidated statements of operations, equity and cash flows for the year then ended December 31, 2016. These financial statements are the responsibility ofthe Partnership’s management. Our responsibility is to express an opinion on these 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 financial statements are free of material misstatement. An audit includesexamining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accountingprinciples used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our auditprovides a reasonable basis for our opinion.In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Black Stone Minerals,L.P. and subsidiaries at December 31, 2016, and the consolidated results of their operations and their cash flows for the year then ended December 31, 2016,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), Black Stone Minerals, L.P.’sinternal control over financial reporting as of December 31, 2016, 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 March 1, 2017 expressed an unqualifiedopinion thereon./s/ Ernst & Young LLPHouston, TXMarch 1, 2017F-2REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMThe Audit Committee of the Board of Directors and Unitholders of Black Stone Minerals, L.P. and subsidiariesWe have audited Black Stone Minerals, L.P. and subsidiaries’ internal control over financial reporting as of December 31, 2016, based on criteria establishedin Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSOcriteria). Black Stone Minerals, L.P. and subsidiaries’ management is responsible for maintaining effective internal control over financial reporting, and for itsassessment of the effectiveness of internal control over financial reporting included in the accompanying “Management’s Annual Report on Internal Controlover Financial Reporting.” Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting 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 effective internal control over financial reporting was maintained in all materialrespects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testingand evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considerednecessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.A 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.In our opinion, Black Stone Minerals, L.P. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as ofDecember 31, 2016, based on the COSO criteria.We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheetof Black Stone Minerals, L.P. and subsidiaries as of December 31, 2016, and the related consolidated statements of operations, equity and cash flows for theyear then ended December 31, 2016 of Black Stone Minerals, L.P. and subsidiaries and our report dated March 1, 2017 expressed an unqualified opinionthereon./s/ Ernst & Young LLPHouston, TXMarch 1, 2017F-3REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMThe Partners ofBlack Stone Minerals, L.P.Houston, TexasWe have audited the accompanying consolidated balance sheet of Black Stone Minerals, L.P. and subsidiaries (the “Partnership”) as of December 31, 2015,and the related consolidated statements of operations, equity, and cash flows for each of the two years in the period ended December 31, 2015. Theseconsolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidatedfinancial statements based on our audits.We conducted our audits 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 audits includedconsideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for thepurpose of expressing an opinion on the effectiveness of the Partnership's internal control over financial reporting. Accordingly, we express no such opinion.An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, assessing theaccounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statementpresentation. We believe that our audits provide a reasonable basis for our opinion.In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Black Stone Minerals,L.P. and subsidiaries at December 31, 2015, and the results of its operations and its cash flows for each of the two years in the period ended December 31,2015, in conformity with accounting principles generally accepted in the United States of America./s/ BDO USA, LLPHouston, TexasMarch 8, 2016F-4BLACK STONE MINERALS, L.P. AND SUBSIDIARIESCONSOLIDATED BALANCE SHEETS(in thousands) As of December 31, 2016 2015ASSETS CURRENT ASSETS Cash and cash equivalents$9,772 $13,233Accounts receivable68,181 41,246Commodity derivative assets— 48,260Prepaid expenses and other current assets1,036 856TOTAL CURRENT ASSETS78,989 103,595PROPERTY AND EQUIPMENT Oil and natural gas properties, at cost, using the successful efforts method of accounting, includes unprovedproperties of $605,736 and $524,563 at December 31, 2016 and 2015, respectively2,697,073 2,482,211Accumulated depreciation, depletion, amortization, and impairment(1,652,930) (1,543,796)Oil and natural gas properties, net1,044,143 938,415Other property and equipment, net of accumulated depreciation of $14,327 and $14,660 at December 31, 2016and 2015, respectively528 179NET PROPERTY AND EQUIPMENT1,044,671 938,594DEFERRED CHARGES AND OTHER LONG-TERM ASSETS5,167 19,247TOTAL ASSETS$1,128,827 $1,061,436LIABILITIES, MEZZANINE EQUITY AND EQUITY CURRENT LIABILITIES Accounts payable$4,142 $5,036Accrued liabilities50,952 58,003Commodity derivative liabilities16,237 —TOTAL CURRENT LIABILITIES71,331 63,039LONG-TERM LIABILITIES Credit facility316,000 66,000Accrued incentive compensation1,485 7,902Commodity derivative liabilities482 —Deferred revenue518 3,257Asset retirement obligations13,350 10,585TOTAL LIABILITIES403,166 150,783COMMITMENTS AND CONTINGENCIES (Note 12) MEZZANINE EQUITY Partners' equity - redeemable preferred units, 53 and 77 units outstanding at December 31, 2016 and 2015,respectively54,015 79,162EQUITY Partners' equity - general partner interest— —Partners' equity - common units, 95,721 and 96,162 units outstanding at December 31, 2016 and 2015,respectively489,023 574,648Partners' equity - subordinated units, 95,164 and 95,057 units outstanding at December 31, 2016 and 2015,respectively181,602 255,699Noncontrolling interests1,021 1,144TOTAL EQUITY671,646 831,491TOTAL LIABILITIES, MEZZANINE EQUITY AND EQUITY$1,128,827 $1,061,436 The accompanying notes to consolidated financial statements are an integral part of these financial statements.F-5BLACK STONE MINERALS, L.P. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF OPERATIONS(in thousands, except per unit amounts) Year Ended December 31, 2016 2015 2014REVENUE Oil and condensate sales$142,382 $163,538 $257,390Natural gas and natural gas liquids sales122,836 116,018 207,456Gain (loss) on commodity derivative instruments(36,464) 90,288 37,336Lease bonus and other income32,079 23,080 46,139TOTAL REVENUE260,833 392,924 548,321OPERATING (INCOME) EXPENSE Lease operating expense18,755 21,583 21,233Production costs and ad valorem taxes35,464 35,767 49,575Exploration expense645 2,592 631Depreciation, depletion and amortization102,487104,298111,962Impairment of oil and natural gas properties6,775249,569117,930General and administrative73,139 77,175 62,765Accretion of asset retirement obligations8921,0751,060(Gain) loss on sale of assets, net(4,793) (4,873) 32Other expense— 1,593 1,424TOTAL OPERATING EXPENSE233,364 488,779 366,612INCOME (LOSS) FROM OPERATIONS27,469 (95,855) 181,709OTHER INCOME (EXPENSE) Interest and investment income656 58 28Interest expense(7,547) (6,418) (13,509)Other income (expense)(390) 910 959TOTAL OTHER EXPENSE(7,281) (5,450) (12,522)NET INCOME (LOSS)20,188 (101,305) 169,187NET INCOME (LOSS) ATTRIBUTABLE TO PREDECESSOR— (450) (169,187)NET INCOME (LOSS) ATTRIBUTABLE TO NONCONTROLLING INTERESTS SUBSEQUENT TOINITIAL PUBLIC OFFERING12 1,260 —DISTRIBUTIONS ON REDEEMABLE PREFERRED UNITS SUBSEQUENT TO INITIAL PUBLICOFFERING(5,763) (7,522) —NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON ANDSUBORDINATED UNITS SUBSEQUENT TO INITIAL PUBLIC OFFERING$14,437 $(108,017) $—ALLOCATION OF INCOME (LOSS) SUBSEQUENT TO INITIAL PUBLIC OFFERINGATTRIBUTABLE TO: General partner interest$— $— Common units24,669 (54,326) Subordinated units(10,232) (53,691) $14,437 $(108,017) NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON ANDSUBORDINATED UNIT: Per common unit (basic)$0.26 $(0.56) Weighted average common units outstanding (basic)96,073 96,182 Per subordinated unit (basic)$(0.11) $(0.56) Weighted average subordinated units outstanding (basic)95,138 95,057 Per common unit (diluted)$0.26 $(0.56) Weighted average common units outstanding (diluted)96,243 96,182 Per subordinated unit (diluted)$(0.11) $(0.56) Weighted average subordinated units outstanding (diluted)95,138 95,057 DISTRIBUTIONS DECLARED AND PAID SUBSEQUENT TO INITIAL PUBLIC OFFERING: Per common unit$1.10 $0.424 Per subordinated unit$0.74 $0.424 The accompanying notes to consolidated financial statements are an integral part of these financial statements.F-6BLACK 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, 2013164,133 $716,403 — — $— $— $— $716,403Conversion of Predecessor redeemablepreferred units15 221 — — — — — 221Issuance of Predecessor units for acquisitionof oil and natural gas properties104 2,258 — — — — — 2,258Repurchase of Predecessor units(239) (5,199) — — — — — (5,199)Restricted Predecessor units granted, net offorfeitures471 — — — — — — —Equity-based compensation— 11,340 — — — — — 11,340Distributions to Predecessor unitholders andnon-controlling interests— (225,273) — — — — — (225,273)Net income attributable to Predecessor— 169,187 — — — — — 169,187Distributions on Predecessor redeemablepreferred units— (15,720) — — — — — (15,720)BALANCE 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 redeemable preferred units— — — — (3,783) (3,739) — (7,522)BALANCE AT DECEMBER 31, 2015— — 96,162 95,057 574,648 255,699 1,144 831,491Restricted units granted, net of forfeitures— — 993 (56) — — — —Equity-based compensation— — — — 21,022 2,823 — 23,845Conversion of redeemable preferred units— — 184 241 2,625 3,439 — 6,064Repurchases of common and subordinatedunits— — (1,618) (78) (27,436) — — (27,436)Distributions— — — — (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 redeemable preferred units— — — — (2,896) (2,867) — (5,763)BALANCE AT DECEMBER 31, 2016— $— 95,721 95,164 $489,023 $181,602 $1,021 $671,646The accompanying notes to consolidated financial statements are an integral part of these financial statements.F-7BLACK STONE MINERALS, L.P. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF CASH FLOWS(in thousands) Year Ended December 31, 2016 2015 2014CASH FLOWS FROM OPERATING ACTIVITIES Net income (loss)$20,188 $(101,305) $169,187Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation, depletion, and amortization102,487 104,298 111,962Impairment of oil and natural gas properties6,775 249,569 117,930Accretion of asset retirement obligations892 1,075 1,060Amortization of deferred charges871 935 965(Gain) loss on commodity derivative instruments36,464 (90,288) (37,336)Net cash received (paid) on settlement of commodity derivative instruments44,789 63,225 (1,947)Equity-based compensation43,138 18,000 11,340(Gain) loss on sale of assets, net(4,793) (4,873) 32Changes in operating assets and liabilities: Accounts receivable(29,759) 33,586 17,210Prepaid expenses and other current assets(180) 95 453Accounts payable and accrued liabilities(23,029) 11,221 8,003Deferred revenue(870) (660) (2,589)Settlement of asset retirement obligations(317) (143) (145)NET CASH PROVIDED BY OPERATING ACTIVITIES196,656 284,735 396,125CASH FLOWS FROM INVESTING ACTIVITIES Additions to oil and natural gas properties(80,179) (54,244) (74,201)Purchase of other property and equipment(425) (181) (827)Proceeds from the sale of oil and natural gas properties198 25,705 19,470Acquisitions of oil and natural gas properties(141,136)(62,278)(45,552)NET CASH USED IN INVESTING ACTIVITIES(221,542) (90,998) (101,110)CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from issuance of common units of Black Stone Minerals, L.P., net of offering costs— 399,087 (7,587)Borrowings under senior line of credit349,000 245,600 230,000Repayments under senior line of credit(99,000) (573,600) (287,000)Distributions to Predecessor unitholders— (126,383) (224,926)Distributions to Black Stone Minerals, L.P. common and subordinated unitholders(175,943) (81,087) —Distributions to preferred unitholders(6,385) (13,578) (15,724)Distributions to noncontrolling interests(111) (208) —Redemption of redeemable preferred units(18,461) (40,747) —Repurchases of Predecessor units— (3,015) (5,199)Debt issuance costs(239) (1,376) —Note receivable-officers— — 101Repurchase of common and subordinate units(27,436) — —NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES21,425 (195,307) (310,335)NET CHANGE IN CASH AND CASH EQUIVALENTS(3,461) (1,570) (15,320)CASH AND CASH EQUIVALENTS - beginning of the year13,233 14,803 30,123CASH AND CASH EQUIVALENTS - end of the year$9,772 $13,233 $14,803SUPPLEMENTAL DISCLOSURE Interest paid$6,535 $5,478 $12,754NON-CASH ACTIVITIES Accrued Predecessor distributions payable$— $(53,248) $347Conversion of redeemable preferred units$(6,064) $(39,240) $(221)Accrued distributions payable for redeemable preferred units$(1,324) $(2,016) $(4)Property additions and acquisitions financed through accounts payable and accrued liabilities$26,553 $21,496 $14,130Public offering costs capitalized and offset against proceeds from initial public offering$— $7,587 $—Asset retirement obligations incurred$2,009 $272 $2,505Accrued distribution equivalent rights$847 $159 $—Liabilities assumed as consideration for oil and natural gas properties acquired$— $— $7,000Acquisition of oil and natural gas properties financed through issuance of Predecessor units$— $— $2,258Deferred revenue (settled) assumed through acquisition of oil and natural gas properties$— $— $(2,657) The accompanying notes to consolidated financial statements are an integral part of these financial statements.F-8BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSNOTE 1—BUSINESS AND BASIS OF PRESENTATIONDescription of the business: Black Stone Minerals, L.P. (“BSM” or the “Partnership”) is a publicly traded Delaware limited partnership formed onSeptember 16, 2014. On May 6, 2015, BSM completed its initial public offering (the “IPO”) of 22,500,000 common units representing limited partnerinterests 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 underwritingdiscount, structuring fee, and offering expenses (including costs previously incurred and capitalized). BSM used the net proceeds from the IPO to repaysubstantially all indebtedness outstanding under its credit facility. On May 1, 2015, BSM’s common units began trading on the New York Stock Exchangeunder the symbol “BSM.”Black Stone Minerals Company, L.P., a Delaware limited partnership, and its subsidiaries (collectively referred to as “BSMC” or the “Predecessor”)own oil and natural gas mineral interests in the United States. In connection with the IPO, BSMC was merged into a wholly owned subsidiary of BSM, withBSMC as the surviving entity. Pursuant to the merger, the Class A and Class B common units representing limited partner interests of the Predecessor wereconverted 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 for 0.4329 commonunits and 0.5671 subordinated units, and the preferred units of BSMC were converted into an aggregate of 117,963 preferred units of BSM at a conversionratio of one to one. The merger is accounted for as a combination of entities under common control with assets and liabilities transferred at their carryingamounts in a manner similar to a pooling of interests. Unless otherwise stated or the context otherwise indicates, all references to the “Partnership” or similarexpressions for time periods prior to the IPO refer to Black Stone Minerals Company, L.P. and its subsidiaries, the Predecessor, for accounting purposes. Fortime periods subsequent to the IPO, these terms refer to Black Stone Minerals, L.P. and its subsidiaries.In addition to minerals interests, which make up the vast majority of the asset base, the Partnership's assets also include nonparticipating royaltyinterests, and overriding royalty interests. These interests, which are substantially non-cost-bearing, are collectively referred to as “mineral and royaltyinterests.” The Partnership’s mineral and royalty interests are located in most of the major onshore oil and natural gas producing basins spread across 41 statesand 61 onshore oil and natural gas producing basins of the continental U.S. The Partnership also owns non-operated working interests in certain oil andnatural gas properties.Basis of presentation: The accompanying audited consolidated financial statements of the Partnership have been prepared in accordance withgenerally accepted accounting principles (“GAAP”) in the United States and pursuant to the rules and regulations of the U.S. Securities and ExchangeCommission ("SEC"). The financial statements include the consolidated results of the Partnership. All intercompany balances and transactions have beeneliminated. The consolidated financial statements reflect all normal recurring adjustments that, in the opinion of management, are necessary for a fairpresentation.Certain reclassifications have been made to the prior periods presented to conform to the current period financial statement presentation. Thereclassifications have no effect on the consolidated financial position, results of operations, or cash flows of the Partnership.The Partnership evaluates the significant terms of its investments to determine the method of accounting to be applied to each respective investment.Investments in which the Partnership has less than a 20% ownership interest and does not have control or exercise significant influence are accounted 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 oiland natural gas property rights by reporting its proportionate share of assets, liabilities, revenues, costs and cash flows within the relevant lines on theaccompanying consolidated balance sheets, statements of operations, and statements of cash flows.Segment reporting: The Partnership operates in a single operating and reportable segment. Operating segments are defined as components of anenterprise for which separate financial information is evaluated regularly by the chief operating decision maker in deciding how to allocate resources andassess performance. The Partnership’s chief executive officer has been determined to be the chief operating decision maker and allocates resources andassesses performance based upon financial information at the consolidated level. F-9BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSNOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIESUse of estimates: The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates andassumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidatedfinancial statements and the reported amounts of revenues and expenses during the reporting periods. 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, amortization (“DD&A”) and impairment of oil and natural gas properties. Reservoir engineeringis a subjective process of estimating underground accumulations of oil and natural gas. There are numerous uncertainties inherent in estimating quantities ofproved oil and natural gas reserves. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geologicalinterpretation and judgment. As a result, reserve estimates may differ from the quantities of oil and natural gas that are ultimately recovered. The Partnership’sreserve estimates are determined by an independent petroleum engineering firm. Other items subject to significant estimates and assumptions include thecarrying amount of oil and natural gas properties, valuation of derivative instruments, revenue accruals, asset retirement obligation (“ARO”) liabilities, anddetermination 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 currenteconomic and commodity price environment. The volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions.A significant decline in natural gas or oil 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 equivalents: The Partnership considers all highly liquid investments purchased with an original maturity of three months or less to becash equivalents.Concentration of credit risk: Financial instruments that potentially subject the Partnership to credit risk consist principally of cash and cash equivalentbalances, accounts receivable, and commodity derivative financial instruments. The Partnership maintains cash and cash equivalent balances with majorfinancial institutions. At times, those balances exceed federally insured limits; however, no losses have been incurred. The Partnership attempts to limit theamount of credit exposure to any one company through procedures that include credit approvals, credit limits and terms, and prepayments. The Partnership’scustomer base is made up of its lessees, which are primarily major integrated and international oil and natural gas companies and other operators, though thePartnership’s credit risk may extend to the eventual purchasers of oil and natural gas produced from the Partnership’s properties. The Partnership believes thecredit quality of its customer base is high and has not experienced significant write-offs in its accounts receivable balances. See Note 8 – SignificantCustomers for further discussion. Derivative instruments may expose the Partnership to credit risk. However, the Partnership monitors the creditworthiness ofits counterparties.Accounts receivable: The Partnership’s accounts receivable balance results primarily from operators’ sales of oil and natural gas to their customers.Accounts receivable is recorded at the contractual amounts and do not bear interest. Any concentration of customers may impact the Partnership’s overallcredit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions impacting the oil andnatural gas industry.Derivatives and financial instruments: The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. Tomitigate the given commodity price risk associated with its operations, the Partnership uses derivative instruments. From time to time, such instruments mayinclude variable–to-fixed-price swaps, costless collars, fixed-price contracts, and other contractual arrangements. The Partnership does not enter intoderivative instruments for speculative purposes.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. 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 derivatives are recognized on a net basis in the accompanying consolidated statements of operations within gain (loss) oncommodity derivative instruments.F-10BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSOil and natural gas properties: The Partnership follows the successful efforts method of accounting for oil and natural gas operations. Under thismethod, costs to acquire interests in oil and natural gas properties, property acquisitions, successful exploratory wells, development costs, and supportequipment and facilities are capitalized when incurred. Exploration dry holes are charged to expense when it is determined that no commercial reserves exist.Other exploratory costs, including annual delay rentals and geological and geophysical costs, are expensed when incurred. Acquired mineral and royaltyinterests and working interests are recorded at cost at the time of acquisition.The costs of unproved leaseholds and mineral interests are capitalized as unproved properties pending the results of exploration and leasing efforts. Asunproved leaseholds are determined to be proved, the related costs are transferred to proved properties. Unproved and non-producing property costs areassessed periodically, on a property-by-property basis, and an impairment loss is recognized to the extent, if any, the recorded value has been impaired.Mineral interests are assessed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. This assessment isperformed by comparing carrying values to valuation estimates and impairment is recognized to the extent that book value exceeds estimated recoverablevalue. Any impairment will generally be based on geographic or geologic data and our estimated future cash flows related to our properties.As exploration and development work progresses and the reserves associated with the Partnership’s properties become proven, capitalized costsattributed to the properties are charged as an operating expense through DD&A. DD&A of producing oil and natural gas properties is recorded based on theunits-of-production method. Acquisition costs of proved properties are amortized on the basis of all proved reserves, both developed and undeveloped, andcapitalized development costs are amortized on the basis of proved developed reserves. Proved reserves are quantities of oil and natural gas that can beestimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, under existing economic conditions,operating methods, and government regulations. DD&A expense related to the Partnership’s producing oil and natural gas properties was $102.4 million,$102.7 million and $109.9 million for the years ended December 31, 2016, 2015, and 2014, respectively.The Partnership evaluates impairment of producing properties whenever events or changes in circumstances indicate that the carrying amount of anasset may 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 the carrying amount to determine recoverability. When the carrying amount of a depletable unit 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.Impairment of proved oil and natural gas properties was $4.9 million, $127.8 million and $117.9 million for the years ended December 31, 2016,2015, and 2014, respectively. The impairment primarily resulted from declines in future expected realizable net cash flows. The charges are included inimpairment of oil and natural gas properties on the consolidated statements of operations and reflected in the net book value of oil and natural gas properties.The carrying value of unproved properties, including unleased mineral rights, is periodically assessed for impairment using management’s assessmentof fair value. The factors used to determine fair value are similar to those previously noted for proved properties. Impairment of unproved properties was $1.9million and $121.8 million for the years ended December 31, 2016 and 2015, respectively. There was no impairment of unproved properties for the yearended December 31, 2014.Upon the sale of complete fields of depreciable or depletable property, the book value thereof, less proceeds or salvage value is charged to income. Onsale or retirement of an individual well, the proceeds are credited to accumulated DD&A.Other property and equipment: Other property and equipment includes furniture, fixtures, office equipment, leasehold improvements, and computersoftware and is stated at historical cost. Depreciation and amortization are calculated using the straight-line method over expected useful lives ranging fromthree to seven years. Depreciation and amortization expense totaled $0.1 million, $1.6 million, and $2.1 million for the years ended December 31, 2016,2015, and 2014, respectively.Repairs and maintenance: The cost of normal maintenance and repairs is charged to expense as incurred. Material expenditures that increase the life ofan asset are capitalized and depreciated over the shorter of the estimated remaining useful life of the asset or the term of the lease, if applicable.Accrued liabilities: Accrued liabilities consisted of the following as of December 31, 2016 and 2015:F-11BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS As of December 31, 2016 2015Accrued liabilities: Accrued capital expenditures$17,775 $20,494Accrued incentive compensation20,898 16,554Accrued legal— 7,000Accrued severance— 3,889Accrued property taxes3,175 3,699Accrued other9,104 6,367TOTAL ACCRUED LIABILITIES$50,952 $58,003 Debt issuance costs: Debt issuance costs consist of costs directly associated with obtaining credit with financial institutions. These costs arecapitalized and are amortized on a straight-line basis over the life of the credit agreement, which approximates the effective-interest method. Anyunamortized debt issue costs are expensed in the year when the associated debt instrument is terminated. Amortization expense for debt issue costs was $0.9million, $0.9 million, and $1.0 million for the years ended December 31, 2016, 2015, and 2014, respectively, and is included in interest expense in theconsolidated statements of operations.Asset retirement obligations: Fair values of legal obligations to retire and remove long-lived assets are recorded when the obligation is incurred andbecomes determinable. When the liability is initially recorded, the Partnership capitalizes this cost by increasing the carrying amount of the related propertyand equipment. Over time, the liability is accreted for the change in its present value, and the capitalized cost in oil and natural gas properties is depletedbased on units of production consistent with the related asset.Revenue recognition: The Partnership recognizes revenue when it is realized or realizable and earned. Revenues are considered realized or realizableand 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 buyeris fixed or determinable, 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, 2016 and 2015. To the extent actualvolumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, theexpected sales volume and prices for these properties are estimated and recorded within accounts receivable in the accompanying consolidated balancesheets. Crude oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality andphysical location. Natural gas contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a welldelivers to a gathering or transmission line, quality and heat content of natural gas, and prevailing supply and demand conditions, so that the price of naturalgas fluctuates to remain competitive with other available natural gas supplies. These market indices are determined on a monthly basis.Other sources of revenue received by the Partnership includes mineral lease bonuses and delay rentals. The Partnership generates lease bonus revenueby leasing its mineral interests to other exploration and production companies. The lease agreements generally transfer the rights to any oil or natural gasdiscovered, grant the Partnership a right to a specified royalty interest, and require that drilling and completion operations commence within a specified timeperiod. The Partnership recognizes such lease bonus revenue at which time the lease agreement has been executed, payment is determined to be collectable,and the Partnership has no further obligation to refund the payment. The Partnership also recognizes revenue from delay rentals to the extent drilling has notstarted within the specified period, payment has been collected, and the Partnership has no further obligation to refund the payment.F-12BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSIncome taxes: The Partnership is organized as a pass-through entity for income tax purposes. As a result, the Partnership’s unitholders are responsiblefor federal and state income taxes attributable to their share of the Partnership’s taxable income. The Partnership is subject to other state-based taxes;however, those taxes are not material.Limited 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 instruments: The carrying values of the Partnership’s current financial instruments, which include cash and cash equivalents,accounts receivable and accounts payable, approximate their fair value at December 31, 2016 and 2015 due to the short-term maturity of these instruments.See Note 6 – Fair Value Measurement for further discussion.Incentive compensation: Incentive compensation includes both equity-based awards and liability awards. The Partnership recognizes compensationexpense associated with its incentive compensation awards using either straight-line or accelerated attribution over the requisite service period (generally thevesting period of the awards) depending on the given terms of the award, based on their grant-date fair values. Incentive compensation expense is charged togeneral and administrative expense.Liability awards are awards that are expected to be settled in cash or an unknown number of common or subordinated units on their vesting dates.Liability awards are recorded as accrued liabilities based on the vested portion of the estimated fair value of the awards as of the grant date, which is subjectto revision based on the impact of certain performance conditions associated with the incentive plans. The Partnership may also recognize liability awards asa result of repurchase options given to the recipients participating in certain incentive plans.Compensation expense for unit-based awards subsequent to the Partnership’s initial public offering is measured by the price of the unit at themeasurement date, which is generally the date of grant, and is recognized in general and administrative expense over the requisite service period. Prior to theinitial public offering, the Predecessor was privately held and determining the fair value required the Predecessor to make complex and subjective judgments.The Board determined the fair value of the equity-based awards’ unit price prior to the Partnership’s initial public offering by considering various objectiveand subjective factors, along with input from management. To determine the fair value of the Predecessor, the Predecessor considered information providedby third-party consultants and relied on generally accepted valuation techniques, which included, but were not limited to, the net asset value method underthe asset approach, the guideline public company method under the market approach, and the dividend discount method of the income approach. Thesemethods were dependent upon various assumptions to develop the estimates in the Predecessor’s operating results, commodity prices, and market-baseddiscount rates. The Predecessor also considered publicly available information on comparable public companies and the Predecessor’s historical transactionsand performance in making these estimates. The Predecessor’s limited partnership agreement contained an annual repurchase obligation of 1% of theoutstanding units. An annual valuation of the Predecessor was required to establish a value basis for the repurchase obligation. The Predecessor utilized thesame valuation for repurchases and issuances of equity, if any, and as the basis for calculating the fair value of its equity awards under its long-term incentiveplans.New accounting pronouncements: The JOBS Act provides that an emerging growth company can delay adopting new or revised accounting standardsuntil such time as those standards apply to private companies. We have irrevocably elected to “opt out” of this exemption and therefore will be subject to thesame new or revised accounting standards as other public companies that are not emerging growth companies.In May 2014, the Financial Accounting Standards Board (the “FASB”) issued an accounting standards update on a comprehensive new revenuerecognition standard that will supersede Accounting Standards Codification (“ASC”) 605, Revenue Recognition. The new accounting guidance creates aframework under which an entity will allocate the transaction price to separate performance obligations and recognize revenue when each performanceobligation is satisfied. Under the new standard, entities will be required to use judgment and make estimates, including identifying performance obligationsin a contract, estimating the amount of variable consideration to include in the transaction price, allocating the transaction price to each separate performanceobligation, and determining when an entity satisfies its performance obligations. The standard allows for either “full retrospective” adoption, meaning thatthe standard is applied to all of the periods presented with a cumulative catch-up adjustment as of the earliest period presented, or “modified retrospective”adoption, meaning the standardF-13BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSis applied only to the most current period presented in the financial statements with a cumulative catch-up as of the current period. In July 2015, the FASBdecided to defer the original effective date by one year to be effective for annual reporting periods beginning after December 15, 2017 instead of December15, 2016 for public entities, with early adoption permitted. The Partnership intends to use the modified retrospective adoption approach. Based on currentevaluations to-date, the Partnership does not anticipate this new guidance will have a material impact on its consolidated financial statements. ThePartnership is continuing to evaluate the disclosure requirements of this new guidance and does not plan on early adopting this guidance.In February 2016, the FASB issued Accounting Standard Update (“ASU”) No. 2016-02, Leases (Topic 842), which requires lessees to recognize thelease assets and lease liabilities classified as operating leases on the balance sheet. The amendment will be effective for reporting periods beginning on orafter December 15, 2018, and early adoption is permitted. The Partnership is evaluating the impact that the new accounting guidance will have on itsconsolidated financial statements and related disclosures.In March 2016, the FASB issued ASU No. 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to employee share-basedpayment accounting, which includes provisions intended to simplify various aspects related to how share-based compensation payments are accounted forand presented in the financial statements. This amendment will be effective prospectively for reporting periods beginning on or after December 15, 2016, andearly adoption is permitted. The Partnership is evaluating the impact that the new accounting guidance will have on its consolidated financial statements andrelated disclosures.In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments,to address 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 amendments in this ASU are effective for public business entities for fiscal years beginning after December 15, 2017 and interimperiods within those fiscal years. Early adoption is permitted. The Partnership is evaluating the impact that the new accounting guidance will have on itsconsolidated financial statements and related disclosure.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.The following table describes changes to the Partnership’s ARO liability: For the year ended December 31, 2016 2015 (In thousands)Beginning asset retirement obligations$10,585 $9,381Liabilities incurred2,009 272Liabilities settled(317) (143)Accretion expense892 1,075Revisions in estimated costs181 —Ending asset retirement obligations$13,350 $10,585 F-14BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSNOTE 4—ACQUISITIONSAcquisitions of proved oil and natural gas properties and working interests are considered business combinations and are recorded at their estimatedfair value as of the acquisition date. Acquisitions of unproved oil and natural gas properties are considered asset acquisitions and are recorded at cost.On January 8, 2016, the Partnership acquired mineral and royalty interests in the Permian Basin for $10.0 million in cash.On June 15, 2016, the Partnership acquired an oil and natural gas mineral asset package primarily located in Weld County, Colorado for $34.0 millionin cash. The following table summarizes the fair values assigned to the properties acquired: (In thousands)Proved oil and natural gas properties$18,948Unproved oil and natural gas properties14,082Net working capital1,038Asset retirement obligations(50) Total fair value$34,018 On June 17, 2016, the Partnership acquired a diverse oil and natural gas mineral package from Freeport-McMoRan Oil and Gas, Inc. for $87.6 millionin cash. The following table summarizes the fair values assigned to the properties acquired: (In thousands)Proved oil and natural gas properties$20,787Unproved oil and natural gas properties65,745Net working capital1,026 Total fair value$87,558On August 8, 2016, the Partnership acquired mineral interests located in Midland and Glasscock counties of Texas for $8.3 million in cash.Throughout 2016, the Partnership funded certain other oil and natural gas asset acquisitions for an aggregate amount of $1.2 million in cash.The Partnership acquired mineral and royalty interests in the Permian Basin throughout 2015. Separate transactions were closed on June 30, 2015($14.4 million), July 15, 2015 ($7.8 million), August 5, 2015 ($20.3 million), August 21, 2015 ($5.8 million), and September 22, 2015 ($3.4 million).The Partnership acquired acreage in the Eagle Ford Shale play through two transactions: mineral and royalty interests in June of 2015 for $0.5 millionand mineral and royalty and non-operated working interests on September 24, 2015 for $9.2 million.On June 2, 2015, the Partnership also acquired overriding royalty interests in the Utica Shale and Marcellus plays for $1.8 million.During 2014, the Predecessor acquired mineral and royalty interests in the Permian Basin for $16.0 million and the Eagle Ford Shale play for $11.9million. The Predecessor also acquired non-operated working interests in the Haynesville play for $24.6 million and mineral and royalty interests and non-operated working interests in various states for $2.3 million through the issuance of Predecessor units. F-15BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSNOTE 5—DERIVATIVES AND 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 derivative instruments. From time to time, such instruments may include fixed-price-swap contracts, fixed price contracts, costless collars, and other contractual arrangements. The Partnership enters into oil and natural gas derivativeinstrument contracts that contain netting arrangements with each counterparty. The Partnership does not enter into derivative instruments for speculativepurposes.As of December 31, 2016, the Partnership's open derivatives contracts consisted of only fixed-price-swap contracts. A fixed-price-swap contractbetween the Partnership and the counterparty specifies a fixed commodity price and a future settlement date. We have not designated any of our 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 accompyingconsolidated statement of operations. All derivative instruments that have not yet been settled in cash are reflected as either derivative assets or liabilities inthe Partnership’s accompanying consolidated balance sheets as of December 31, 2016 and 2015, respectively. See Note 6 – Fair Value Measurement forfurther discussion.The table below summarizes the fair value and classification of the Partnership’s derivative instruments: As at 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 otherlong-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 As of December 31, 2015Classification Balance Sheet Location Gross FairValue Effect ofCounterpartyNetting Net CarryingValue onBalance Sheet (In thousands) Assets: Current asset Commodity derivative assets $48,260 $— $48,260Long-term asset Deferred charges and otherlong-term assets 16,274 — 16,274Total assets $64,534 $— $64,534Liabilities: Current liability Commodity derivative liabilities $— $— $—Long-term liability Commodity derivative liabilities — — —Total liabilities $— $— $— 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. Changes in the fair value of the Partnership’s commodity derivative instruments (both assets and liabilities) are asfollows:F-16BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the year ended December 31,Derivatives not designated as hedging instruments 2016 2015 2014 (In thousands)Beginning fair value of commodity derivative instruments $64,534 $37,471 $(1,812)Gain (loss) on oil derivative instruments (15,998) 57,681 27,548Gain (loss) on natural gas derivative instruments (20,466) 32,607 9,788Net cash received on settlements of oil derivative instruments (27,450) (41,786) (46)Net cash (received) paid on settlements of natural gas derivative instruments (17,339) (21,439) 1,993Net change in fair value of commodity derivative instruments (81,253) 27,063 39,283Ending fair value of commodity derivative instruments $(16,719) $64,534 $37,471The Partnership had the following open derivative contracts for oil as of December 31, 2016: Volume Weighted Average Range (Per Bbl)Period and Type of Contract (Bbl) (Per Bbl) Low HighOil Swap Contracts: 2017 First quarter 394,000 $61.78 $50.34 $63.65Second quarter 405,000 53.63 51.45 54.38Third quarter 396,000 $ $ $Fourth quarter 396,000 53.12 52.57 53.67The Partnership had the following open derivative contracts for natural gas as of December 31, 2016: Volume Weighted Average Range (Per MMBtu)Period and Type of Contract (MMBtu) (Per MMBtu) Low HighNatural Gas Swap Contracts: 2017 First quarter 8,850,000 $3.40 $3.08 $3.52Second quarter 8,300,000 3.09 2.85 3.18Third quarter 7,730,000 2.97 2.90 3.12Fourth quarter 7,040,000 3.08 2.92 3.29 The Partnership entered into the following derivative contracts for oil subsequent to December 31, 2016: F-17BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS Volume Weighted Average Range (Per Bbl)Period and Type of Contract (Bbl) (Per Bbl) Low HighOil Swap Contracts: 2017 First quarter 90,000 $54.80 $54.28 $55.23Second quarter 210,000 54.90 54.65 55.23Third quarter 160,000 54.94 54.65 55.23Fourth quarter 120,000 55.00 54.65 55.232018 First quarter 475,000 $54.74 $54.50 $55.05Second quarter 445,000 54.73 54.50 54.90Third quarter 425,000 54.72 54.50 54.90Fourth quarter 405,000 54.72 54.50 54.90 The Partnership entered into the following derivative contracts for natural gas subsequent to December 31, 2016: Volume Weighted Average Range (Per MMBtu)Period and Type of Contract (MMBtu) (Per MMBtu) Low HighNatural Gas Swap Contracts: 2017 First quarter 1,740,000 $3.19 $2.95 $3.40Second quarter 4,080,000 3.16 2.95 3.40Third quarter 3,480,000 3.21 3.13 3.41Fourth quarter 3,480,000 3.22 3.13 3.572018 First quarter 4,800,000 $3.01 $2.99 $3.02Second quarter 4,800,000 3.01 2.99 3.02Third quarter 4,800,000 3.01 2.99 3.02Fourth quarter 4,500,000 3.01 2.99 3.02 NOTE 6—FAIR VALUE MEASUREMENTFair 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 establishes a framework for measuring fair value, establishes a fair value hierarchy based onthe quality of inputs used to measure fair value, and includes certain disclosure requirements. Fair value estimates are based on either (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 andliabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levelsare defined as follows:Level 1—Unadjusted quoted prices for identical assets or liabilities in active markets.Level 2—Quoted prices for similar assets or liabilities in non-active markets, and inputs that are observable for the asset or liability, either directly orindirectly, for substantially the full term of the financial instrument.Level 3—Inputs that are unobservable and significant to the fair value measurement (including the Partnership’s own assumptions in determining fairvalue).A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair valuemeasurement. The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment andconsiders factors specific to the asset or liability. There were no transfers into, or out of, the three levels of the fair value hierarchy for the years endedDecember 31, 2016 and 2015.F-18BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSThe carrying value of our cash and cash equivalents, receivables and payables approximate fair value due to the short-term nature of the instruments.The estimated carrying value of all debt as of December 31, 2016 and 2015 approximated the fair value due to variable market rates of interest. These debtfair values, which are Level 3 measurements, were estimated based on the Partnership’s incremental borrowing rates for similar types of borrowingarrangements, when quoted market prices were not available. The estimated fair values of the Partnership’s financial instruments are not necessarilyindicative of the amounts that would be realized in a current market exchange.Assets and Liabilities Measured at Fair Value on a Recurring BasisThe Partnership estimated the fair value of derivative instruments using the market approach via a model that uses inputs that are observable in themarket or can be derived from, or corroborated by, observable data. See Note 5 – Derivatives and Financial Instruments for further discussion.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, 2016 Financial Assets Commodity derivative instruments $— $— $— $— $—Financial Liabilities Commodity derivative instruments — 16,719 — — 16,719As of December 31, 2015 Financial Assets Commodity derivative instruments $— $64,534 $— $— $64,534Financial Liabilities Commodity derivative instruments — — — — —Assets 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 acquiredin a 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 - Acquisitions.Oil 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 economic reserves, future operating and development costs, futurecommodity prices, 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, 2016 and 2015.F-19BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSThe 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 3 Value1 Impairment (In thousands)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 $249,569Year Ended December 31, 2014 Impaired oil and natural gas properties $— $— $81,864 $199,794 $117,930 1 Amount represents net book value at the date of assessment.The carrying value of all debt as of December 31, 2016 and 2015 approximates fair value due to variable market rates of interest. These fair values,which are Level 3 measurements, were estimated based on the Partnership’s incremental borrowing rates for similar types of borrowing arrangements, whenquoted market prices were not available. The estimated fair values of the Partnership’s financial instruments are not necessarily indicative of the amounts thatwould be realized in a current market exchange. NOTE 7—RELATED PARTY TRANSACTIONSThe Predecessor executed promissory notes dated April 15, 2010, in the amount of $0.5 million to certain officers of the Predecessor. The promissorynotes related to the acquisition of a partnership interest in a former affiliate by the officers, and the notes were collateralized by a security interest in thePredecessor. The aggregate outstanding note balance and interest receivable of $0.1 million was received during the year ended December 31, 2014. NOTE 8—SIGNIFICANT CUSTOMERSThe Partnership leases mineral interests to exploration and production companies and participates in non-operated working interests when economicconditions are favorable. Exxon Mobil represented 11.0% of total revenue for the years ended December 31, 2016. No customer represented 10.0% or more oftotal revenue for the years ended December 31, 2015. One company, Chesapeake Energy Corporation, represented 10.0% of total revenue for the year endedDecember 31, 2014.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 9—CREDIT FACILITIESSenior Line of CreditThe Partnership maintains a senior secured revolving credit agreement, as amended, (the “Senior Line of Credit”). The Senior Line of Credit has amaximum credit amount of $1.0 billion . On October 28, 2015, the Senior Line of Credit was further amended to extend the term of the agreement fromFebruary 3, 2017 to February 4, 2019. The amount of the borrowing base is derived from the value of the Partnership’s oil and natural gas propertiesdetermined by the lender syndicate using pricing assumptions that often differ from the current market for future prices. Effective October 28, 2015, theborrowing base was $550.0 million. The Partnership' semi-annual borrowing base redetermination process resulted in a decrease of the borrowing base from$550.0 million to $450.0 million, effective April 15, 2016. The Partnership's fall 2016 borrowing base redetermination process resulted in an increase in theborrowing base from $450.0 million to $500.0 million, which became effective October 31, 2016. Drawings on the Senior Line of Credit are used for theacquisition of oil and natural gas properties and for other general business purposes.Prior to October 31, 2016, borrowings under the Senior Line of Credit bore interest at LIBOR plus a margin between 1.50% and 2.50%, or prime rateplus a margin between 0.50% and 1.50%, with the margin depending on the borrowing base utilization percentage of the loan. The prime rate was determinedto be the higher of the financial institution’s prime rate or the federal funds effective rate plus 0.50% per annum. Effective October 31, 2016, borrowingsunder the Senior Line of Credit bore interest at LIBOR plus a margin between 2.00% and 3.00%, or the Prime rate plus a margin between 1.00% and 2.00%,with the margin depending on the borrowing base utilization of the loan. F-20BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS The weighted-average interest rate of the Senior Line of Credit was 3.26% and 1.92% as of December 31, 2016 and 2015, respectively. Accruedinterest is payable 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 caseinterest is payable 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 of0.375% if the borrowing base utilization percentage is less than 50%, or 0.500% per annum if the borrowing base utilization percentage is equal to or greaterthan 50%. The Senior Line of Credit is secured by substantially all of the Partnership’s oil and natural gas production and assets.The Senior Line of Credit contains various limitations on future borrowings, leases, hedging, and sales of assets. Additionally, the Senior Line ofCredit requires the Partnership 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, 2016, the Partnership was in compliance with all financialcovenants in the Senior Line of Credit.The aggregate principal balance outstanding was $316.0 million and $66.0 million at December 31, 2016 and 2015, respectively. The unused portionof the available borrowings under the Senior Line of Credit was $184.0 million and $484.0 million at December 31, 2016 and 2015, respectively.NOTE 10—INCENTIVE COMPENSATIONOverviewThe Board of Directors of the Partnership’s general partner (“the Board”) adopted a long-term incentive plan (the “2015 LTIP”), pursuant to whichnon-employee directors of the Partnership’s general partner and certain employees and consultants of the Partnership and its affiliates are eligible to receiveawards with respect to the Partnership’s common or subordinated units. On May 6, 2015, the Partnership registered 17,420,310 common and subordinatedunits that are issuable under the 2015 LTIP. The 2015 LTIP permits the grant of unit options, unit appreciation rights, restricted units, unit awards, phantomunits, distribution equivalent rights either in tandem with an award or as a separate award, cash awards, and other unit-based awards. Any vesting termsassociated with incentive awards will be based on a predetermined schedule as approved by the Board.Incentive compensation expense is included in general and administrative expense on the consolidated statements of operations. The totalcompensation expense related to the common and subordinated unit grants is measured as the number of units granted that are expected to vest multiplied bythe grant-date fair value per unit. Incentive compensation expense is recognized using straight-line or accelerated attribution depending on the specific termsof the award agreements over the requisite service periods (generally equivalent to the vesting period).Cash AwardsThe Partnership provides cash long-term incentive awards annually for its executive officers and certain other employees. In 2012, the Predecessoradopted a long-term incentive plan that combined both its management and senior management long-term incentive plans (the “2012 LTI Plan”). Under the2012 LTI Plan, executive officers and certain other members of management are granted fifty percent of their incentive compensation in performance cashawards determined based on achieving specific production and reserves targets as set by the Board. Cash award compensation cliff vests on the thirdanniversary of the grant date, subject to satisfaction of the applicable performance targets so long as the employee remains employed through the vestingdate. Certain other employees are entitled to earn cash bonuses based on service criteria over a four-year requisite service period. Payments are disbursed one-third per year over three years beginning on the first anniversary following December 31 of the service year.On May 6, 2015, cash awards with service-based graded vesting requirements through March 31, 2019 were also granted to certain other employees.Unit Grant AwardsThe remaining fifty percent of incentive compensation was paid in the form of restricted common units of the Predecessor under the 2012 LTI Plan toexecutive officers and certain other members of management. Restricted common units of the Predecessor that were outstanding as of the date of the IPO wereconverted into restricted common and subordinated units of the Partnership in connection with the IPO as set forth in the table below. The convertedrestricted units awarded are subject to restrictions on transferability, customary forfeiture provisions, and time vesting provisions. Each converted award vestspursuant to the original vesting schedule applicable to the restricted unit award of the Predecessor.F-21BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSAward recipients have all the rights of a unitholder in the Partnership with respect to the converted restricted units, including the right to receive distributionsthereon, if and when distributions are made by the Partnership to its limited partners. For awards granted prior to December 31, 2014, recipients could requestthat the Partnership, at its discretion, repurchase up to fifty percent of the restricted common units that are scheduled to vest. As a result of the repurchaseoption, fifty percent of the equity awards to be vested on each vesting date were classified as a liability during the corresponding year prior to the vestingdate until a request for the Partnership to repurchase was made by the recipient, or the repurchase option period ended, which was 30 days prior to the vestingdate. The liability was measured periodically at fair value. In conjunction with the adoption of the 2015 LTIP, the provision in certain of the Predecessor’srestricted unit agreements that allowed award recipients to request cash settlement for up to 50% of their restricted unit awards was removed; as such, theseawards are no longer classified as liability awards. Non-employee directors of the Partnership’s general partner received compensation under the 2015 LTIP inthe form of fully vested common units granted after each year of service.On May 6, 2015, in conjunction with the adoption of the 2015 LTIP, the Board approved a grant of awards to each of the Partnership’s executiveofficers, certain other employees, and each of the non-employee directors of the Partnership’s general partner. The grants included 1,034,013 restrictedcommon units subject to limitations on transferability, customary forfeiture provisions, and service-based graded vesting requirements through April 1, 2019.The holders of restricted common unit awards have all of the rights of a common unitholder, including non-forfeitable distribution rights with respect to theirrestricted common units. The grant-date fair value of these awards, net of estimated forfeitures, is recognized ratably using the straight-line attributionmethod. Additionally, non-employee directors of the Partnership’s general partner received a one-time grant totaling 63,156 fully vested common units.On January 12, 2016, each non-employee director on the Board of Directors of the Partnership’s general partner (the “Board”) was granted 12,368 fullyvested common units for service during 2015. On February 19, 2016, the Compensation Committee of the Board approved a grant of awards to each of thePartnership’s executive officers and certain other employees. These awards consisted of restricted common units and restricted performance units (in the formof phantom units) with distribution equivalent rights. The grants included 717,654 restricted common units subject to limitations on transferability,customary forfeiture provisions, and service-based graded vesting requirements through January 7, 2019. The holders of restricted common unit awards haveall of the rights of a common unitholder, including non-forfeitable distribution rights with respect to their restricted common units. The grant-date fair valueof these awards, net of estimated forfeitures, is recognized ratably using the straight-line attribution method. The Compensation Committee of the Board alsoapproved a grant of 717,654 restricted performance units that are subject to both performance-based and service-based vesting provisions. The number ofcommon units issued to a recipient upon vesting of a restricted performance unit will be calculated based on performance against certain metrics that relate tothe Partnership’s average performance over each calendar year during the performance period commencing January 1, 2016. The target number of commonunits subject to each restricted performance unit is one; however, based on the achievement of performance criteria, the number of common units that may bereceived in settlement of each restricted performance unit can range from zero to two times the target number. The restricted performance units are eligible tobecome earned at the end of the performance period on December 31, 2018. Compensation expense related to the restricted performance unit awards isdetermined by multiplying the number of common units underlying such awards that, based on the Partnership’s estimate, are likely to vest, by the grant-datefair value and recognized using the accelerated attribution method. Distribution equivalent rights for the restricted performance unit awards that are expectedto vest are charged to partners’ capital. The Compensation Committee of the Board also approved the dollar-value targets for performance-based short-termincentive compensation for executive officers of the Partnership and certain other employees. The Partnership expects to ultimately settle the authorizedawards at the end of the performance period in common units of the Partnership.On April 25, 2016, the Compensation Committee of the Board approved a resolution to change the settlement feature of certain employee long-termincentive compensation plans from cash to equity. As a result of the modification, $10.1 million of cash-settled liabilities were reclassified to equity-settledliabilities during the second quarter of 2016 and the remaining unamortized expense of the awards will be amortized as equity-settled liabilities.F-22BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSThe following table summarizes information about restricted units for the year ended December 31, 2016. Units Weighted-Average Grant-Date FairValue per UnitUnits Common Subordinated Common SubordinatedUnvested at December 31, 2015 1,362,091 442,778 $19.08 $19.36Granted 985,239 — 10.58 —Vested (716,753) (224,090) 15.10 19.80Converted — — — —Forfeited (359,362) (55,647) 17.09 18.77Unvested at December 31, 2016 1,271,215 163,041 15.29 18.97The weighted-average grant-date fair value for unit-based awards was $10.09, $18.79, and $20.73 for the years ended December 31, 2016, 2015, and2014, respectively. Unrecognized compensation cost associated with restricted common and subordinated unit awards was $13.1 million and $1.3 million,respectively, as of December 31, 2016, which the Partnership expects to recognize over a weighted-average period of 2.06 years and 1.20 years for commonunits and subordinated units, respectively. The fair value of units vested for the years ended December 31, 2016, 2015, and 2014 was $11.9 million, $9.4million and $8.6 million, respectively. There were no cash payments made for vested units during the years ended December 31, 2016, 2015 and 2014.Performance Unit Grant AwardsOn May 6, 2015, the Board also approved a grant of 947,142 restricted performance units that are subject to both performance-based and service-basedvesting provisions. The number of common units issued to a recipient upon vesting of a restricted performance unit will be calculated based on performanceagainst certain metrics that relate to the Partnership’s performance over each of the four 12-month performance periods commencing April 1, 2015. The targetnumber of common units subject to each restricted performance unit is one; however, based on the achievement of performance criteria, the number ofcommon units that may be received in settlement of each restricted performance unit can range from zero to two times the target number. The restrictedperformance units are eligible to become earned as follows: 16.66%, 16.67%, and 16.67% in each of the 12-month performance periods that end on March31, 2016, March 31, 2017, and March 31, 2018, respectively. The remaining 50% of the restricted performance units are eligible to become earned duringthe final 12-month performance period that ends on March 31, 2019. If the performance criteria are not met for the final performance period, the awards allowfor a make-up period ending on March 31, 2020. Compensation expense related to the restricted performance unit awards is determined by multiplying thenumber of common units underlying such awards that, based on the Partnership’s estimate, are likely to vest, by the grant-date fair value and recognizedusing the accelerated attribution method. Distribution equivalent rights for the restricted performance unit awards that are expected to vest are charged topartners’ capital.The following table summarizes information about performance units for the year ended December 31, 2016. Performance units Units Weighted-Average Grant-Date Fair Valueper UnitUnvested at December 31, 2015 947,142 $19.00Granted 730,632 11.36Vested (216,177) 17.90Forfeited (305,178) 16.88Unvested at December 31, 2016 1,156,419 14.94 Unrecognized compensation cost associated with performance unit awards was $10.8 million as of December 31, 2016, which the Partnership expectsto recognize over a weighted-average period of 1.92 years.F-23BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSIncentive 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, 2016, 2015, and 2014. Year Ended December 31,Incentive compensation expense 2016 2015 2014 (In thousands)Cash—long-term incentive plan $2,725 $15,064 $13,927Equity-based compensation—restricted common and subordinated units 13,408 10,137 7,194Equity-based compensation—restricted performance units 18,518 4,743 —Board of Directors incentive plan 2,012 3,120 4,146Total incentive compensation expense $36,663 $33,064 $25,267 NOTE 11—EMPLOYEE BENEFIT PLANSThe Partnership sponsors a defined contribution 401(k) Profit Sharing Plan (the “401(k) Plan”) for the benefit of substantially all employees of thePartnership. The 401(k) Plan became effective on January 1, 2001 and allows eligible employees to make tax-deferred contributions up to 100% of theirannual compensation, not to exceed annual limits established by the Internal Revenue Service. The Partnership makes matching contributions of 100% ofemployee contributions, up to 5% of compensation. These matching contributions are subject 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 the Partnership. Following three years of employment, future Partnershipmatching contributions vest immediately. The Partnership’s contributions were $0.5 million, $0.6 million, and $0.6 million for the years ended December 31,2016, 2015, and 2014, respectively. NOTE 12—COMMITMENTS AND CONTINGENCIESLeasesThe Partnership leases certain office space and equipment under cancelable and non-cancelable operating leases that end at various dates through2019. The Partnership recognizes rent expense on a straight-line basis over the lease term. Rent expense under such arrangements was $1.9 million, $1.8million, and $1.9 million for the years ended December 31, 2016, 2015, and 2014, respectively. Such amounts are included in general and administrativeexpense on the consolidated statements of operations.Future minimum lease commitments under non-cancelable leases are as follows: Year Ending December 31,(In thousands)2017$1,60320181,6472019352020122021—Total$3,297 Environmental MattersThe Partnership’s business includes activities that are subject to U.S. federal, state and local environmental regulations with regard to air, land, andwater quality 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.F-24BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSLitigationFrom 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, 2016 will be resolved without material adverse effect on the Partnership’s financial condition or results of operations. NOTE 13—REDEEMABLE PREFERRED UNITSThe Partnership has outstanding 52,691 and 77,216 redeemable preferred units outstanding with a carrying value of $54.0 million and $79.2 millionas of December 31, 2016 and 2015, respectively. The aforementioned amounts include accrued distributions of $1.3 million and $1.9 million as ofDecember 31, 2016 and 2015, respectively. The redeemable preferred units are classified as mezzanine equity on the consolidated balance sheets sinceredemption is outside the control of the Partnership. The preferred units are entitled to an annual distribution of 10% of the funded capital of the redeemablepreferred units, payable on a quarterly basis in arrears.Prior to our liquidation, and while any of our redeemable preferred units remain outstanding, cash or other property of the partnership will bedistributed 100% to our redeemable preferred unitholders until the aggregate Unpaid Preferred Yield (as defined below) of each redeemable preferred unitaccrued through the last day of the immediately preceding calendar quarter has been reduced to zero. Distributions in excess of the aggregate UnpaidPreferred Yield will be distributed 100% to common and subordinated unitholders, until there has been distributed an aggregate amount in respect of suchcalendar year equal to 10% of the aggregate Interest Fair Market Value of the outstanding common and subordinated units as of the first day of such calendaryear. Any additional distributions shall be distributed to the common and subordinated unitholders, on the one hand, and the preferred unitholders, on theother 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 preferred units were converted into or exchanged or exercised for common units and, during the subordination period,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 Fair MarketValue equaled the Value (as defined in the partnership agreement) as of such date, adjusted to reflect any increases in equity value resulting from the deemedconversion, exchange or exercise of convertible securities, and (c) an amount equal to such Value (as defined in the partnership agreement), as so adjusted,were distributed to the unitholders in accordance with the liquidation distribution provisions of the partnership agreement.“Preferred Yield” means a yield on the outstanding preferred units equivalent to a 10% per annum interest rate (subject to adjustment following certainevents of default by the partnership) on an initial investment of $1,000, calculated based on a 365-day year and compounded quarterly.“Unpaid Preferred Yield” means, with respect to each preferred unit and as of any date of determination, an amount equal to the excess, if any, of (a)the cumulative Preferred Yield from the closing of this offering through the date established, over (b) the cumulative amount of distributions made as of thedate established in respect of the preferred unit.The redeemable preferred units are convertible into common and subordinated units at the option of the redeemable preferred unitholders. Theredeemable preferred units have an adjusted conversion price of $14.2683 and an adjusted conversion rate of 30.3431 common units and 39.7427subordinated units per redeemable preferred unit, which reflects the reverse split described in Note 1 – Business and Basis of Presentation and the capitalrestructuring related to the IPO. The redeemable preferred unitholders can elect to have the Partnership redeem, at face value, up to 28,266 redeemablepreferred units as of December 31, 2017 and 24,425 redeemable preferred units as of December 31, 2018, plus any accrued and unpaid distributions. The Partnership shall have the right, at its sole option, to redeem an amount of redeemable preferred units equal to the units being redeemed by anowner of redeemable preferred units on each December 31. Any amount of a given year’s redeemable preferred units eligible for redemption not redeemed onDecember 31 shall automatically convert to common and subordinated units on January 1 in the following year.For the year ended December 31, 2016, 18,461 redeemable preferred units were redeemed for $19.0 million, including accrued unpaid yield. For theyear ended December 31, 2016, 6,064 redeemable preferred units totaling $6.1 million were converted into 184,006 common units and 240,986 subordinatedunits as a result of the mandatory conversion subsequent to December 31, 2015. For the year ended December 31, 2015, 39,240 redeemable preferred unitstotaling $39.2 million wereF-25BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSconverted into the equivalent of 1,190,664 common units and 1,559,502 subordinated units on an adjusted basis. For the year ended December 31, 2014, 221redeemable preferred units totaling $0.2 million were converted into 15,489 Predecessor units.On November 6, 2015, the Partnership commenced a tender offer to purchase up to 100% of the then outstanding redeemable preferred units at parvalue plus unpaid accrued yield. The tender offer expired on December 10, 2015. The Partnership purchased and canceled 40,747 redeemable preferred unitsfor $1,019.45 per unit for a total cost of $41.5 million, excluding fees and expenses related to the tender offer. NOTE 14—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 subordinatedunitholders in proportion to their pro rata ownership after giving effect to distributions, if any, declared during the period. The redeemable preferred unitscould be converted into 1.6 million common units and 2.1 million subordinated units as of December 31, 2016. At December 31, 2016, if the redeemablepreferred units were converted to common and subordinated units, the effect would be anti-dilutive. Therefore, the redeemable preferred units are notincluded in the diluted EPU calculation. The Partnership’s restricted performance unit awards are contingently issuable units that are considered in thecalculation of diluted EPU. The Partnership assesses the number of units that would be issuable, if any, under the terms of the arrangement if the end of thereporting period were the end of the contingency period. As of December 31, 2016, there were no units related to the Partnership’s restricted performance unitawards included in the calculation of diluted EPU as the inclusion of these units would be antidilutive.The following table sets forth the computation of basic and diluted earnings per unit: For the Year Ended December 31, 2016 2015 2014 (In thousands, except per unit amounts)NET INCOME (LOSS) $20,188 $(101,305) $169,187NET (INCOME) LOSS ATTRIBUTABLE TO PREDECESSOR — (450) (169,187)NET (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTSSUBSEQUENT TO INITIAL PUBLIC OFFERING 12 1,260 —DISTRIBUTIONS ON REDEEMABLE PREFERRED UNITS SUBSEQUENT TO INITIALPUBLIC OFFERING (5,763) (7,522) —NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON ANDSUBORDINATED UNITS SUBSEQUENT TO INITIAL PUBLIC OFFERING $14,437 $(108,017) $—ALLOCATION OF NET INCOME (LOSS) SUBSEQUENT TO INITIAL PUBLIC OFFERINGATTRIBUTABLE TO: General partner interest $— $— Common units 24,669 (54,326) Subordinated units (10,232) (53,691) $14,437 $(108,017) NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON ANDSUBORDINATED UNIT: Per common unit (basic) $0.26 $(0.56) Weighted average common units outstanding (basic) 96,073 96,182 Per subordinated unit (basic) $(0.11) $(0.56) Weighted average subordinated units outstanding (basic) 95,138 95,057 Per common unit (diluted) $0.26 $(0.56) Weighted average common units outstanding (diluted) 96,243 96,182 Per subordinated unit (diluted) $(0.11) $(0.56) Weighted average subordinated units outstanding (diluted) 95,138 95,057 F-26BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTSNOTE 15—COMMON UNIT REPURCHASE PROGRAMOn March 4, 2016, the Board of Directors of the Partnership's general partner (the “Board”) authorized the repurchase of up to $50.0 million incommon units through a program that terminated on September 15, 2016. The repurchase program authorized the Partnership to make repurchases on adiscretionary basis as determined by management, subject to market conditions, applicable legal requirements, available liquidity, and other appropriatefactors. The Partnership repurchased a total of 1.3 million common units for an aggregate cost of $20.2 million . The repurchase program was funded from thePartnership's cash on hand or available revolving credit facility. Repurchased common units were canceled.NOTE 16—SUBSEQUENT EVENTSOn February 9, 2017, the Board approved a distribution for the period October 1, 2016 to December 31, 2016 of $0.2875 per common unit and$0.18375 per subordinated unit. Distributions were paid on February 27, 2017 to unitholders of record at the close of business on February 20, 2017.During January 2017, the Partnership closed four mineral interest transactions in Loving County, Texas for approximately $32.0 million in cash, withborrowings from the Senior Credit facility, and $11.8 million of the Partnership's common units. Two Haynesville/Bossier Shale mineral interest transactionsclosed for $6.4 million. Two additional mineral interest acquisitions closed in Angelina County, Texas for approximately $8.6 million.On February 2, 2017 the Partnership filed a shelf registration statement, on Form S-3, with the U.S. Securities and Exchange Commission for theissuance of the Partnership's common units. The filing became effective on February 8, 2017.On February 15, 2017, the Board granted 750,892 restricted common units and 438,067 restricted performance units at a grant-date fair value of$18.30 per unit under the 2015 LTIP.On 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 average 50% workinginterest in the acreage and is the largest mineral owner. A total of 58 wells are anticipated to be drilled over an initial phase, beginning with wells spud afterJanuary 1, 2017. At its option, Canaan may participate in two additional phases with each phase estimated to last approximately two years. During the threephases 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 assigned80% of the Partnership's working interests in such wells (40% working interest on an 8/8ths basis). After the third phase, Canaan can earn 40% of thePartnership’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'scosts for those wells on a well-by-well basis. The Partnership will receive a base overriding royalty interest (“ORRI”) before payout and an additional ORRIafter payout on all wells drilled under the agreement. The execution of this agreement is anticipated to reduce the Partnership's future capital obligations byapproximately $30-$35 million in 2017 and by an average of $40-$50 million annually, thereafter.F-27BLACK 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 United States. Therefore, the followingdisclosures about 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, 2016 2015 2014 (In thousands)Acquisition Costs of Properties:1 Proved $40,242 $2,302 $13,215Unproved 100,888 60,994 35,706Exploration Costs 645 2,592 631Development Costs 73,316 60,056 50,595Total $215,091 $125,944 $100,147 1. See Note 4 – 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, 2016 2015 (In thousands)Proved properties $2,091,337 $1,957,648Unproved properties 605,736 524,563Total 2,697,073 2,482,211Accumulated depreciation, depletion, amortization, and impairment (1,652,930) (1,543,796)Oil and natural gas properties, net $1,044,143 $938,415 F-28Oil and Natural Gas Reserve Information—UnauditedThe 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, 2013 18,949 239,960 58,942Revisions of previous estimates1 (1,904) (20,764) (5,365)Purchases of minerals in place2 89 7,439 1,329Extensions, discoveries and other additions3 2,938 19,894 6,254Production (3,005) (42,273) (10,051)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 place4 8 367 69Extensions, discoveries and other additions5 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 place6 1,322 5,683 2,269Extensions, discoveries and other additions7 1,877 79,455 15,120Production (3,680) (47,498) (11,596)Net proved reserves at December 31, 2016 18,368 270,339 63,425Net Proved Developed Reserves8 December 31, 2014 16,700 202,888 50,514December 31, 2015 15,497 174,555 44,590December 31, 2016 18,150 223,057 55,327Net Proved Undeveloped Reserves9 December 31, 2014 367 1,368 595December 31, 2015 345 29,120 5,198December 31, 2016 218 47,282 8,0981 Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors. Themost 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.5 Includes discoveries and additions primarily related to active drilling in the Haynesville/Bossier, Bakken/Three Forks, Wilcox, Eagle Ford, and Fayettevilleplays.6 Includes the acquisition of mineral-and-royalty reserves primarily in the Permian and Denver basins.7 Includes extensions and additions primarily related to the active drilling program in the Haynesville/Bossier play.8 Proved developed reserves of 74 MBoe, 84 MBoe and 87 MBoe as of December 31, 2016, 2015, and 2014, respectively, were attributable to noncontrollinginterests in the Partnership’s consolidated subsidiaries.9 As of December 31, 2016, 2015, and 2014, no proved undeveloped reserves were attributable to noncontrolling interests. F-29Standardized Measure of Discounted Future Net Cash Flows—UnauditedFuture cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the 12-month unweightedaverage of first-day-of-the-month commodity prices for the periods presented. All prices are adjusted by field for quality, transportation fees, energy contentand regional 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, 2016 2015 2014 (In thousands)Future cash inflows $1,267,179 $1,211,290 $2,493,294Future production costs (193,749) (205,861) (405,833)Future development costs (36,509) (84,746) (64,968)Future income tax expense (3,516) — —Future net cash flows (undiscounted) 1,033,405 920,683 2,022,493Annual discount 10% for estimated timing (430,390) (365,711) (879,399)Total1 $603,015 $554,972 $1,143,094 1 Includes standardized measure of discounted future net cash flows of approximately $0.6 million, $0.7 million, and $1.4 million for December 31, 2016,2015, and 2014, 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, 2016 2015 2014 (In thousands)Standardized measure, beginning of year $554,972 $1,143,094 $1,185,257Sales, net of production costs (210,354) (222,206) (391,983)Net changes in prices and production costs related to future production (81,456) (621,065) 75,284Extensions, discoveries and improved recovery, net of future production anddevelopment costs 86,606 165,020 209,651Previously estimated development costs incurred during the period 28,909 7,084 12,162Revisions of estimated future development costs — 669 7,854Revisions of previous quantity estimates, net of related costs 147,507 (67,911) (110,431)Accretion of discount 55,662 114,309 118,526Purchases of reserves in place, less related costs 34,751 584 24,210Other (13,582) 35,394 12,564Net increase (decrease) in standardized measures 48,043 (588,122) (42,163)Standardized measure, end of year $603,015 $554,972 $1,143,094 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 pricesF-30and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to thecomputational methods utilized and the limitations inherent therein. F-31Selected Quarterly Financial Information—UnauditedQuarterly financial data was as follows for the periods indicated. First Quarter Second Quarter Third Quarter Fourth Quarter2 (In thousands, except for per unit data)2016 Total revenue $64,381 $40,569 $99,171 $56,712Income (loss) from operations 11,610 (19,478) 39,316 (3,979)Net income (loss) 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) .09 (0.08) 0.24 0.01Per subordinated unit (basic) .01 (0.15) 0.14 (0.11)Net income (loss) attributable to common and subordinated units per unit(diluted)1 Per common unit (diluted) .09 (0.08) 0.24 0.01Per subordinated unit (diluted) .01 (0.15) 0.14 (0.11)Cash distributions declared and paid 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 54,0152015 Total revenue $91,061 $64,803 $137,020 $100,040Net income (loss) 17,299 (122,766) 53,892 (49,730)Net income (loss) attributable to the general partner and common andsubordinated units * (107,587) 50,916 (51,346)Net income (loss) attributable to common and subordinated units per unit (basic)1 Per common unit (basic) * (0.56) 0.27 (0.27)Per subordinated unit (basic) * (0.56) 0.27 (0.27)Net income (loss) attributable to common and subordinated units per unit(diluted)1 Per common unit (diluted) * (0.56) 0.27 (0.27)Per subordinated unit (diluted) * (0.56) 0.27 (0.27)Cash distributions declared per limited partner unit Per common unit * * 0.1615 0.2625Per subordinated unit * * 0.1615 0.2625Total assets $1,274,291 $1,118,569 $1,161,446 $1,061,436Long-term debt 389,000 6,000 43,000 66,000Total mezzanine equity 120,889 120,904 120,936 79,162* Information is not applicable for the periods prior to the initial public offering.1 See Note 14 – 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-32Exhibit 10.3 Second AmendmentToThird Amended and RestatedCredit AgreementDated as of October 31, 2016AmongBlack 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, LLCSECOND AMENDMENT TO THIRD AMENDEDAND RESTATED CREDIT AGREEMENTTHIS SECOND AMENDMENT TO THIRD AMENDED AND RESTATED CREDIT AGREEMENT (this “SecondAmendment”) dated as of October 31, 2016, is among: BLACK STONE MINERALS COMPANY, L.P., a Delaware limitedpartnership (the “Borrower”); BLACK STONE MINERALS, L.P., a Delaware limited partnership (the “Parent MLP”); each of thelenders party to the Credit Agreement referred to below (collectively, the “Lenders”); and WELLS FARGO BANK, NATIONALASSOCIATION, 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 Third Amended andRestated Credit Agreement dated as of January 23, 2015, as amended by First Amendment to Third Amended and Restated CreditAgreement dated as of October 28, 2015 (as amended, modified or supplemented to date, the “Credit Agreement”), pursuant to whichthe Lenders have made certain credit 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 to,among other things, amend the pricing grid and approve the new Borrowing Base.C. Now, therefore, to induce the Administrative Agent and the Lenders to enter into this Second Amendment and inconsideration of the premises and the mutual covenants herein contained, for good and valuable consideration, the receipt andsufficiency of which are hereby acknowledged, the parties hereto agree as follows:Section 1.Defined Terms. Each capitalized term used herein but not otherwise defined herein has the meaninggiven such term in the Credit Agreement, as amended by this Second Amendment. Unless otherwise indicated, all section references inthis Second Amendment refer to sections of the Credit Agreement.Section 2. Amendments to Credit Agreement2.1 Amendments to Section 1.02. Section 1.02 is hereby amended by deleting the following definition in its entirety andreplacing it with the following:“Agreement” means this Third Amended and Restated Credit Agreement, as amended by the First Amendment to ThirdAmended and Restated Credit Agreement dated as of October 28, 2015 and Second Amendment to Third Amended andRestated Credit Agreement dated as of October 31, 2016, as the same may be amended or supplemented from time to time.The table set forth in the definition of “Applicable Margin” in Section 1.02 is hereby amended by deleting such table in itsentirety and replacing it with the following:Aggregate Elected Commitment Utilization Grid <25%>25%<50%>50%<75%>75%<90%>90%Eurodollar Margin2.00%2.25%2.50%2.75%3.00%Base RateMargin1.00%1.25%1.50%1.75%2.00%The definition of “Defaulting Lender” in Section 1.02 is hereby amended by adding “or become the subject of a Bail-InAction” at the end thereof.The definition of “Federal Funds Rate” in Section 1.02 is hereby amended by adding a new sentence at the end thereof, to readas follows:Notwithstanding anything to the contrary herein, in no event shall the Federal Funds Rate be less than 0%.Section 1.02 is hereby amended by adding the following definitions where alphabetically appropriate to read as follows:“Account Control Agreement” means a control agreement, in form and substance reasonably satisfactory to theAdministrative Agent, which grants the Administrative Agent “control” as defined in the Uniform Commercial Code in effectin the applicable jurisdiction over any Deposit Account, Securities Account or Commodities Account maintained by any LoanParty, in each case, among the Administrative Agent, the applicable Loan Party and the applicable financial institution at whichsuch Deposit Account, Securities Account or Commodities Account is maintained.“Bail-In Action” means the exercise of any Write-Down and Conversion Powers by the applicable EEA ResolutionAuthority in respect of any liability of an EEA Financial Institution.“Bail-In Legislation” means, with respect to any EEA Member Country implementing Article 55 of Directive2014/59/EU of the European Parliament and of the Council of the European Union, the implementing law for such EEAMember Country from time to time which is described in the EU Bail-In Legislation Schedule.“Commodities Account” shall have the meaning set forth in Article 9 of the UCC.“Deposit Account” shall have the meaning set forth in Article 9 of the UCC.“EEA Financial Institution” means (a) any credit institution or investment firm established in any EEA MemberCountry which is subject to the supervision of an EEA Resolution Authority, (b) any entity established in an EEA MemberCountry which is a parent of an institution described in clause (a) of this definition, or (c) any financial institutionestablished in an EEA Member Country which is a subsidiary of an institution described in clauses (a) or (b) of this definitionand is subject to consolidated supervision with its parent;“EEA Member Country” means any of the member states of the European Union, Iceland, Liechtenstein, and Norway.“EEA Resolution Authority” means any public administrative authority or any person entrusted with publicadministrative authority of any EEA Member Country (including any delegee) having responsibility for the resolution of anyEEA Financial Institution.“EU Bail-In Legislation Schedule” means the EU Bail-In Legislation Schedule published by the Loan MarketAssociation (or any successor person), as in effect from time to time.“Excluded Accounts” means (a) any Deposit Account, Commodity Account or Securities Account so long as thebalance in each such account, individually, does not exceed $2,500,000 at any time and the aggregate balance of all suchDeposit Accounts, Commodity Accounts and Securities Accounts does not at any time exceed $5,000,000, (b) any DepositAccount that is a zero balance account or a Deposit Account for which the balance of such Deposit Account is transferred atthe end of each date to a Deposit Account that is not an Excluded Account, (c) any other Deposit Accounts exclusively usedfor trust, payroll, payroll taxes and other employee wage and benefit payments to or for the benefit of any employees of theLoan Parties or any of their subsidiaries and (d) any other Deposit Account, Commodity Account or Securities Account that ispledged to a third party to the extent such Lien is permitted by the Loan Documents.“Securities Account” shall have the meaning set forth in Article 8 of the UCC.“UCC” means the Uniform Commercial Code, as in effect from time to time, of the State of Texas or of any other statethe laws of which are required as a result thereof to be applied in connection with the attachment, perfection or priority of, orremedies with respect to, Administrative Agent’s or any Secured Party’s Lien on any Collateral.“Write-Down and Conversion Powers” means, with respect to any EEA Resolution Authority, the write-down andconversion powers of such EEA Resolution Authority from time to time under the Bail-In Legislation for the applicable EEAMember Country, which write-down and conversion powers are described in the EU Bail-In Legislation Schedule.2.2 Amendment to Section 7.24. The reference to “After giving effect to the transactions contemplated hereby” in the firstsentence of Section 7.24 of the Credit Agreement is hereby amended to refer instead to “After giving effect to the transactionscontemplated hereby and each Borrowing made hereunder”.2.3 Amendment to Article VII. Article VII of the Credit Agreement is hereby amended by adding a new Section 7.28 at theend thereof, to read as follows:Section 7.28. EEA Financial Institution. No Loan Party is an EEA Financial Institution.2.4 Amendment to Section 8.09. Section 8.09 of the Credit Agreement is hereby amended by adding a new subsection (d) atthe end thereof, to read as follows:(d) Each Loan Party will cause each of their respective Deposit Accounts, Commodities Accounts or SecuritiesAccounts (in each case, other than Excluded Accounts) to at all times either be maintained with the Administrative Agent orsubject to an Account Control Agreement.2.5 Amendment to Article XII. Article XII of the Credit Agreement is hereby amended by adding a new Section 12.20 at theend thereof, to read as follows:Section 12.20. Acknowledgment and Consent to Bail-In of EEA Financial Institutions. Notwithstanding anything tothe contrary in any Loan Document or in any other agreement, arrangement or understanding among any such parties, eachparty hereto acknowledges that any liability of any EEA Financial Institution arising under any Loan Document, to the extentsuch liability is unsecured, may be subject to the write-down and conversion powers of an EEA Resolution Authority andagrees and consents to, and acknowledges and agrees to be bound by:(a)the application of any Write-Down and Conversion Powers by an EEA Resolution Authority to any suchliabilities arising hereunder which may be payable to it by any party hereto that is an EEA Financial Institution; and(b)the effects of any Bail-In Action on any such liability, including, if applicable:(i)a reduction in full or in part or cancellation of any such liability;(ii)a conversion of all, or a portion of, such liability into shares or other instruments of ownership in suchEEA Financial Institution, its parent undertaking, or a bridge institution that may be issued to it or otherwise conferred on it,and that such shares or other instruments of ownership will be accepted by it in lieu of any rights with respect to any suchliability under this Agreement or any other Loan Document; or(iii)the variation of the terms of such liability in connection with the exercise of the Write-Down andConversion Powers of any EEA Resolution Authority.Section 3 Borrowing Base. All of the Lenders and the Borrower agree that, from and after the Second AmendmentEffective Date (as defined below) until the next redetermination of the Borrowing Base, the amount of the Borrowing Baseshall be $500,000,000. This provision does not limit the right of the parties to initiate interim redeterminations of the BorrowingBase in accordance with Section 2.08(b) or further adjustments pursuant to Section 2.08(e) or (f), Section 8.08, Section 9.02(i)or (j) or Section 9.13. This Section 3 of this Amendment constitutes written notice of the redetermined Borrowing Base inaccordance with Section 2.08(d).Section 4. Assignments and Reallocation of Commitments and Loans. The Lenders have agreed among themselves, inconsultation with the Borrower, to reallocate their respective Commitments. The Administrative Agent and the Borrower herebyconsent to such reallocation and the Lenders’ assignments of their Commitments. On the Second Amendment Effective Date and aftergiving effect to such reallocations, the Commitment of each Lender shall be as set forth on Annex I of this Second Amendment andsuch Commitments shall supersede and replace those set forth on Schedule 2.01. With respect to such reallocation, each Lender shallbe deemed to have acquired the Commitment allocated to it from or to (as applicable) each of the other Lenders pursuant to the termsof the Assignment and Assumption attached as Exhibit E to the Credit Agreement as if each such Lender had executed an Assignmentand Assumption with respect to such allocation. In connection with this Assignment and for purposes of this Assignment only, theLenders, the Administrative Agent and the Borrower waive the processing and recordation fee under Section 12.06(b).Section 5. Conditions Precedent. This Second Amendment shall become effective on the date (such date, the “SecondAmendment Effective Date”), when each of the following conditions is satisfied (or waived in accordance with Section 12.04):5.1 The Administrative Agent shall have received from each of the Lenders, the Parent MLP, and the Borrower, counterparts(in such number as may be requested by the Administrative Agent) of this Second Amendment signed on behalf of such Person.5.2 The Administrative Agent shall have received the Consent and Agreement attached to this Second Amendment executedby the Guarantors (in such numbers as may be requested by the Administrative Agent).5.3 The Administrative Agent and the Lenders shall have received all fees and other amounts due and payable on or prior tothe date hereof, including, to the extent invoiced, reimbursement or payment of all documented out-of-pocket expenses required to bereimbursed or paid by the Borrower under the Credit Agreement.5.4 No Default or Event of Default shall have occurred and be continuing as of the date hereof, immediately after givingeffect to the terms of this Second Amendment.The Administrative Agent is hereby authorized and directed to declare this Second Amendment to be effective when it hasreceived documents confirming or certifying, to the satisfaction of the Administrative Agent, compliance with the conditions set forthin this Section 5 of this Amendment or the waiver of such conditions as permitted in Section 12.04. Such declaration shall be final,conclusive and binding upon all parties to the Credit Agreement for all purposes.Section 6. Post-Closing Obligations6.1 On or prior to November 30, 2016 (or such later date as Administrative Agent may agree), Administrative Agent shallhave received amendments to the mortgages and deeds of trust constituting Security Instruments, in form and substance reasonablysatisfactory to the Administrative Agent executed by the Borrower and acknowledged (in such numbers as may be requested by theAdministrative Agent) as may be required by Section 8.09(a) of the Credit Agreement in connection with the redetermination of theBorrowing Base set forth above.6.2 On or prior to December 31, 2016 (or such later date as Administrative Agent may agree), Administrative Agent shallhave received any Account Control Agreements required to be delivered pursuant to Section 8.09(d) of the Credit Agreement withrespect to any Deposit Accounts, Securities Accounts or Commodities Accounts maintained by any Loan Party as of the date hereof.Section 7. Miscellaneous7.1 Confirmation. The provisions of the Credit Agreement, as amended and waived by this Second Amendment, shall remainin full force and effect following the effectiveness of this Second Amendment.7.2 Ratification and Affirmation; Representations and Warranties. Each of the Borrower and the Parent MLP hereby (a)ratifies and affirms its obligations under, and acknowledges its continued liability under, each Loan Document to which it is a partyand agrees that each Loan Document to which it is a partyremains in full force and effect as expressly amended or waived hereby and (b) represents and warrants to the Lenders that as of thedate hereof, after giving effect to the terms of this Second Amendment:(i)all of the representations and warranties contained in each Loan Document to which it is a party aretrue and correct in all material respects, except to the extent any such representations and warranties are expresslylimited to an earlier date, in which case, such representations and warranties shall continue to be true and correct as ofsuch 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 beexpected to have a Material Adverse Effect.7.3 Counterparts. This Second Amendment may be executed by one or more of the parties hereto in any number of separatecounterparts, and all of such counterparts taken together shall be deemed to constitute one and the same instrument. Delivery of thisSecond Amendment by facsimile transmission shall be effective as delivery of a manually executed counterpart hereof.7.4 NO ORAL AGREEMENT. THIS SECOND AMENDMENT, THE CREDIT AGREEMENT AND THEOTHER LOAN DOCUMENTS EXECUTED IN CONNECTION HEREWITH AND THEREWITH REPRESENT THEFINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OFPRIOR, CONTEMPORANEOUS, OR SUBSEQUENT UNWRITTEN ORAL AGREEMENTS OF THE PARTIES.THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.7.5 GOVERNING LAW. THIS SECOND AMENDMENT SHALL BE GOVERNED BY, AND CONSTRUED INACCORDANCE WITH, THE LAWS OF THE STATE OF TEXAS.7.6 Payment of Expenses. In accordance with Section 12.03, the Borrower agrees to pay or reimburse the AdministrativeAgent for all of its reasonable out-of-pocket expenses incurred in connection with this Second Amendment, any other documentsprepared in connection herewith and the transactions contemplated hereby, including, without limitation, the reasonable fees, chargesand disbursements of counsel to the Administrative Agent.7.7 Severability. Any provision of this Second Amendment which is prohibited or unenforceable in any jurisdiction shall, asto such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisionshereof, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision inany other jurisdiction.7.8 Successors and Assigns. This Second Amendment shall be binding upon and inure to the benefit of the parties hereto andtheir respective successors and assigns.7.9 Loan Document. This Second Amendment is a Loan Document.[SIGNATURES BEGIN NEXT PAGE]IN WITNESS WHEREOF, the parties hereto have caused this Second Amendment to be duly executed as of the date firstwritten above. BLACK STONE MINERALS COMPANY, L.P., as Borrower 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/ Richard M. Carroll Richard M. Carroll Senior Vice President, Chief Financial Officer and Treasurer BLACK STONE MINERALS, L.P., as Parent MLP By:Black Stone Minerals GP, L.L.C. its General Partner By:/s/ Richard M. Carroll Richard M. Carroll Senior Vice President, Chief Financial Officer and TreasurerSIGNATURE PAGESECOND AMENDMENT TO CREDIT AGREEMENT WELLS FARGO BANK, NATIONAL ASSOCIATION, as Administrative Agent, Issuing Bank and a Lender By: /s/ Greg Smothers Name: Greg Smothers Title: Director BANK OF AMERICA, N.A., as a Lender By: /s/ Alia Qaddumi Name: Alia Qaddumi Title: Director COMPASS BANK, as a Lender By: /s/ Les Werme Name: Les Werme Title: Director JPMORGAN CHASE BANK N.A., as a Lender By: /s/ Theresa M. Benson Name: Theresa M. Benson Title: Authorized Officer 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 PresidentSIGNATURE PAGESECOND AMENDMENT TO CREDIT AGREEMENT ZB BANK, N.A., DBA AMEGY BANK, NATIONAL ASSOCIATION, as a Lender By: /s/ Sam Trail Name: Sam Trail Title: Senior Vice President THE BANK OF NOVA SCOTIA, as a Lender By: /s/ Alan Dawson Name: Alan Dawson Title: Director IBERIABANK, as a Lender By: /s/ Tyler S. Thoem Name: Tyler S. Thoem Title: Senior Vice President 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 COMERICA BANK, as a Lender By: /s/ William Robinson Name: William Robinson Title: Senior Vice President KEYBANK, NATIONAL ASSOCIATION, as a Lender By: /s/ George E. McKean Name: George E. McKean Title: Senior Vice PresidentSIGNATURE PAGESECOND AMENDMENT TO CREDIT AGREEMENT TEXAS CAPITAL BANK, N.A., as a Lender By: /s/ W. David McCarver IV Name: W. David McCarver IV Title: Executive Vice President BOKF, N.A. DBA BANK OF TEXAS., as a Lender By: /s/ Mari Salazar Name: Mari Salazar Title: Senior Vice PresidentSIGNATURE PAGESECOND AMENDMENT TO CREDIT AGREEMENTANNEX ILIST OF MAXIMUM CREDIT AMOUNTS AND ELECTED COMMITMENTSName of LenderPercentage ShareMaximum Credit AmountElected CommitmentWells Fargo Bank, N.A.18.333333334%$183,333,333.34$91,666,666.67Bank of America, N.A.12.500000000%$125,000,000.00$62,500,000.00Compass Bank12.500000000%$125,000,000.00$62,500,000.00JPMorgan Chase Bank, N.A.10.000000000%$100,000,000.00$50,000,000.00Natixis, New York Branch8.333333333%$83,333,333.33$41,666,666.66ZB, N.A., dba Amegy Bank, National Association6.666666667%$66,666,666.67$33,333,333.33The Bank of Nova Scotia6.666666667%$66,666,666.67$33,333,333.33IBERIABANK5.000000000%$50,000,000.00$25,000,000.00ABN AMRO Capital USA LLC5.000000000%$50,000,000.00$25,000,000.00Comerica Bank5.000000000%$50,000,000.00$25,000,000.00Key Bank, National Association3.333333333%$33,333,333.33$16,666,666.67Texas Capital Bank, N.A.3.333333333%$33,333,333.33$16,666,666.67BOKF, N.A. dba Bank of Texas3.333333333%$33,333,333.33$16,666,666.67TOTAL100.000000000%$1,000,000,000.00$500,000,000.00[Second Amendment]CONSENT AND AGREEMENTEach of the undersigned hereby (i) consents to the provisions of this Second Amendment and the transactions contemplatedherein, (ii) ratifies and confirms the Fourth Amended and Restated Guaranty and Collateral Agreement dated as of October 28, 2013,as amended, modified or supplemented to date, made by it for the benefit of Administrative Agent and Lenders executed pursuant tothe Credit Agreement and the other Loan Documents, (iii) ratifies and confirms all other Loan Documents made by it for the benefit ofAdministrative Agent and Lenders, (iv) agrees that all of its respective obligations and covenants thereunder, except as may beamended or modified hereby, shall remain unimpaired by the execution and delivery of this Second Amendment and the otherdocuments and instruments executed in connection herewith, and (v) agrees that such Fourth Amended and Restated Guaranty andsuch other Loan Documents 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 firstwritten 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/ Richard M. Carroll Richard M. CarrollSenior Vice President, Chief Financial Officer and Treasurer BSML PARTNERSHIP By:Black Stone Minerals Company, L.P.,its Managing Partner 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/ Richard M. Carroll Richard M. CarrollSenior Vice President, Chief Financial Officer and TreasurerSIGNATURE PAGESECOND AMENDMENT TO CREDIT AGREEMENT 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/ Richard M. Carroll Richard M. CarrollSenior Vice President, Chief Financial Officer and Treasurer TLW INVESTMENTS, L.L.C. By:Black Stone Natural Resources, L.L.C.,its sole Manager By:Black Stone Minerals Company, L.P.,its sole Memberits General Partner 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/ Richard M. Carroll Richard M. CarrollSenior Vice President, Chief Financial Officer and TreasurerSIGNATURE PAGESECOND AMENDMENT TO CREDIT AGREEMENT BSAP II GP, L.L.C. By:Black Stone Natural Resources, L.L.C.,its sole Manager By:Black Stone Minerals Company, L.P.,its sole Memberits General Partner 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/ Richard M. Carroll Richard M. CarrollSenior Vice President, Chief Financial Officer and Treasurer BLACK STONE MINERALS, L.P. By:Black Stone Minerals GP, L.L.C.its General Partner By:/s/ Richard M. Carroll Richard M. CarrollSenior Vice President, Chief Financial Officer and Treasurer BSMC GP, L.L.C. By:Black Stone Minerals, L.P.its Sole Member By:/s/ Richard M. Carroll Richard M. CarrollSenior Vice President, Chief Financial Officer and TreasurerSIGNATURE PAGESECOND AMENDMENT TO CREDIT AGREEMENTExhibit 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. DelawareBSML Partnership TexasO’Connell Holdings, L.L.C. DelawareO’Connell Partners, L.P. DelawareTLW Investments, L.L.C. OklahomaExhibit 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) of Black Stone Minerals, 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 March 1, 2017, 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 Black Stone Minerals, L.P. for the year ended December 31, 2016./s/ Ernst & Young LLP Houston, TexasMarch 1, 2017Exhibit 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 and 2014 consolidated financial statements, which appears inthis Form 10-K./s/ BDO USA, LLPHouston, TexasMarch 1, 2017Exhibit 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, 2016, and the inclusion of our corresponding report letter, dated January 23, 2017, inthe 2016 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., P.E. J. Carter Henson, Jr.,P.E. Senior VicePresidentHouston, TexasMarch 1, 2017Exhibit 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 thisreport;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) and15d-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 oursupervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to usby others within those 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 designedunder our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation offinancial statements for external 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 aboutthe effectiveness 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’smost recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or isreasonably likely to materially 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, tothe registrant’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’sinternal control over financial reporting. Date:March 1, 2017 /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 thisreport;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) and15d-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 oursupervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to usby others within those 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 designedunder our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation offinancial statements for external 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 aboutthe effectiveness 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’smost recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or isreasonably likely to materially 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, tothe registrant’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’sinternal control over financial reporting. Date:March 1, 2017 /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 theCompany. Date:March 1, 2017 /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:March 1, 2017 /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 23, 2017Mr. 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, 2016, to the Black StoneMinerals, L.P. (Black Stone) interest in certain oil and gas properties located in the United States. We completed our evaluation on or about thedate of this letter. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by BlackStone. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and ExchangeCommission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for Black Stone'suse in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate forsuch purpose.We estimate the net reserves and future net revenue to the Black Stone interest in these properties, as of December 31, 2016, to be: Net Reserves Future Net Revenue (M$) Oil Gas Present WorthCategory (MBBL) (MMCF) Total at 10% Proved Developed Producing 18,030.0 189,319.5 923,850.5 527,557.3Proved Developed Non-Producing 120.7 33,737.1 65,115.7 48,686.1Proved Undeveloped 218.2 47,281.9 47,954.4 28,873.9 Total Proved 18,369.0 270,338.5 1,036,920.6 605,117.3Totals 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 42United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.The estimates shown in this report are for proved reserves. No study was made to determine whether probable or possible reserves might beestablished for these properties. This report does not include any value that could be attributed to interests in undeveloped acreage beyond thosetracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reservessubcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not beenadjusted for risk.Gross revenue is Black Stone's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is afterdeductions for Black Stone's share of production taxes, ad valorem taxes, capital costs, and operating expenses but before consideration of anyincome taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown toindicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not beconstrued as being the fair market value of the properties.Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the periodJanuary through December 2016. For oil volumes, the average West Texas Intermediate spot price of $42.75 per barrel is adjusted for quality,transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $2.481 per MMBTU is adjusted for energycontent, transportation fees, and market differentials. When applicable, gas prices have been adjusted to include the value for natural gas liquids.All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaininglives of the properties are $37.50 per barrel of oil and $2.139 per MCF of gas.Operating costs used in this report are based on operating expense records of Black Stone, where available. For other properties, we haveestimated operating costs based on our knowledge of similar operations in the area. Operating costs include the per-well overhead expensesallowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Operating costshave been divided into per-well costs and per-unit-of-production costs. Since all properties are nonoperated, headquarters general andadministrative overhead expenses of Black Stone are not included. Operating costs are not escalated for inflation.Capital costs used in this report were provided by Black Stone and are based on authorizations for expenditure and actual costs from recentactivity. Capital costs are included as required for workovers, new development wells, and production equipment. Based on our understanding offuture development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital coststo be reasonable. Capital costs are not escalated for inflation. As requested, our estimates do not include any salvage value for the lease and wellequipment or the cost of abandoning the properties.For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or conditionof the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do notinclude any costs due to such possible liability.We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the Black Stone interest.Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections arebased on Black Stone receiving its net revenue interest share of estimated future gross production. Additionally, we have been informed by BlackStone that they are not aware of any firm transportation contracts to which Black Stone is a party that contain volume commitments which mightrepresent a liability to the company; no adjustments have been made to our estimates of future revenue to account for such contracts.The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oiland gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible;probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimatesof reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance.In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to,that the properties will be developed consistent with current development plans as provided to us by Black Stone, that the properties will beoperated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner torecover the reserves,and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefromand the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply anddemand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made whilepreparing this report.For the purposes of this report, we used technical and economic data including, but not limited to, well logs, well test data, production data,historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministicmethods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and GasReserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geosciencemethods, or a combination of methods, including performance analysis and analogy, 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 areuncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informedprofessional judgment.The data used in our estimates were obtained from Black Stone, public data sources, and the nonconfidential files of Netherland, Sewell &Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to theproperties or independently confirmed the actual degree or type of interest owned. The technical person primarily responsible for preparing theestimates presented herein meets the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPEStandards. J. Carter Henson, Jr., a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering atNSAI since 1989 and has over 8 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, andpetrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.Sincerely,NETHERLAND, SEWELL & ASSOCIATES, INC.Texas Registered Engineering Firm F-2699/s/ C.H. (Scott) Rees IIIBy: C.H. (Scott) Rees III, P.E.Chairman and Chief Executive Officer/s/ J. Carter Henson, Jr.By: J. Carter Henson, Jr., P.E. 73964Senior Vice PresidentDate Signed: January 23, 2017JCH:LRGPlease be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document isintended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions statedin the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digitaldocument.DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Rule 4-10(a) and the 2007 Petroleum Resources Management System Approved by the Society of Petroleum EngineersThe 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) theFASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance and DisclosureInterpretations.(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options topurchase or lease 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 interestand thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support provedreserves, an "analogous reservoir" 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 viscositygreater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state itusually 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,when produced, 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 (fromthe 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 minorcompared to 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 notinvolving a 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 at the time of theestimate. 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 to be recoveredfrom (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions orpipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wellswhich will require additional completion work or future recompletion prior to start of production. In all cases, production can be initiated or restored with relatively lowexpenditure 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 storingthe oil and gas. More specifically, development costs, including depreciation andDefinitions - Page 1 of 7DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Rule 4-10(a) and the 2007 Petroleum Resources Management System Approved by the Society of Petroleum Engineersapplicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:(i)Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specificdevelopment drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extentnecessary in developing the 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,and production 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.As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of agroup of several 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 thatexceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined atthe terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulativeproduction as of that date.(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered tohave prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells.Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and afteracquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment andfacilities 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 andother expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to asgeological 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 titledefense, and the maintenance 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 ofoil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or astratigraphic test well as 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.(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structuralfeature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening imperviousstrata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated asa single or commonDefinitions - Page 2 of 7DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Rule 4-10(a) and the 2007 Petroleum Resources Management System Approved by the Society of Petroleum Engineersoperational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features asopposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.(16) Oil and gas producing activities.(i)Oil and gas producing activities include:(A)The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and originallocations;(B)The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas fromsuch properties;(C)The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including theacquisition, 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 nonrenewablenatural resources 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 outletvalve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminalpoint for the production 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 amarine terminal; 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 apurchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, amarine terminal, or a facility 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 aresaleable in the state 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 havethe legal right 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 canbe extracted; 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 provedplus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the totalquantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.(ii)Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations ofavailable data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to defineclearly the area and vertical limits of commercial production from the reservoir by a defined project.Definitions - Page 3 of 7DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Rule 4-10(a) and the 2007 Petroleum Resources Management System Approved by the Society of Petroleum Engineers(iii)Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than therecovery quantities assumed for probable reserves.(iv)The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technicaland commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results insuccessful similar projects.(v)Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within thesame accumulation that may be separated from proved areas by faults with displacement less than formation thickness or othergeological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are incommunication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower thanthe proved area if these areas are in communication 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 thepotential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir abovethe HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir thatdo not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties andpressure gradient interpretations.(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which,together with proved 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 estimatedproved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantitiesrecovered will equal or exceed 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 availabledata are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certaintycriterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communicationwith the proved reservoir.(iii)Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of thehydrocarbons in place than assumed for proved reserves.(iv)See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that couldreasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomesand their associated probabilities of occurrence.(20) Production costs.(i)Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs ofsupport equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. Theybecome part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:(A)Costs of labor to operate the wells and related equipment and facilities.(B)Repairs and maintenance.(C)Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.(D)Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.(E)Severance taxes.(ii)Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining,and marketing activities. To the extent that the support equipmentDefinitions - Page 4 of 7DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Rule 4-10(a) and the 2007 Petroleum Resources Management System Approved by the Society of Petroleum Engineersand facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration,development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, anddevelopment costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costsidentified 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 andengineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs,and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right tooperate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are usedfor the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it willcommence 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 containeconomically producible 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 awell penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonablecertainty.(iii)Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associatedgas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, orperformance data and reliable 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, fluidinjection) 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, theoperation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes thereasonable certainty 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 priceshall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as anunweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined bycontractual arrangements, excluding escalations based upon future conditions.(23) Proved properties. Properties with proved reserves.(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will berecovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceedthe estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increasedavailability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery(EUR) with time, reasonably certain EUR 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 fieldtested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or inan analogous formation.Definitions - Page 5 of 7DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Rule 4-10(a) and the 2007 Petroleum Resources Management System Approved by the Society of Petroleum Engineers(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as ofa given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonableexpectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas orrelated substances to market, and all permits 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 thosereservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from aknown accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas maycontain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of theyear:a. Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)b. Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation ofthe properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordancewith paragraphs 932-235-50-3 through 50-11B:a. Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities ofthose reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing theproved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated developmentexpenditures are significant, they shall be presented separately from estimated production costs.c. Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of futuretax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. Thefuture income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.d. Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from futurecash inflows.e. Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to provedoil and gas reserves.f. Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.(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 beestimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscoveredaccumulations.(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells includegas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situcombustion.(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 completedDefinitions - Page 6 of 7DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Rule 4-10(a) and the 2007 Petroleum Resources Management System Approved by the Society of Petroleum Engineersfor hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbonexploration. Stratigraphic tests are classified as "exploratory type" if not drilled 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 fromnew wells on undrilled 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 ofproduction when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility atgreater distances.(ii)Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they arescheduled to be drilled within five years, unless the specific circumstances, justify a longer time.From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations —by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of thefacts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five yearsinclude, but are not limited to, the following:Ÿ The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wellsnecessary to maintain the lease generally would not constitute significant development activities);Ÿ The company's historical record at completing development of comparable long-term projects;Ÿ The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;Ÿ The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development planseveral times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); andŸ The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions ondevelopment on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties withhigher priority).(iii)Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injectionor other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the samereservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technologyestablishing reasonable certainty.(32) Unproved properties. Properties with no proved reserves.Definitions - Page 7 of 7

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