Black Stone Minerals
Annual Report 2015

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UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549 FORM 10-K (Mark One)xxANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the fiscal year ended December 31, 2015ORooTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934For the transition period _______________ to _______________Commission file number 001-37362 Black Stone Minerals, L.P.(Exact Name of Registrant As Specified in Its Charter) Delaware 47-1846692(State or Other Jurisdiction 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 o No xIndicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o 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 oIndicate 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 oIndicate 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. oIndicate 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 ¨ Accelerated Filer ¨ Non-Accelerated Filer x(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 o No xThe aggregate market value of the common units held by non-affiliates was $1,240,495,410 on June 30, 2015, the last business day of the registrant’s most recently completed secondfiscal quarter, based on a closing price of $17.22 per unit as reported by the New York Stock Exchange on such date. As of March 4, 2016, 96,965,879 common units, 95,002,347subordinated units, and 77,216 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 May 26, 2016. BLACK STONE MINERALS, L.P.TABLE OF CONTENTS PAGEPART IITEMS 1 AND 2.BUSINESS AND PROPERTIES 2ITEM 1A.RISK FACTORS 26ITEM 1B.UNRESOLVED STAFF COMMENTS 44ITEM 3.LEGAL PROCEEDINGS 44ITEM 4.MINE SAFETY DISCLOSURES 44PART IIITEM 5.MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OFEQUITY SECURITIES 45ITEM 6.SELECTED FINANCIAL DATA 50ITEM 7.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 51ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 64ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 65ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 65ITEM 9A.CONTROLS AND PROCEDURES 65ITEM 9B.OTHER INFORMATION 66PART IIIITEM 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 67ITEM 11.EXECUTIVE COMPENSATION 67ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDERMATTERS 67ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 67ITEM 14.PRINCIPAL ACCOUNTANT FEES AND SERVICES 67PART IVITEM 15.EXHIBITS AND FINANCIAL STATEMENT SCHEDULES 68 ii GLOSSARY OF TERMSThe following list includes a description of the meanings of some of the oil and gas industry terms used in this Annual Report on Form 10-K (“AnnualReport”).Basin. A large depression on the earth’s surface in which sediments accumulate.Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume.Bbl/d. Bbl per day.Bcf. One billion cubic feet of natural gas.Boe. Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil. This “Btu-equivalent” conversionmetric is based on an approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas.Boe/d. Boe per day.British Thermal Unit (Btu). The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.Completion. The process of treating a drilling well followed by the installation of permanent equipment for the production of natural gas or oil, or inthe case of a dry hole, the reporting of abandonment to the appropriate agency.Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is inthe liquid phase at surface pressure and temperature.Crude oil. Liquid hydrocarbons retrieved from geological structures underground to be refined into fuel sources.Delaware Act. Delaware Revised Uniform Limited Partnership Act.Delay rental. Payment made to the lessor under a non-producing oil and natural gas lease at the end of each year to defer a drilling obligation andcontinue the lease for another year during its primary term.Deterministic method. The method of estimating reserves or resources under which a single value for each parameter (from the geoscience,engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.Development costs. Capital costs incurred in the acquisition, exploitation, and exploration of proved oil and natural gas reserves.Development well. A well drilled within the proved area of an oil and natural gas reservoir to the depth of a stratigraphic horizon known to beproductive.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 locationof oil or natural gas.Dry hole or dry well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of suchproduction exceed production expenses and taxes.Economically producible. A resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.Electrical log. An analysis that provides information on porosity, hydraulic conductivity, and fluid content of formations drilled in fluid-filledboreholes.iii Exploitation. A drilling or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally hasa lower risk than that associated with exploration projects.Exploratory 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 previouslyfound to be 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 structuralfeature and/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 anglewithin a 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 ofthe current operating expenses of a working interest. Such costs include labor, supplies, repairs, maintenance, allocated overhead charges, workover costs,insurance, and other expenses incidental to production, but exclude lease acquisition or drilling or completion costs.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 isfound in underground 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 theright, which is typically perpetual, to receive a fixed cost-free percentage of production or revenue from production, without an associated right to lease.iv NYMEX. New York Mercantile Exchange.Oil. Crude oil and condensate.Oil and natural gas properties. Tracts of land consisting of properties to be developed for oil and natural gas resource extraction.Operator. The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.Overriding royalty interest (ORRI). A fractional, undivided interest or right of participation in the oil or natural gas, or in the proceeds from the sale ofthe oil or gas, produced from a specified tract or tracts, which are limited in duration to the terms of an existing lease and which are not subject to any portionof the expense of development, operation, or maintenance.PDP. Proved developed producing, used to characterize reserves.Play. A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such assource rock, reservoir structure, timing, trapping mechanism, and hydrocarbon type.Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape 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 adjacentleased tracts, which may be covered by multiple leases with multiple lessors, in order to maximize drilling efficiency or to comply with state mandated wellspacing requirements. Pooling dilutes our royalty in a given well or unit, but it also increases both the acreage footprint and the number of wells in which wehave an economic interest. To estimate our total potential drilling locations in a given play, we include third-party acreage that is pooled with our acreage.Production Costs. The production or operational costs incurred while extracting and producing, storing, and transporting oil and/or natural gas.Typical of these costs are wages for workers, facilities lease costs, equipment maintenance, logistical support, applicable taxes, and insurance.PUD. Proved undeveloped, used to characterize reserves.Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of theproduction exceed production expenses and taxes.Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.Proved developed producing reserves. Reserves expected to be recovered from existing completion intervals in existing wells.Proved reserves. The estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to 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 arelatively major expenditure is required for recompletion.Reliable technology. A grouping of one or more technologies (including computation methods) that have been field tested and have beendemonstrated to provide 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 agiven date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation thatthere will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to themarket, and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentiallysealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearlyseparatedv from a known 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). Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined byimpermeable rock or water barriers and is separate from other reservoirs.Resource play. A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic, and temporal properties,such as source rock, reservoir structure, timing, trapping mechanism, and hydrocarbon type.Royalty interest. An interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs ofdevelopment.Seismic data. Seismic data is used by scientists to interpret the composition, fluid content, extent, and geometry of rocks in the subsurface. Seismicdata is acquired 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 caninclude relatively large amounts of organic material compared with other rock types and thus has the potential to become rich hydrocarbon source rock. Itsfine grain size and lack of permeability can allow shale to form a good cap rock for hydrocarbon traps.Spacing. The distance between wells producing from the same reservoir 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 inaccordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, production andincome tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Because we are a limited partnership, we are generally notsubject to federal or state income taxes and thus make no provision for federal or state income taxes in the calculation of our standardized measure.Standardized measure does not give effect to derivative transactions.Tight formation. A formation with low permeability that produces natural gas with low flow rates for long periods of time.Trend. A region of oil and/or natural gas production, the geographic limits of which have not been fully defined, having geological characteristicsthat have been 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 commercialquantities of oil and natural gas regardless of whether such acreage contains proved reserves.Working interest. An operating interest that gives the owner the right to drill, produce, and conduct operating activities on the property, and receive ashare of production and requires the owner to pay a share of the costs of drilling and production operations.Workover. Operations on a producing well to restore or increase production.WTI. West Texas Intermediate oil, which is a light, sweet crude oil, characterized by an American Petroleum Institute (“API”) gravity between 39 and41 and a sulfur content of approximately 0.4 weight percent that is used as a benchmark for the other crude oils. vi CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTSCertain statements and information in this Annual Report may constitute “forward-looking statements.” The words “believe,” “expect,” “anticipate,”“plan,” “intend,” “foresee,” “should,” “would,” “could,” or other similar expressions are intended to identify forward-looking statements, which are generallynot historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and theirpotential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance thatfuture developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results arebased on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involvesignificant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from ourhistorical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in theforward-looking statements include, but are not limited to, those summarized below: ·our ability to execute our business strategies; ·the volatility of realized oil and natural gas prices; ·the level of production on our properties; ·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. 1 PART IUnless the context clearly indicates otherwise, references in this Annual Report on Form 10-K to “BSMC,” “Black Stone Minerals, L.P. Predecessor,”or “our predecessor,” refer to Black Stone Minerals Company, L.P. and its subsidiaries for time periods prior to the initial public offering of Black StoneMinerals, L.P. on May 6, 2015 (the “IPO”), and references to “BSM,” “Black Stone,” “we,” “our,” “us,” “the Partnership,” or like terms refer to BlackStone Minerals, L.P. and its subsidiaries for time periods subsequent to the IPO. ITEMS 1 AND 2. BUSINESS AND PROPERTIESGeneralWe are one of the largest owners of oil and natural gas mineral interests in the United States. Our principal business is actively managing our existingportfolio of mineral and royalty assets to maximize its value and expanding our asset base through acquisitions of additional mineral and royalty interests.We maximize value through marketing our mineral assets for lease, creatively structuring terms on those leases to encourage and accelerate drilling activity,and selectively participating alongside our lessees on a working-interest basis in low-risk development-drilling opportunities on our mineral acreage. Ourprimary business objective is to grow our reserves, production, and cash generated from operations over the long term, while increasing, to the extentpracticable, the distribution to our unitholders over time.We own mineral interests in approximately 14.6 million acres, with an average 47.8% ownership interest in that acreage. We also ownnonparticipating royalty interests in 1.3 million acres and overriding royalty interests in 1.4 million acres. These non-cost-bearing interests, which we refer tocollectively as our “mineral and royalty interests,” include ownership in over 45,000 producing wells. Our mineral and royalty interests are located in 41states and in 61 onshore basins in the continental United States. Many of these interests are in active resource plays, including the Bakken/Three Forks, EagleFord Shale, Wolfcamp, Haynesville/Bossier, and Fayetteville Shale plays, as well as emerging plays such as the Lower Wilcox and Canyon Lime plays. Thecombination of the breadth of our asset base and the long-lived, non-cost-bearing nature of our mineral and royalty interests exposes us to potentialadditional production and reserves from new and existing plays without investing additional capital. We are a publicly traded Delaware limited partnership formed on September 16, 2014. On May 1, 2015, our common units began trading on the NewYork Stock Exchange under the symbol “BSM.” On May 6, 2015, we completed our initial public offering of 22,500,000 common units representing limitedpartner interests at a price to the public of $19.00 per common unit.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.Recent DevelopmentsCommon Unit Repurchase ProgramOn March 4, 2016, the board of directors of our general partner authorized the repurchase of up to $50.0 million in common units over the next sixmonths. The repurchase program authorizes us to make repurchases on a discretionary basis as determined by management, subject to market conditions,applicable legal requirements, available liquidity, and other appropriate factors. All or a portion of any repurchases may be made under a Rule 10b5-1 plan,which would permit common units to be repurchased when we might otherwise be precluded from doing so under insider trading laws. The repurchaseprogram does not obligate us to acquire any particular amount of common units and may be modified or suspended at any time and could be terminated priorto completion. We will periodically report the number of common units repurchased. The repurchase program will be funded from our cash on hand oravailable revolving credit facility. Any repurchased common units will be cancelled.Cash Tender OfferOn November 6, 2015, we commenced a tender offer to purchase up to 100% of the 117,963 then outstanding preferred units from our preferredunitholders at the units’ par value of $1,000.00 per preferred unit, plus unpaid accrued yield. The tender offer expired on December 10, 2015. We purchasedand cancelled 40,747 preferred units, representing 34.5% of our then outstanding preferred units. The tendered units were purchased for $1,019.45 perpreferred unit for a total cost of approximately $41.5 million, excluding fees and expenses relating to the tender offer.2 AcquisitionsWe closed five separate transactions to acquire unproved oil and natural gas properties in the Permian Basin during 2015 for a total of $51.7 million.We acquired acreage in the Eagle Ford Shale play through two transactions totaling $9.7 million during 2015, and we also acquired an overriding royaltyinterest in the Utica Shale and Marcellus plays for $1.8 million.Our AssetsAs of December 31, 2015, our total estimated proved oil and natural gas reserves were 49,788 MBoe based on a reserve report prepared by NetherlandSewell and Associates (“NSAI”), an independent third-party petroleum engineering firm. Of the reserves as of December 31, 2015, approximately 89.6% wereproved developed reserves (approximately 88.1% proved developed producing and 1.5% proved developed non-producing) and approximately 10.4% wereproved undeveloped reserves. At December 31, 2015, our estimated proved reserves were 31.8% oil and 68.2% natural gas.The locations of our oil and natural gas properties are presented on the following map. Additional information related to these properties follows thismap. Mineral and Royalty InterestsMineral interests are real-property interests that are typically perpetual and grant ownership of the oil and natural gas under a tract of land and 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 exploration3 and development rights to another party. Mineral interests generate the substantial majority of our revenue and are also the assets that we have the mostinfluence 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, whichis typically perpetual, to receive a fixed, cost-free percentage of production or revenue from production, without an associated right to lease orreceive lease bonus; and ·overriding royalty interests (“ORRIs”), which are royalty interests that burden working interests and represent the right to receive a fixed, cost-free percentage of production or revenue from production from a lease. ORRIs remain in effect until the associated leases expire.Working-Interest Participation ProgramWe own working interests related to our mineral interests in various plays across our asset base. Many of these working interests were acquired throughworking-interest participation rights, which we often include in the terms of our leases. This participation right complements our core mineral-and-royalty-interest business because it allows us to realize additional value from our minerals. Under the terms of the relevant leases, we are typically granted a unit-by-unit or a well-by-well option to participate on a non-operated, working-interest basis in drilling opportunities on our mineral acreage. This right to participatein a unit or well is exercisable at our sole discretion. We generally only exercise this option when the results from prior drilling and production activitieshave substantially reduced the economic risk associated with development drilling and where we believe the probability of achieving attractive economicreturns is high. A small portion of our working interests, unrelated to our mineral and royalty assets, were acquired because of the attractive working-interestinvestment opportunities on those properties. The majority of these assets are focused in the Anadarko Basin, and to a lesser extent, in the Permian andPowder River Basins.We collectively refer to these working interests as our “working-interest participation program.” When we participate in non-operated working-interestopportunities, we are required to pay our portion of the costs associated with drilling and operating these wells. Our 2016 drilling capital expenditure budgetassociated with our working-interest participation program is approximately $60.0 million. Approximately 95% of our 2016 drilling capital budget will bespent in the Haynesville/Bossier and the Bakken/Three Forks plays, with the remainder spent in various plays including the Wolfcamp and Wilcox plays. Asof December 31, 2015, we owned non-operated working interests in over 10,000 gross (269 net) wells.Working interest production represented 29.5% of our total production volumes during the year ended December 31, 2015.Our PropertiesMaterial Basins and Producing RegionsThe following table summarizes our exposure to the U.S. basins and regions we consider most material to our current and future business. Acreage as of December 31, 20151 Average Daily Mineral and Royalty Interests Working Interests Production (Boe/d) USGS Petroleum Province2 MineralInterests NPRIs ORRIs Gross Net For the Year EndedDecember 31, 2015 Louisiana-Mississippi Salt Basins 5,274,784 111,707 17,660 54,346 6,917 5,576 Western Gulf (onshore) 1,553,239 180,185 79,895 124,656 18,112 6,527 Williston Basin 1,112,646 62,133 30,765 54,666 7,740 4,037 Palo Duro Basin 1,010,414 22,791 1,120 — — 23 Permian Basin 780,361 577,172 102,967 8,113 4,734 903 Anadarko Basin 534,332 10,616 178,394 31,313 21,294 2,404 Appalachian Basin 486,964 416 12,492 — — 920 East Texas Basin 406,111 41,975 30,294 110,507 30,504 3,687 Arkoma Basin 331,777 5,170 35,949 8,950 2,409 1,849 Bend Arch-Fort Worth Basin 138,933 52,368 40,663 53,606 11,022 660 Southwestern Wyoming 25,450 560 70,607 15,336 2,477 530 Other 2,935,091 188,446 789,502 39,262 9,300 1,551 Total 14,590,102 1,253,539 1,390,308 500,755 114,509 28,667 4 1We 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 inthat tract. Consequently, some of the acreage shown for one type of interest above may also be included in the acreage shown for another type ofinterest. Because of our working-interest participation program, overlap between working-interest acreage and mineral-and-royalty-interest acreage issignificant, while overlap between the different types of mineral and royalty interests is not. Working-interest acreage excludes acreage that is notquantifiable due to incomplete seller records. 2The basins and regions shown in the table are consistent with U.S. Geological Survey (“USGS”) delineations of petroleum provinces of onshore andstate offshore areas in the continental United States. We refer to these petroleum provinces as “basins” or “regions.”The following is an overview of the U.S. basins and regions we consider most material to our current and future business. ·Louisiana-Mississippi Salt Basins. The Louisiana-Mississippi Salt Basins region ranges from northern Louisiana and southern Arkansasthrough south central and southern Mississippi, southern Alabama, and the Florida Panhandle. The Haynesville/Bossier plays, which have beenextensively delineated through drilling, are the most prospective 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, wherewe own significant mineral and royalty interests and working interests. There are a number of additional active conventional andunconventional plays in the basins 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 active conventional and unconventional plays to which we have exposure to in the region,including the Austin Chalk, Buda, Eaglebine (or Maness) Shale, Frio, Glenrose, Olmos, Woodbine, Vicksburg, Wilcox, and Yegua plays. ·Williston Basin. The Williston Basin stretches through all of North Dakota, the northwest part of South Dakota, and eastern Montana andincludes plays such as the Bakken/Three Forks plays, where we have significant exposure through our mineral and royalty interests as well asthrough our working interests. We are also exposed to other well-known plays in the basin, including the Duperow, Mission Canyon, Madison,Ratcliff, Red River, and Spearfish plays. ·Palo Duro Basin. The Palo Duro Basin covers much of the Texas Panhandle but also occupies a small portion of the Oklahoma Panhandle 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 active conventional andunconventional plays in the Palo 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 fordrilling in the United States. It includes three geologic provinces: the Midland Basin to the east, the Delaware Basin to the west, and theCentral Basin in between. Our acreage underlies prospective areas for the Wolfcamp play in the Midland and Delaware Basins, the Spraberryformation in the Midland Basin, and the Bone Springs formation in the Delaware Basin, which are among the plays most actively targeted bydrillers within the basin. In addition to these plays, we own mineral and royalty interests that are prospective for a number of other activeconventional and unconventional plays in the Permian Basin, including the Atoka, Clearfork, Ellenberger, San Andres, Strawn, and WichitaAlbany plays. ·Anadarko Basin. The Anadarko Basin encompasses the Texas Panhandle, southeastern Colorado, southwestern Kansas, and western Oklahoma.We own mineral and royalty interests as well as working interests in prospective areas for most of the prolific plays in this basin, including theGranite Wash, Atoka, Cleveland, and Woodford Shale plays. Other active plays in which we hold interests in prospective acreage include theCottage Grove, Hogshooter, Marmaton, Springer, and Tonkawa plays. ·Appalachian Basin. The Appalachian Basin covers most of Pennsylvania, eastern Ohio, West Virginia, western Maryland, eastern Kentucky,central Tennessee, western Virginia, northwestern Georgia, and northern Alabama. The basin’s most active plays in which we have acreage arethe Marcellus Shale and Utica plays, which cover most of western Pennsylvania, northern West Virginia, and eastern Ohio. In addition to theMarcellus Shale, there are a number of other active conventional and unconventional plays to which we have material exposure in theAppalachian Basin, including the Berea, Big Injun, Devonian, Huron, Rhinestreet, and Utica plays.5 ·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 Shelby Trougharea of the Haynesville/Bossier plays located in San Augustine and Nacogdoches Counties, which is one of the most active areas being drilledtoday for that play in the East Texas Basin. There are other active plays to which we have significant exposure, including the Bossier Sand,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 thebasin’s most significant unconventional natural gas plays. We own material mineral and royalty interests within the prospective area of theFayetteville Shale. In addition, we have exposure to a number of other active conventional and unconventional plays in the basin, includingthe 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 itsmost active unconventional play. Through our mineral and royalty interests in this basin, we have significant exposure to the Barnett Shale aswell as a number of other active conventional and unconventional plays in the basin, including the Bend Conglomerate, Caddo, Marble Falls,and Mississippian Lime plays. ·Southwestern Wyoming. The Southwestern Wyoming region covers most of southern and western Wyoming. The Pinedale Anticline is one ofthe region’s largest producing fields and mainly produces from the Lance formation. We have a meaningful position in the Pinedale Anticline,and we have interests prospective for other active plays as well, including the Mesaverde, Niobrara, and Wasatch plays.Interests by USGS Petroleum ProvinceThe following tables present information about our mineral-and-royalty-interest and non-operated working-interest acreage, production, and wellcount by basin. We may own more than one type of interest in the same tract of land. For example, where we have acquired working interests through ourworking-interest participation program in a given tract, our working-interest acreage in that tract will relate to the same acres as our mineral-interest acreagein that tract. Consequently, some of the acreage shown for one type of interest below may also be included in the acreage shown for another type of interest.Because of our working-interest participation program, overlap between working-interest acreage and mineral-and-royalty-interest acreage is significant,while overlap between the different types of mineral and royalty interests is not significant.6 Mineral InterestsThe following table sets forth information about our mineral interests: Average Daily Production (Boe/d) As of December 31, 2015 For the Year Ended December 31, USGS Petroleum Province1 Acres AverageOwnershipInterest2 AverageOwnershipLeased3 2015 2014 2013 Louisiana-Mississippi Salt Basins 5,274,784 54.4% 7.2% 3,384 4,061 5,455 Western Gulf (onshore) 1,553,239 55.2% 39.8% 5,021 4,099 3,443 Williston Basin 1,112,646 16.8% 23.8% 2,430 1,989 1,646 Palo Duro Basin 1,010,414 46.7% 6.4% 23 16 15 Permian Basin 780,361 16.4% 54.9% 585 566 499 Eastern Great Basin 599,463 96.8% 0.1% — — — Black Warrior Basin 592,116 54.7% 2.3% 39 41 41 Anadarko Basin 534,332 33.0% 56.9% 959 790 815 Appalachian Basin 486,964 39.5% 27.6% 80 89 67 East Texas Basin 406,111 56.1% 29.3% 884 793 994 Arkoma Basin 331,777 54.4% 26.1% 1,458 1,646 1,642 Western Great Basin 308,258 88.9% 0.0% — — — Piedmont 179,724 67.7% 0.0% — — — North-Central Montana 151,113 14.7% 16.3% 4 7 4 Bend Arch-Fort Worth Basin 138,933 20.8% 32.9% 392 252 325 Atlantic Coastal Plain 117,326 12.2% 0.0% — — — Cherokee Platform 106,475 13.8% 29.2% 41 46 34 Illinois Basin 79,221 53.6% 6.1% 2 1 1 Powder River Basin 66,415 11.1% 15.1% 56 3 2 Uinta-Piceance Basin 63,408 3.2% 31.4% 6 6 5 Other 697,022 35.1% 12.3% 295 311 332 Total 14,590,102 47.8% 18.1% 15,659 14,716 15,320 1The basins and regions shown in the table are consistent with USGS petroleum-province delineations.2Ownership interest is equal to the percentage that our undivided ownership interest in a tract bears to the entire tract. The per-basin average ownershipinterest shown reflects the weighted average of our ownership interests in all tracts in the basin. 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 mineraland royalty interests.3The average percent leased reflects the weighted average of our leased acres relative to our total acreage on a tract-by-tract basis in the basin.7 NPRIsThe following table sets forth information about our NPRIs: Average Daily Production (Boe/d) As of December 31, 2015 For the Year Ended December 31, USGS Petroleum Province1 Acres AverageRoyaltyInterest2 AveragePercentLeased3 2015 2014 2013 Permian Basin 577,172 3.2% 26.5% 31 11 3 Western Gulf (onshore) 180,185 5.2% 36.0% 10 14 3 North-Central Montana 127,307 3.0% 8.2% — — — Louisiana-Mississippi Salt Basins 111,707 6.8% 24.6% — <1 <1 Williston Basin 62,133 2.6% 33.0% 106 64 32 Bend Arch-Fort Worth Basin 52,368 4.3% 7.4% — 3 2 East Texas Basin 41,975 2.8% 79.2% 381 2 2 Powder River Basin 32,424 6.3% 4.2% — — — Palo Duro Basin 22,791 3.8% 1.7% — — — Anadarko Basin 10,616 4.4% 92.6% 8 2 3 Cambridge Arch-Central Kansas Uplift 8,583 5.7% 83.1% — — — Montana Thrust Belt 6,474 3.2% 14.7% — — — Southwest Montana 6,307 5.3% 5.1% — — — Arkoma Basin 5,170 4.5% 71.6% 21 — — Cherokee Platform 2,634 4.6% 30.4% — — — Nemaha Uplift 2,334 1.6% 41.4% — — — Sedgwick Basin 1,530 3.1% 78.4% — — — Southwestern Wyoming 560 1.0% 0.0% — — — Denver Basin 480 9.1% 0.0% — — — Appalachian Basin 416 8.9% 6.0% — — — Other 373 2.0% 12.2% 185 151 148 Total 1,253,539 3.9% 27.1% 742 247 193 1The basins and regions shown in the table are consistent with USGS petroleum-province delineations.2Average royalty interest is equal to the weighted-average percentage of production or revenues (before operating costs) that we are entitled to on atract-by-tract basis in the basin.3The average percent leased reflects the weighted average of our leased acres relative to our total acreage on a tract-by-tract basis in the basin.8 ORRIsThe following table sets forth information about our ORRIs: Average Daily Production (Boe/d) As of December 31, 2015 For the Year Ended December 31, USGS Petroleum Province1 Acres AverageRoyaltyInterest2 2015 2014 2013 North-Central Montana 458,645 2.4% 35 36 42 Anadarko Basin 178,394 2.2% 232 253 258 Permian Basin 102,967 1.2% 72 60 69 Western Gulf (onshore) 79,895 1.9% 262 166 126 Powder River Basin 74,713 1.5% 98 50 52 Southwestern Wyoming 70,607 2.1% 529 530 631 Michigan Basin 56,178 1.0% 21 21 24 Uinta-Piceance Basin 55,684 1.6% 37 32 37 Bend Arch-Fort Worth Basin 40,663 4.5% 160 166 208 Arkoma Basin 35,949 2.3% 29 23 24 Williston Basin 30,765 2.1% 76 54 53 East Texas Basin 30,294 3.5% 81 100 110 San Juan Basin 28,187 1.1% 3 3 4 Paradox Basin 23,374 0.6% 2 2 3 Northern Alaska 20,039 1.7% 32 27 18 Louisiana-Mississippi Salt Basins 17,660 3.2% 1,185 903 819 Wind River Basin 15,841 1.9% 33 31 33 Denver Basin 15,080 2.8% 83 91 107 Wyoming Thrust Belt 8,149 1.1% 5 5 5 Cambridge Arch-Central Kansas Uplift 5,762 3.8% 5 4 4 Other 41,462 2.1% 906 879 905 Total 1,390,308 2.1% 3,886 3,436 3,532 1The basins and regions shown in the table are consistent with USGS petroleum-province delineations.2Average royalty interest is equal to the weighted-average percentage of production or revenues (before operating costs) that we are entitled to on atract-by-tract basis in the basin.9 Working InterestsThe following table sets forth information about our non-operated working interests: Average Daily Production (Boe/d) As of December 31, 2015 For the Year Ended December 31, USGS Petroleum Province1 Gross Acres2 Net Acres2 2015 2014 2013 Western Gulf (onshore) 124,656 18,112 1,234 786 831 East Texas Basin 110,507 30,504 2,341 1,564 1,427 Williston Basin 54,666 7,740 1,425 1,386 844 Louisiana-Mississippi Salt Basins 54,346 6,917 1,007 2,077 3,105 Bend Arch-Fort Worth Basin 53,606 11,022 108 129 159 Anadarko Basin 31,313 21,294 1,205 1,402 1,567 Southwestern Wyoming 15,336 2,477 1 6 8 Michigan Basin 13,287 1,330 6 6 6 Powder River Basin 11,507 2,535 169 121 61 Arkoma Basin 8,950 2,409 341 360 408 Permian Basin 8,113 4,734 214 204 160 Denver Basin 4,286 1,037 5 4 4 San Juan Basin 3,442 1,575 11 9 10 North-Central Montana 2,080 605 1 1 1 Wind River Basin 2,000 935 — — — Paradox Basin 1,125 522 5 5 5 Southern Oklahoma 390 92 174 141 138 Cherokee Platform 328 137 5 9 14 Big Horn Basin 320 320 — — — Wyoming Thrust Belt 176 176 — — — Other 321 36 128 109 129 Total 500,755 114,509 8,380 8,319 8,877 1The basins and regions shown in the table are consistent with USGS petroleum-province delineations.2Excludes acreage that is not quantifiable due to incomplete seller records.10 WellsThe following table sets forth information about our mineral-and-royalty-interest and working-interest wells as of December 31, 2015: Mineral and Royalty Interests Working Interests USGS Petroleum Province1 Gross Well Count2 USGS Petroleum Province1 Gross Well Count2 Permian Basin 19,671 Anadarko Basin 3,026 Anadarko Basin 3,599 Uinta-Piceance Basin 1,962 Williston Basin 2,643 Permian Basin 773 Louisiana-Mississippi Salt Basins 2,536 Arkoma Basin 709 Western Gulf (onshore) 2,504 Southern Oklahoma 692 East Texas Basin 2,303 Western Gulf (onshore) 593 Uinta-Piceance Basin 2,224 Williston Basin 542 Arkoma Basin 1,726 Louisiana-Mississippi Salt Basins 492 Bend Arch-Fort Worth Basin 1,212 East Texas Basin 448 Michigan Basin 1,043 Bend Arch-Fort Worth Basin 224 Southern Wyoming 700 Appalachian Basin 189 Cherokee Platform 660 Nemaha Uplift 174 Appalachian Basin 633 Michigan Basin 62 Southern Oklahoma 620 Powder River Basin 51 San Juan Basin 481 Cherokee Platform 15 San Joaquin Basin 455 North-Central Montana 10 North-Central Montana 440 Paradox Basin 8 Nemaha Uplift 419 Southwestern Wyoming 5 Powder River Basin 366 San Juan 5 Wyoming Thrust Belt 361 Black Warrior Basin 5 Other 1,716 Other 125 Total 46,312 Total 10,110 1The basins and regions shown in the table are consistent with USGS petroleum-province delineations.2We own both mineral and royalty interests and working interests in 4,498 of the wells shown in each column above.11 Material Resource PlaysThe following table presents information about our mineral-and-royalty-interest and working-interest acreage by the resource plays we consider mostmaterial to our current and future business and contribute 61.0% of our aggregate production for the year ended December 31, 2015. Acreage as of December 31, 20151 Mineral and Royalty Interests Working Interests Resource Play2 MineralInterests NPRIs ORRIs Gross Net Bakken Shale 304,908 36,421 12,730 50,091 7,104 Three Forks 292,960 33,602 12,050 50,292 6,731 Haynesville Shale 271,237 7,123 14,468 149,500 35,746 Marcellus Shale 248,786 — 9,962 — — Canyon Lime 219,438 — — — — Bossier Shale 207,593 2,096 8,441 122,121 31,958 Tuscaloosa Marine Shale 179,345 3,981 860 — — Wolfcamp-Midland 154,965 68,827 58,362 160 4 Granite Wash 100,883 4,042 87,516 4,840 1,254 Fayetteville Shale 70,446 — 11,673 — — Barnett Shale 62,178 4,004 37,472 13,417 7,284 Eagle Ford Shale 59,465 85,609 46,926 7,039 437 Wolfcamp-Delaware 32,815 11,033 1,040 642 160 1We 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 inthat tract. Consequently, some of the acreage shown for one type of interest above may also be included in the acreage shown for another type ofinterest. Because of our working-interest participation program, overlap between working-interest acreage and mineral-and-royalty-interest acreage issignificant, while overlap between the different types of mineral and royalty interests is not significant. Working-interest acreage excludes acreagethat is not quantifiable due to incomplete seller records.2The 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.12 Interests 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 above, we may own more than one type of interest in the same tract of land. Consequently, some ofthe acreage shown for one type of interest below may also be included in the acreage shown for another type of interest.Mineral InterestsThe following table sets forth information about our mineral interests: Average Daily Production (Boe/d) As of December 31, 2015 For the Year Ended December 31, Resource Play1 Acres AverageOwnershipInterest2 AverageOwnershipLeased3 2015 2014 2013 Bakken Shale 304,908 18.2% 73.5% 1,746 1,275 1,074 Three Forks 292,960 17.9% 74.7% 823 626 490 Haynesville Shale 271,237 68.5% 59.8% 2,728 3,152 4,139 Marcellus Shale 248,786 17.8% 44.0% 71 74 50 Canyon Lime 219,438 30.7% 18.3% 8 1 1 Bossier Shale 207,593 70.2% 67.3% 351 548 1,066 Tuscaloosa Marine Shale 179,345 63.0% 68.8% 46 6 <1 Wolfcamp-Midland 154,965 4.7% 97.5% 76 27 15 Granite Wash 100,883 15.1% 55.5% 194 241 276 Fayetteville Shale 70,446 56.7% 77.0% 1,349 1,529 1,508 Barnett Shale 62,178 15.6% 61.2% 239 228 299 Eagle Ford Shale 59,465 15.8% 85.3% 2,355 1,595 989 Wolfcamp-Delaware 32,815 20.3% 89.9% 148 132 72 1The plays above have been delineated based on information from the EIA, the USGS, or state agencies or according to areas of the most active industrydevelopment.2Ownership 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 ofour mineral interests is approximately 20%, which may be multiplied by our ownership interest to approximate the average royalty interest in ourmineral and royalty interests.3The average percent leased reflects the weighted average of our leased acres relative to our total acreage on a tract-by-tract basis in the play. 13 NPRIsThe following table sets forth information about our NPRIs: Average Daily Production (Boe/d) As of December 31, 2015 For the Year Ended December 31, Resource Play1 Acres AverageRoyaltyInterest2 AveragePercentLeased3 2015 2014 2013 Bakken Shale 36,421 1.4% 51.4% 56 37 18 Three Forks 33,602 1.2% 54.9% 50 27 13 Haynesville Shale 7,123 4.2% 97.1% 325 — — Marcellus Shale — 0.0% NA — — — Canyon Lime — 0.0% NA — — — Bossier Shale 2,096 2.7% 60.2% 53 — — Tuscaloosa Marine Shale 3,981 2.1% 48.2% — — — Wolfcamp-Midland 68,827 1.5% 62.9% 22 5 — Granite Wash 4,042 0.9% 100.0% 5 <1 — Fayetteville Shale — 0.0% NA — — — Barnett Shale 4,004 2.8% 86.3% — 2 2 Eagle Ford Shale 85,609 1.5% 27.8% 3 7 — Wolfcamp-Delaware 11,033 3.4% 59.8% 1 2 <1 1The plays above have been delineated based on information from the EIA, the USGS or state agencies or according to areas of the most active industrydevelopment.2Average royalty interest is equal to the weighted-average percentage of production or revenues (before operating costs) that we are entitled to on atract-by-tract basis for the given area.3The average percent leased reflects the weighted average of our leased acres relative to our total acreage on a tract-by-tract basis in the play. ORRIsThe following table sets forth information about our ORRIs: Average Daily Production (Boe/d) As of December 31, 2015 For the Year Ended December 31, Resource Play1 Acres AverageRoyaltyInterest2 2015 2014 2013 Bakken Shale 12,730 1.2% 41 27 20 Three Forks 12,050 1.2% 27 18 20 Haynesville Shale 14,468 4.4% 1,111 816 689 Marcellus Shale 9,962 2.8% 6 — — Canyon Lime — 0.0% — — — Bossier Shale 8,441 4.7% 57 60 89 Tuscaloosa Marine Shale 860 2.0% — <1 <1 Wolfcamp-Midland 58,362 0.4% 5 3 5 Granite Wash 87,516 1.2% 115 191 180 Fayetteville Shale 11,673 4.0% — — — Barnett Shale 37,472 4.7% 158 163 205 Eagle Ford Shale 46,926 2.1% 204 96 52 Wolfcamp-Delaware 1,040 0.6% — — — 1The plays above have been delineated based on information from the EIA, the USGS, or state agencies or according to areas of the most active industrydevelopment.2Average royalty interest is equal to the weighted-average percentage of production or revenues (before operating costs) that we are entitled to on atract-by-tract basis in this play. 14 Working InterestsThe following table sets forth information about our working interests. Average Daily Production (Boe/d) As of December 31, 2015 For the Year Ended December 31, Resource Play1 Gross Acres2 Net Acres2 2015 2014 2013 Bakken Shale 50,091 7,104 792 855 507 Three Forks 50,292 6,731 551 491 307 Haynesville Shale 149,500 35,746 2,909 3,136 3,937 Marcellus Shale — — — — — Canyon Lime — — — — — Bossier Shale 122,121 31,958 135 199 277 Tuscaloosa Marine Shale — — — — — Wolfcamp-Midland 160 4 — 1 1 Granite Wash 4,840 1,254 537 647 753 Fayetteville Shale — — — — — Barnett Shale 13,417 7,284 104 124 154 Eagle Ford Shale 7,039 437 11 — — Wolfcamp-Delaware 642 160 23 33 4 1The plays above have been delineated based on information from the EIA, the USGS, or state agencies or according to areas of the most active industrydevelopment.2Excludes 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, 2015.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, 2015 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 gas production,well test data, realized commodity prices, and operating and development costs. We also provided ownership interest information with respect to ourproperties. Brock Morris, our Senior Vice President, Engineering and Geology, is primarily responsible for overseeing the preparation of all of our reserveestimates. Mr. Morris is a petroleum engineer with approximately 30 years of reservoir-engineering and operations experience.15 The preparation of our historical proved reserve estimates were completed in accordance with our internal control procedures. Throughout the year,our technical team met with NSAI to review properties and discuss evaluation methods and assumptions used in the proved reserves estimates, in accordancewith our prescribed internal control procedures. Our internal controls over the reserves estimation process include verification of input data used in thereserves evaluation software as well as reviews by our internal engineering staff and management, which include the following: ·Comparison of historical operating expenses from the lease operating statements to the operating costs input in the reserves database; ·Review of working interests and net revenue interests in the reserves database against our well ownership system; ·Review of historical realized commodity prices and differentials from index prices compared to the differentials used in the reserves database; ·Review of capital costs assumptions to actual historical capital costs; ·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, 2015 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 has been field tested and has 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 analyses, 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. Recovery factors were determined utilizing reservoirsimulation or analogy with similar reservoirs where similar drilling and completion techniques have been employed.16 Summary of Estimated Proved ReservesThe following table presents our estimated proved oil and natural gas reserves: As ofDecember 31, 20151 (Unaudited) Estimated proved developed reserves2: Oil (MBbls) 15,497 Natural gas (MMcf) 174,555 Total (MBoe) 44,590 Estimated proved undeveloped reserves3: Oil (MBbls) 345 Natural gas (MMcf) 29,120 Total (MBoe) 5,198 Estimated proved reserves: Oil (MBbls) 15,842 Natural gas (MMcf) 203,675 Total (MBoe) 49,788 Percent proved developed 89.6% 1Estimates of reserves as of December 31, 2015 were prepared using oil and natural gas prices equal to the unweighted arithmetic average of the first-day-of-the-month market price for each month in the period January through December 2015. For oil volumes, the average WTI spot oil price of$50.28 per barrel is used for estimates of reserves for all the properties as of December 31, 2015. These average prices are adjusted for quality,transportation fees, and market differentials. For natural gas volumes, the average Henry Hub price of $2.59 per MMBTU is used for estimates ofreserves for all the properties as of December 31, 2015. These average prices are adjusted for energy content, transportation fees, and marketdifferentials. Natural gas prices are also adjusted to account for NGL revenue since there is not sufficient data to account for NGL volumes separatelyin the reserve estimates. These reserve estimates exclude NGL quantities. When taking these adjustments into account, the average adjusted gas priceweighted by production over the remaining lives of the properties is $2.45 per Mcf. Reserve estimates do not include any value for probable orpossible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in ourproperties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operatingexpenses, and quantities of recoverable oil and natural gas may vary substantially from these estimates.2Proved developed reserves of 84 MBoe as of December 31, 2015 were attributable to noncontrolling interests in our consolidated subsidiaries.3As of December 31, 2015, 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.”Additional information regarding our estimated proved reserves can be found in the notes to the consolidated financial statements of BSM includedelsewhere in this Annual Report and the estimated proved reserve reports as of December 31, 2015, which are included as exhibits to this Annual Report.17 Estimated Proved Undeveloped ReservesAs of December 31, 2015, our PUDs were composed of 345 MBbls of oil and 29,120 MMcf of natural gas, for a total of 5,198 MBoe. PUDs will beconverted from undeveloped to developed as the applicable wells begin production.The following tables summarize our changes in PUDs during the year ended December 31, 2015 (in MBoe): Proved Undeveloped Reserves (Unaudited) Balance as of December 31, 2014 595 Acquisitions of reserves — Extensions and discoveries 5,051 Revisions of previous estimates (101)Transfers to estimated proved developed (347)Balance as of December 31, 2015 5,198 There were no PUD reserves acquired during the year ended December 31, 2015. New PUD reserves totaling 5,051 MBoe were added during the yearended December 31, 2015 resulted primarily from drilling and capital expenditures in the Haynesville/Bossier, Bakken/Three Forks, and Wolfcamp plays.During the year ended December 31, 2015, we had downward revisions of previous PUD reserve estimates totaling 101 MBoe, which were made up of307 MMcf of natural gas reserve estimate revisions and 50 MBbl of oil reserve estimate revisions. Reductions of 45 MBoe are related to wells removed fromPUD status as a result of stale permits or updated operator information, and 56 MBoe are related to revised reserve estimates for PUD locations in theWolfcamp and Haynesville plays.Costs incurred relating to the development of locations that were classified as PUDs at December 31, 2014 were $1.3 million during the year endedDecember 31, 2015. Additionally, during the year ended December 31, 2015, we incurred $58.7 million drilling and completing other wells which were notclassified as PUDs as of December 31, 2014. Estimated future development costs during the year ended December 31, 2016 relating to the development ofPUD reserves at December 31, 2015 are projected to be approximately $30.6 million. All of our PUD drilling locations as of December 31, 2015 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 31,2015. As of December 31, 2015, approximately 10.4% of our total proved reserves were classified as PUDs.18 Oil and Natural Gas Production Prices and Production CostsProduction and Price HistoryFor the year ended December 31, 2015, 34.1% of our production and 58.5% 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 65.9% of our production and 41.5% 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, 2015 2014 2013 Production: Oil and condensate (MBbls)1 3,565 3,005 2,626 Natural gas (MMcf)1 41,389 42,273 45,400 Total (MBoe) 10,463 10,051 10,193 Average daily production (MBoe/d) 28.7 27.5 27.9 Realized Prices2: Oil and condensate (per Bbl) $45.87 $85.65 $96.25 Natural gas and natural gas liquids (per Mcf)1 $2.80 $4.91 $4.06 Unit Cost per Boe: Lease operating expense $2.06 $2.11 $2.07 Production costs and ad valorem taxes $3.42 $4.93 $4.20 1As a mineral-and-royalty interest owner, we are often provided insufficient and inconsistent data by our operators. As a result, we are unable to reliablydetermine the total volumes of NGLs associated with the production of natural gas on our acreage. As such, the realized prices account for all valueattributable to NGLs. The oil and condensate production volumes and natural gas production volumes do not include NGL volumes.2Excludes the effect of commodity derivative instruments.Productive WellsProductive wells consist of producing wells, wells capable of production, and exploratory, development, or extension wells that are not dry wells. Asof December 31, 2015, we owned mineral and royalty interests or working interests in 51,924 productive wells, which consisted of 31,967 oil wells and19,957 natural gas wells. As of December 31, 2015, we owned mineral and royalty interests in 46,312 productive wells, which consisted of 31,136 oil wellsand 15,176 natural gas wells, and working interests in 10,110 gross productive wells and 269 net productive wells, which consisted of 4,128 gross (55net) productive oil wells and 5,982 gross (214 net) productive natural gas wells. We own both mineral and royalty interests and working interests in 4,498 ofthese wells.19 AcreageMineral and Royalty InterestsThe following table sets forth information relating to our acreage for our mineral interests as of December 31, 2015: State DevelopedAcreage UndevelopedAcreage Total Acreage Texas 320,947 3,627,378 3,948,325 Mississippi 5,264 2,320,726 2,325,990 Alabama 2,792 2,025,227 2,028,019 Arkansas 4,887 1,187,605 1,192,492 North Dakota 17,800 850,142 867,942 Nevada — 792,328 792,328 Florida — 698,830 698,830 Louisiana 35,354 490,274 525,628 Oklahoma 120,860 350,317 471,177 Montana 20,765 408,373 429,138 Other 83,900 1,226,333 1,310,233 Total 612,569 13,977,533 14,590,102 The following table sets forth information relating to our acreage for our NPRIs as of December 31, 2015: State DevelopedAcreage UndevelopedAcreage Total Acreage Texas 199,596 659,780 859,376 Montana 11,684 167,606 179,290 Louisiana 11,148 43,708 54,856 Mississippi 10,045 33,509 43,554 North Dakota 18,540 18,616 37,156 Arkansas 3,974 15,207 19,181 Wyoming 1,360 16,840 18,200 New Mexico 14,129 1,120 15,249 Oklahoma 7,056 4,828 11,884 Kansas 8,722 2,663 11,385 Other 367 3,041 3,408 Total 286,621 966,918 1,253,539 The following table sets forth information relating to our acreage for our ORRIs as of December 31, 2015: State DevelopedAcreage UndevelopedAcreage Total Acreage Montana 295,969 165,676 461,645 Texas 228,964 47,058 276,022 Wyoming 134,234 35,100 169,334 Oklahoma 158,783 — 158,783 Utah 40,510 28,149 68,659 Michigan 55,259 919 56,178 New Mexico 46,631 1,847 48,478 Colorado 27,028 5,111 32,139 Kansas 18,274 921 19,195 Louisiana 15,264 375 15,639 Other 55,467 28,769 84,236 Total 1,076,383 313,925 1,390,308 20 Working InterestsThe following table sets forth information relating to our acreage for our non-operated working interests as of December 31, 2015: Developed Acreage Undeveloped Acreage Total Acreage State Gross Net Gross Net Gross Net Texas 181,541 45,882 131,157 29,017 312,698 74,899 Louisiana 31,570 4,292 18,879 1,909 50,449 6,201 North Dakota 42,060 6,154 8,804 990 50,864 7,144 Wyoming 22,342 4,207 6,678 1,916 29,020 6,123 Michigan 13,208 1,330 79 — 13,287 1,330 Oklahoma 11,452 3,066 90 7 11,542 3,073 Kansas 6,480 6,213 921 — 7,401 6,213 Colorado 7,088 2,598 — — 7,088 2,598 New Mexico 6,038 3,615 360 89 6,398 3,704 South Dakota 2,160 504 880 55 3,040 559 Other 7,013 2,258 1,955 407 8,968 2,665 Total 330,952 80,119 169,803 34,390 500,755 114,509 The following table lists the net undeveloped acres, the net acres expiring in the years ending December 31, 2016, 2017, and 2018, and, whereapplicable, the net acres expiring that are subject to extension options: 2016 Expirations 2017 Expirations 2018 Expirations Net 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. 34,390 5,506 195 1,745 75 437 — Drilling Results for Our Working InterestsThe following table sets forth information with respect to the number of wells completed on our properties during the periods indicated. 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, 2015 2014 2013 Gross development wells: Productive 74.0 222.0 210.0 Dry 1.0 1.0 — Total 75.0 223.0 210.0 Net development wells: Productive 2.9 7.3 7.6 Dry <0.1 — — Total 2.9 7.3 7.6 Gross exploratory wells: Productive — 1.0 1.0 Dry — 1.0 — Total — 2.0 1.0 Net exploratory wells: Productive — <0.1 0.1 Dry — — — Total — <0.1 0.1 As of December 31, 2015, we had 40 wells in the process of drilling, completing or dewatering, or shut in awaiting infrastructure that are not reflectedin the above table.21 Environmental MattersOil and natural gas exploration, development, and production operations are subject to stringent laws and regulations governing the discharge ofmaterials into the environment or otherwise relating to protection of the environment or occupational health and safety. These laws and regulations have thepotential to impact production on our properties, which could materially adversely affect our business and our prospects. Numerous federal, state, and localgovernmental agencies, such as the Environmental Protection Agency (“EPA”), issue regulations that often require compliance measures that carrysubstantial administrative, civil, and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may requirethe acquisition of a permit before drilling commences, restrict the types, quantities, and concentrations of various substances that can be released into theenvironment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying withinwilderness, wetlands, ecologically sensitive, and other protected areas, require action to prevent, or remediate pollution from current or historic operations,such as plugging abandoned wells or closing earthen pits, result in the suspension or revocation of necessary permits, licenses, and authorizations, requirethat additional pollution controls be installed, and impose substantial liabilities for pollution resulting from operations. The strict, joint, and several liabilitynature of such laws and regulations could impose liability upon our operators, or us as working-interest owners if the operator fails to perform, regardless offault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedlycaused by the release of hazardous substances, hydrocarbons, or other waste products into the environment. Changes in environmental laws and regulationsoccur frequently, and any changes that impact our operators and result in more stringent and costly pollution control or waste handling, storage, transport,disposal, or cleanup requirements could materially adversely affect our business and prospects. Below is a summary of environmental laws applicable to ouroperators.Waste HandlingThe Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes and regulations promulgated thereunder, affectoil and natural gas exploration, development, and production activities by imposing requirements regarding the generation, transportation, treatment,storage, disposal, and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions ofRCRA, 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. Administrative, civil, and criminal penalties can be imposed for failure to comply with waste handling requirements. Any changes in the lawsand regulations could have a material adverse effect on our operators’ capital expenditures and operating expenses, which in turn could affect productionfrom 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 analogous statelaws generally impose strict, joint, and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered tobe responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility(which can include working-interest owners), a former owner or operator of the facility at the time of contamination and those persons that disposed orarranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” maybe subject to strict and joint and several liability for the costs of removing or remediating previously disposed wastes (including wastes disposed of orreleased by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs ofcertain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and propertydamage allegedly caused by the hazardous substances released into the environment. Oil and natural gas exploration and production activities on ourproperties use materials that, if released, would be subject to CERCLA and comparable state statutes. Therefore, governmental agencies or third parties mayseek to hold our operators, or us as working-interest owners if the operator fails to perform, responsible under CERCLA and comparable state statutes for all orpart of the costs to clean-up sites at which these “hazardous substances” have been released.Water DischargesThe Federal Water Pollution Control Act of 1972, also known as the “Clean Water Act” (“CWA”), the Safe Drinking Water Act (“SDWA”), the OilPollution Act (“OPA”), and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorizeddischarge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. Thedischarge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The Clean WaterAct and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands,unless authorized by an appropriately issued permit. In September 2015, new EPA and U.S. Army Corps of Engineers rules defining the scope of the EPA’sand the Corps’ jurisdiction became effective. To the extent the rule expands the scope of the CWA’s jurisdiction, our operators could22 face 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.Noncompliance with the Clean Water Act or the OPA may result in substantial administrative, civil, and criminal penalties, as well as injunctiveobligations.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. More recently, in October 2015, the EPAlowered the National Ambient Air Quality Standard, (“NAAQS”) for ozone from 75 to 70 parts per billion for both the 8-hour primary and secondarystandards. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit the ability of our operators to obtainsuch permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. These laws and regulations mayincrease the costs of compliance for oil and natural gas producers and impact production on our properties, and federal and state regulatory agencies canimpose administrative, civil, and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associatedstate laws and regulations. Moreover, obtaining or renewing permits has the potential to delay the development of oil and natural gas projects.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 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, theEPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sourcesin the United States on an annual basis, which include operations on certain of our properties. More recently, in December 2015, the EPA finalized rulesadding new sources to the scope of the GHG monitoring and reporting rule. These new sources include gathering and boosting facilities as well ascompletions and workovers of hydraulically fractured wells. Also, in August 2015, the EPA announced proposed rules that would establish new air emissioncontrols for methane emissions from certain new, modified or reconstructed equipment and processes in the oil and natural gas source category, includingproduction, processing, transmission and storage activities, as part of an overall effort to reduce methane emissions by up to 45 percent in 2025. These rulescould result in increased compliance costs for our operators and require them to make expenditures to purchase pollution control equipment. Consequently,these and other regulations related to controlling GHG emissions could 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 and regionalefforts have emerged that are aimed at tracking or reducing GHG emissions by means of cap and trade programs. These programs typically require majorsources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. Although it is not possible at this time to predicthow legislation or new regulations that may be adopted to address GHG emissions would impact our business, any future laws and regulations imposingreporting obligations on, or limiting emissions of GHGs from, our operators’ equipment and operations could require them to incur costs to reduce emissionsof GHGs associated with their operations. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil and natural gasproduced from our properties. Restrictions on emissions of methane or carbon23 dioxide that may be imposed in various states, as well as state and local climate change initiatives, could adversely affect the oil and natural gas industry,and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business.Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climatechanges that have significant physical effects, such as increased frequency and severity of storms, floods, and other climatic events; if any of these effectswere to occur, they could have a material adverse effect on our properties and operations. Hydraulic FracturingOur operators engage in hydraulic fracturing. Hydraulic fracturing is a common practice that is used to stimulate production of hydrocarbons fromtight formations, including shales. The process involves the injection of water, sand, and chemicals under pressure into formations to fracture the surroundingrock and stimulate production. The federal SDWA regulates the underground injection of substances through the Underground Injection Control (“UIC”)program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic-fracturing process is typically regulated by stateoil and natural gas commissions. The U.S. Environmental Protection Agency (“EPA”), however, has recently taken the position that hydraulic fracturing withfluids containing diesel fuel is subject to regulation under the UIC program and issued guidance in February 2014 applicable to hydraulic fracturinginvolving the use of diesel fuel. The EPA has also issued final regulations under the federal Clean Air Act governing performance standards, includingstandards for the capture of air emissions released during hydraulic fracturing; proposed in April 2015 to prohibit the discharge of wastewater from hydraulicfracturing operations to publicly owned wastewater treatment plants; and issued in May 2014 an Advanced Notice of Proposed Rulemaking seekingcomment on its intent to develop regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicalsused in hydraulic fracturing. Also, the Bureau of Land Management (“BLM”) finalized rules in March 2015 that impose new or more stringent standards forperforming hydraulic fracturing on federal and American Indian lands including, for example, notice to and pre approval by BLM of the proposed hydraulicfracturing activities; development and pre approval by BLM of a plan for managing and containing flowback fluids and produced water recovered during thehydraulic fracturing process; implementation of measures designed to protect usable water from hydraulic fracturing activities; and public disclosure of thechemicals used in the hydraulic fracturing fluid. The U.S. District Court of Wyoming has temporarily stayed implementation of this rule. A final decision hasnot yet been issued.Several governmental reviews are underway that focus on environmental aspects of hydraulic fracturing activities. In June 2015, the EPA released itsdraft report on the potential impacts of hydraulic fracturing on drinking water resources, which concluded that hydraulic fracturing activities have not led towidespread, systemic impacts on drinking water sources in the United States, although there are above and below ground mechanisms by which hydraulicfracturing activities have the potential to impact drinking water sources. The draft report is expected to be finalized after a public comment period and aformal review by EPA’s Science Advisory Board. In addition, the White House Council on Environmental Quality is coordinating an administration widereview of hydraulic fracturing practices. These studies, depending on their results, could spur efforts to further regulate hydraulic fracturing.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 not24 possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing. Occupational 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 acquired, lease status, and royalties as well as encumbrances and other related burdens. Depending on themateriality of properties, we may obtain a title opinion if we believe additional title due diligence is necessary. As a result, title examinations have beenobtained on a significant portion of our properties. After an acquisition, we review the assignments from the seller for scrivener’s and other errors and executeand record corrective assignments as necessary.In addition to our initial title work, our operators conduct a thorough title examination prior to leasing and drilling a well. Should our operators’ titlework uncover any title defects, either we or our operators will perform curative work with respect to such defects. Our operators generally will not commencedrilling operations on a property until any material title defects on such property have been cured.We believe that the title to our assets is satisfactory in all material respects. Although title to these properties is subject to encumbrances in some cases,such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms andrestrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and otherburdens, easements, restrictions, and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions,easements, burdens, and encumbrances will materially detract from the value of these properties or from our interest in these properties or materially interferewith our use of these properties in the operation of our business. In addition, we believe that we have obtained sufficient rights-of-way grants and permitsfrom public authorities and private parties for us to operate our business in all material respects.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, 2015 2014 2013 Chesapeake Energy Corporation* 10.0% 10.9% *Accounted for less than 10% of total revenues for the period indicated.CompetitionThe oil and natural gas business is highly competitive in the exploration for and acquisition of reserves, the acquisition of minerals and oil and naturalgas leases, and personnel required to find and produce reserves. Many of these companies not only explore for and produce oil and natural gas, but also carryon midstream and refining operations and market petroleum and other products on a regional, national, or worldwide basis. Certain of our competitors maypossess financial or other resources substantially larger than we possess. Our ability to acquire additional minerals and properties and to discover reserves inthe future will be25 dependent upon our ability to identify and evaluate suitable acquisition prospects and to consummate transactions in a highly competitive environment. Oiland natural gas products compete with other sources of energy available to customers, primarily based on price. These alternate sources of energy includecoal, nuclear, solar and wind. Changes in the availability or price of oil and natural gas or other sources of energy, as well as business conditions,conservation, legislation, regulations, and the ability to convert to alternate fuels and other sources of energy may affect the demand for oil and natural gas. Seasonal Nature of 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, 2015, Black StoneManagement had 107 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 58,261 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 fund replacement capital expenditures, acquisitions, and participation in working interests. If over the long term we donot retain cash for replacement capital expenditures in amounts necessary to maintain our asset base, a portion of future distributions will represent a return ofcapital and the value of our common units will be adversely affected, which will eventually cause our cash distributions per unit to decrease. Withholdingcash for our capital expenditures may have an adverse impact on the cash distributions in the quarter in which amounts are withheld.26 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, 2015, the spot price for West Texas Intermediate light sweet crude oil, which we refer to asWTI has ranged from a high of $113.39 per Bbl in 2011 to a low of $34.55 per Bbl in 2015. During the same period, the Henry Hub spot market price ofnatural gas has ranged from a low of $1.63 in 2015 to a high of $8.15 per MMBtu in 2014. During 2015, the WTI spot price of oil ranged from $34.55 to$61.36 per Bbl and the Henry Hub spot market price of natural gas ranged from $1.63 to $3.32 per MMBtu. On December 31, 2013, the WTI spot price for oilwas $98.17 per Bbl and the Henry Hub spot market price of natural gas was $4.31 per MMBtu. On December 31, 2014, the WTI spot price for oil was $53.45per Bbl, and the Henry Hub spot market price of natural gas was $2.99 per MMBtu. On December 31, 2015, the WTI spot price for oil was $37.13 per Bbl, andthe Henry Hub spot market price of natural gas was $2.28 per MMBtu.Any 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 estimated27 proved reserves, which could negatively impact our borrowing base and our ability to fund our operations. If this occurs or if production estimates change orexploration or development results deteriorate, successful efforts method of accounting principles may require us to write down, as a non-cash charge toearnings, the carrying value of our oil and natural gas properties. Our operators could also determine during periods of low commodity prices to shut in orcurtail production from wells on our properties. In addition, they could determine during periods of low commodity prices to plug and abandon marginalwells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, they may abandon anywell if they reasonably believe that the well can 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 58.5% of our 2015 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 $37.13 per Bbl on December 31, 2015.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. The International Energy Agency (“IEA”) forecasts global demand growth to ease back considerably in 2016 to 1.2 millionBbl/d from a five-year high of 1.6 million Bbl/d in 2015. This environment could cause prices for oil to remain at current levels or to fall to lower levels. Ifprices for oil continue to remain depressed for lengthy periods, we may be required to further write down the value of our oil and natural gas properties inaddition to impairments taken during 2015, and some of our undeveloped locations may no longer be economically viable. In addition, sustained low pricesfor oil will continue to negatively impact the value of our estimated proved reserves and the amount that we are allowed to borrow under our bank creditfacility and reduce the amounts of cash we would otherwise have available to pay expenses, fund capital expenditures, make distributions to our unitholders,and service our indebtedness.Natural gas prices have declined substantially from historical highs and are expected to remain depressed for the foreseeable future. Approximately65.9% of our 2015 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 eight years prior to December 31, 2015, natural gas prices at Henry Hub have ranged from a high of $13.31 per MMBtu in 2008 to a low of$1.63 per MMBtu in 2015. On December 31, 2015, the Henry Hub spot market price of natural gas was $2.28 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 some of our undeveloped locations may no longer be economically viable. In addition,sustained low prices for natural gas will continue to negatively impact the value of our estimated proved reserves and the amount that we are allowed toborrow under our bank credit facility and reduce the amounts of cash we would otherwise have available to pay expenses, make distributions to ourunitholders, 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 willdepend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic data,and other information, the results of which are often inconclusive and subject to various interpretations. The successful acquisition of properties requires anassessment of several factors, including: •recoverable reserves; •future oil and natural gas prices and their applicable differentials; •development plans; •operating costs; and •potential environmental and other liabilities.The accuracy of these assessments is inherently uncertain and we may not be able to identify attractive acquisition opportunities. In connection 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 contractualprotection28 against all or part of the problems. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so oncommercially 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,and costs; •a decrease in our liquidity by using a significant portion of our cash generated from operations or borrowing capacity to finance acquisitions; •a significant increase in our interest expense or financial leverage if we incur debt to finance acquisitions; •the assumption of unknown liabilities, losses, or costs for which we are not indemnified or for which any indemnity we receive is inadequate; •mistaken assumptions about the overall cost of equity or debt; •our ability to obtain satisfactory title to the assets we acquire; •an inability to hire, train, or retain qualified personnel to manage and operate our growing business and assets; and •the occurrence of other significant changes, such as impairment of oil and natural gas properties, goodwill or other intangible assets, 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 effect onour results of operations.Our assets consist of mineral and royalty interests and non-operated working interests. For the year ended December 31, 2015, 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 to theirreasonable discretion. Our operators could determine to drill and complete fewer wells on our acreage than is currently expected. The success and timing ofdrilling and development activities on our properties, and whether the operators elect to drill any additional wells on our acreage, depends on a number offactors that will be largely outside of our control, including: •the capital costs required for drilling activities by our operators, which could be significantly more than anticipated; •the ability of our operators to access capital; •prevailing commodity prices; •the availability of suitable drilling equipment, production and transportation infrastructure, and qualified operating personnel; •the operators’ expertise, operating efficiency, and financial resources; •approval of other participants in drilling wells;29 •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 an 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.Producing 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 undeveloped30 drilling location will be made by the operator and not by us. The reserve data included in the reserve report of our engineer assume that substantial capitalexpenditures are required to develop the reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, thatdevelopment will occur as scheduled or that the results of the development will be as estimated. Delays in the development of our reserves, increases in coststo drill and develop our reserves, or decreases in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and mayresult in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our undevelopedreserves 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 theavailability of capital, construction of infrastructure, inclement weather, regulatory changes and approvals, oil and natural gas prices, costs, drilling results,and the availability of water. Further, our operators’ identified potential drilling locations are in various stages of evaluation, ranging from locations that areready to drill to locations that will require substantial additional interpretation. The use of technologies and the study of producing fields in the same areawill not enable our operators to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will bepresent in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, our operators may damage the potentiallyproductive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction inproduction from the well or abandonment of the well. If our operators drill additional wells that they identify as dry holes in current and future drillinglocations, their drilling success rate may decline and materially harm their business as well as ours.We cannot assure you that the analogies our operators draw from available data from the wells on our acreage, more fully explored locations, orproducing fields will be applicable to their drilling locations. Further, initial production rates reported by our or other operators in the areas in which ourreserves are located may not be indicative of future or long-term production rates. Because of these uncertainties, we do not know if the potential drillinglocations our operators have identified will ever be drilled or if our operators will be able to produce oil or natural gas from these or any other potentialdrilling locations. As such, the actual drilling activities of our operators may materially differ from those presently identified, which could adversely affectour business, results of operation, and cash distributions to unitholders.The unavailability, high cost, or shortages of rigs, equipment, raw materials, supplies, or personnel may restrict or result in increased costs foroperators related to developing and operating our properties.The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly sand and otherproppants), supplies, and personnel. When shortages occur, the costs and delivery times of rigs, equipment, and supplies increase and demand for, and wagerates of, qualified drilling rig crews also rise with increases in demand. In accordance with customary industry practice, our operators rely on independentthird-party service providers to provide many of the services and equipment necessary to drill new wells. If our operators are unable to secure a sufficientnumber of drilling rigs at reasonable costs, our financial condition and results of operations could suffer. Shortages of drilling rigs, equipment, raw materials(particularly sand and other proppants), supplies, personnel, trucking services, tubulars, fracking and completion services, and production equipment coulddelay or restrict our operators’ exploration and development operations, which in turn could have a material adverse effect on our financial condition, resultsof operations, and cash distributions to unitholders.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 with31 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 financialcondition, results of operations, and cash distributions to unitholders. Our or our operators’ access to transportation options and the prices we or our operatorsreceive can also be affected by federal and state regulation—including regulation of oil production, transportation, and pipeline safety—as well by generaleconomic conditions and changes in supply and demand. In addition, the third parties on whom we or our operators rely for transportation services aresubject 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, 2015 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, 2015 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, 2015 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.Our operators use the latest drilling and completion techniques in their operations, and these techniques come with inherent risks. When drillinghorizontal wells, operators risk not landing the well bore in the desired drilling zone and straying from the desired drilling zone. When drilling horizontallythrough a formation, operators risk being unable to run casing through the entire length of the well bore and being unable to run tools and other equipmentconsistently through the horizontal well bore. Risks that our operators face while completing wells include being unable to fracture stimulate the plannednumber of stages, to run tools the entire length of the well bore during completion operations, and to clean out the well bore after completion of the finalfracture stimulation stage. In addition, to the extent our operators engage in horizontal drilling, those activities may adversely affect their ability tosuccessfully drill in identified vertical drilling locations. Furthermore, certain of the new techniques that our operators may adopt, such as infill drilling andmulti-well pad drilling, may cause irregularities or interruptions in production due to, in the case of infill drilling, offset wells being shut in and, in the case ofmulti-well pad drilling, the time required to drill and complete multiple wells before these wells begin producing. The results of drilling in new or emergingformations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer oremerging formations and areas often have limited or no production history and consequently our operators will be less able to predict future drilling results inthese areas.Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production 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 and32 natural gas properties and the value of our undeveloped acreage could decline, and our results of operations and cash distributions to unitholders could beadversely 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. Please read Part I, Items 1 and 2. “Business and Properties—Environmental Matters” for a description of the laws and regulations that affect our operators and that may affect us. These and other potential regulationscould increase the operating costs of our operators and delay production, which could reduce the amount of cash distributions to our unitholders.Louisiana mineral servitudes are subject to reversion to the surface owner after ten years’ nonuse.We own mineral servitudes covering several hundred thousand acres in Louisiana. A mineral servitude is created in Louisiana when the mineral 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.33 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 underground injection ofsubstances through the Underground Injection Control (“UIC”) program. Hydraulic fracturing is generally exempt from regulation under the UIC program,and the hydraulic-fracturing process is typically regulated by state oil and natural gas commissions. The U.S. Environmental Protection Agency (“EPA”),however, has recently taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program and issuedguidance in February 2014 applicable to hydraulic fracturing involving the use of diesel fuel. The EPA has also issued final regulations under the federalClean Air Act governing performance standards, including standards for the capture of air emissions released during hydraulic fracturing; proposed in April2015 to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants; and issued in May 2015 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 Bureau of Land Management (“BLM”) finalized rules inMarch 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands including, for example,notice to and pre‑approval by BLM of the proposed hydraulic fracturing activities; development and pre‑approval 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.Several governmental reviews are underway that focus on environmental aspects of hydraulic fracturing activities. In June 2015, the EPA released itsdraft report on the potential impacts of hydraulic fracturing on drinking water resources, which concluded that hydraulic fracturing activities have not led towidespread, systemic impacts on drinking water sources in the United States, although there are above and below ground mechanisms by which hydraulicfracturing activities have the potential to impact drinking water sources. The draft report is expected to be finalized after a public comment period and aformal review by EPA’s Science Advisory Board. In addition, the White House Council on Environmental Quality is coordinating an administration‑widereview of hydraulic fracturing practices. These studies, depending on their results, could spur efforts to further regulate hydraulic fracturing.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 if scientificdata 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 terminatethe permit application or existing operating permit for that well. These existing or any new legal requirements establishing seismic permitting requirementsor similar restrictions on the construction or operation of disposal wells for the injection of produced water likely will result in added costs to comply andaffect our operators’ rate of production, which in turn could have a material adverse effect on our results of operations and financial position. In addition tostate laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general or hydraulic fracturing inparticular. In the event state, local, or municipal legal restrictions are adopted in areas where our operators conduct operations, our operators may incursubstantial costs to comply with these requirements, which may be significant in nature, experience delays, or curtailment in the pursuit of exploration,development, or production activities and perhaps even be precluded from the drilling of wells.There has been increasing public controversy regarding hydraulic fracturing with regard to increased risks of induced seismicity, the use of 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.34 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 31,2015, we had outstanding borrowings of $66.0 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 2015 is $550.0 million and the next semi-annual redetermination is scheduled for April 2016.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 immediately due and payable, our ability to make distributions will be inhibited, and our lenders’ commitment to make furtherloans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations underour credit facility are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our credit facility, the lenders can seek toforeclose on our assets.The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the oil and natural gas thatour operators produce.In response to findings that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”) present an endangerment to public 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, theEPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sourcesin the United States on an annual basis, which include operations on certain of our properties. More recently, in December 2015, the EPA finalized rulesadded new sources to the scope of the GHG monitoring and reporting rule. These new sources include gathering and boosting facilities as well as completionsand workovers of hydraulically fractured wells. Also, in August 2015, the EPA announced proposed rules that would establish new air emission controls formethane emissions from certain new, modified, or35 reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission, and storage activities, aspart of an overall effort to reduce methane emissions by up to 45% in 2025. These rules could result in increased compliance costs for our operators andrequire them to make expenditures to purchase pollution control 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 and regionalefforts have emerged that are aimed at tracking or reducing GHG emissions by means of cap and trade programs. These programs typically require majorsources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. Although it is not possible at this time to predicthow legislation or new regulations that may be adopted to address GHG emissions would impact our business, any future laws and regulations imposingreporting obligations on, or limiting emissions of GHGs from, our operators’ equipment and operations could require them to incur costs to reduce emissionsof GHGs associated with their operations. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil and natural gasproduced from our properties. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states, as well as state and local climatechange initiatives, could adversely affect the oil and natural gas industry, and, at this time, it is not possible to accurately estimate how potential future lawsor regulations addressing GHG emissions would impact our business. Finally, it should be noted that some scientists have concluded that increasingconcentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency andseverity of storms, floods, and other 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.In accordance with what we believe to be customary industry practice, we maintain insurance against some, but not all, of our business risks. Ourinsurance may not be adequate to cover any losses or liabilities we may suffer. Also, insurance may no longer be available to us or, if it is, its availability maybe at premium levels that do not justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limitsmaintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normalbusiness operations and on our financial condition, results of operations, or cash distributions to unitholders. In addition, we may not be able to secureadditional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severelyimpact our financial position. We may also be liable for environmental damage caused by previous owners of properties purchased by us, which liabilitiesmay not be covered by insurance.We may not have coverage if we are unaware of a sudden and accidental pollution event and unable to report the “occurrence” to our 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 and36 our security measures failed, the potential consequences 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 partnershipagreement does not require us to pay any distributions at all. If we make distributions, our preferred unitholders have priority with respect to rights toshare in those 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 distribution amount under certain circumstances that we do not expect to occur. Even if thoseadditional distributions do occur, considering that the outstanding preferred units are convertible into only a relatively small number of our total outstandingcommon and subordinated units, we believe these additional distributions payable under those circumstances would not materially adversely affect the perunit distribution rate we would otherwise pay on our common and subordinated units. Our initial minimum quarterly distribution is $1.05 per common andsubordinated unit on an annualized basis (or $0.2625 per unit on a quarterly basis) for the four quarters ending March 31, 2016. The minimum quarterlydistribution will be $1.15 per common and subordinated unit on an annualized basis (or $0.2875 per unit on a quarterly basis) for the four quarters endingMarch 31, 2017. We expect that we will distribute a substantial majority of the cash we generate from operations each quarter. However, the board of directorsof our general partner could elect not to pay distributions for one or more quarters or at all. Please read Part II, Item 5. “Market for Registrant’s CommonEquity, Related Unitholder Matters and Issuer Purchases of Equity Securities—Cash Distribution Policy.”Our partnership agreement does not require us to pay any distributions at all on our common units. Accordingly, investors are cautioned not to placeundue reliance on the permanence of any distribution policy in making an investment decision. Any modification or revocation of our cash distributionpolicy could substantially reduce or eliminate the amounts of distributions to our unitholders. The amount of distributions we make, if any, and the decisionto make any distribution at all will be determined by the board of directors of our general partner. If we make distributions, our 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.”37 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. Forexample, our partnership agreement provides that our general partner and its directors and executive officers will not be liable for monetary damages to us orour limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdictiondetermining that the general partner or those other persons acted in bad faith or engaged in willful misconduct or fraud or, with respect to any criminalconduct, with the knowledge that its conduct was unlawful.Unitholders are bound by the provisions of our partnership agreement, including the provisions described above.Our partnership agreement restricts the voting rights of unitholders owning 15% or more of our units, subject to certain exceptions.Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person or group that owns 15% or more of 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.Actions taken by our general partner may affect the amount of cash generated from operations that is available for distribution to unitholders oraccelerate the right to convert subordinated units.The amount of cash generated from operations available for distribution to unitholders is affected by decisions of our general partner regarding suchmatters as: •amount and timing of asset purchases and sales; •cash expenditures; •borrowings; •entry into and repayment of current and future indebtedness; •issuance of additional units; and •the creation, reduction, or increase of reserves in any quarter.In addition, borrowings by us do not constitute a breach of any duty owed by our general partner to our unitholders, including borrowings that 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 amount, equal to $137.6 million, which would not otherwise constitute cash generated from operations, inorder to permit the payment of distributions on subordinated units. All of these actions may affect the amount of cash distributed to our unitholders and mayfacilitate the conversion of subordinated units into common units.38 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 Revised Uniform Limited Partnership Act (the “Delaware Act”), we may not make a distribution to our unitholders if the distribution would causeour liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution,limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limitedpartnership for the distribution amount. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnershipare not counted for purposes of determining whether a distribution is permitted.Increases in interest rates may cause the market price of our common units to decline.An increase in interest rates may cause a corresponding decline in demand for equity investments in general, and in particular, for yield-based 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; •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, 2015, we had 96,161,911 common units and 95,057,312 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.39 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.For as long as we are an emerging growth company, we will not be required to comply with certain disclosure requirements, including those relating toaccounting standards, our executive compensation, and internal control auditing requirements that apply to other public companies.We are classified as an “emerging growth company” under Section 2(a)(19) of the Securities Act. For as long as we are an emerging growth company,which may be up to five full fiscal years, we will not be required to comply with certain requirements that other public companies are required to complywith. Among other things, we will not be required to: •provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reportingpursuant to Section 404(b) of the Sarbanes-Oxley Act; •comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor’s report inwhich the auditor would be required to provide additional information about the audit and the financial statements of the issuer; or •provide certain disclosure regarding executive compensation required of larger public companies.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. We must comply with Section 404 (except for the requirement for an auditor’s attestation report) beginning withour fiscal year ending December 31, 2016. 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.Our partnership agreement is governed by Delaware law. Our partnership agreement includes exclusive forum, venue, and jurisdiction provisionsdesignating Delaware courts as the exclusive venue for all claims, suits, actions, or proceedings arising out of or relating in any way to the partnershipagreement, brought in a derivative manner on behalf of the partnership, asserting a claim of breach of a fiduciary or other duty owed by any director, officer,or other employee of the partnership or the general partner, or owed by the general partner to the partnership or the partners, asserting a claim arising pursuantto any provision of the Delaware Act, or asserting a claim governed by the internal affairs doctrine. By purchasing a common unit, a limited partner isirrevocably consenting to these provisions regarding claims, suits, actions, or proceedings and submitting to the exclusive jurisdiction of Delaware courts. Ifa40 dispute were to arise between a limited partner and us or our officers, directors, or employees, the limited partner may be required to pursue its legal remediesin 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,which is currently a maximum of 35%. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains,losses, or deductions would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, cash distributions to our unitholderswould be substantially reduced. In addition, changes in current state law may subject us to additional entity-level taxation by individual states. Because ofwidespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the impositionof state income, franchise, and other forms of taxation. Imposition of any of those taxes may substantially reduce the cash distributions to our unitholders.Therefore, treatment of us as a corporation or the assessment of a material amount of entity-level taxation would result in a material reduction in theanticipated cash generated from operations and after-tax return to the 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. For example, the Obama administration’s budget proposal for fiscalyear 2017 recommends that certain publicly traded partnerships earning income from activities related to fossil fuels be taxed as corporations beginning in2022. From time to time, members of Congress propose and consider similar substantive changes to the existing federal income tax laws that affect publiclytraded partnerships. If successful, such proposals could eliminate the qualifying income exception to the treatment of all publicly traded partnerships ascorporations upon which we rely for our treatment as a partnership for federal income tax purposes.In addition, the IRS, on May 5, 2015, issued proposed regulations concerning which activities give rise to qualifying income within the meaning ofSection 7704(d)(1)(E) of the Internal Revenue Code. The proposed regulations provide an exclusive list of industry-specific rules regarding the qualifyingincome exception, including whether an activity constitutes the exploration, development, production, and marketing of natural resources. Income earnedfrom a royalty interest is not specifically enumerated as a qualifying income activity in the proposed regulations. However, notwithstanding the proposedregulations, our external counsel has advised us that royalty income is qualifying income for purposes of Section 7704 of the Internal Revenue Code since itis “derived” from the exploration, development, production, and marketing of natural resources. The U.S. Treasury Department and the IRS may clarify thatroyalty income is qualifying income for purposes of Section 7704 of the Internal Revenue Code; however, there are no assurances that the proposedregulations, when published as final regulations, will not take a position that is contrary to our interpretation of Section 7704 of the Internal Revenue Code.41 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.Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as acorporation or otherwise subjects us to entity-level taxation for federal income tax purposes, the minimum quarterly distribution may be adjusted to reflectthe impact of that law on us.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.Potential legislation, if enacted into law, could make significant changes to U.S. federal and state income tax laws, including the elimination ofcertain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies. These changes include, but arenot limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties; (ii) the elimination of current deductions forintangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of theamortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted,how soon any such changes could become effective. The passage of this legislation or any other similar changes in U.S. federal and state income tax lawscould eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and anysuch change could negatively impact the value of an investment in our common units. Additionally, legislation could be enacted that increases the taxesstates impose on oil and natural gas extraction. Moreover, President Obama has proposed, as part of the Budget of the United States Government forFiscal Year 2017, to impose an “oil fee” of $10.25 on a per barrel equivalent of crude oil. This fee would be collected on domestically produced andimported petroleum products. The fee would be phased in evenly over five years, beginning October 1, 2016. The adoption of this, or similar proposals,could result in increased operating costs and/or reduced consumer demand for petroleum products, which in turn could affect our financial position andcash 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 distributions to our unitholders. Recently enacted legislation alters the procedures for assessing and collecting taxes due fortaxable years beginning after December 31, 2017, in a manner that could substantially reduce cash available for distribution to our unitholders.We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affectingus. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some orall of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely affect themarket for our common units and the price at which they trade. Moreover, the costs of any contest between us and the IRS will result in a reduction in cashdistributions to our unitholders and thus will be borne indirectly by our unitholders.Recently enacted legislation, applicable to us for taxable years beginning after December 31, 2017, alters the procedures for auditing largepartnerships and also alters the procedures for assessing and collecting taxes due (including applicable penalties and interest) as a result of an audit. Underthe new rules, unless we are eligible to, and do, elect to issue revised Schedules K-1 to our partners with respect to an audited and adjusted return, the IRSmay assess and collect taxes (including any applicable penalties and interest) directly from us in the year in which the audit is completed. If we are requiredto pay taxes, penalties and interest as the result of audit adjustments, cash available for distribution to our unitholders may be substantially reduced. Inaddition, because payment would be due for the taxable year in which the audit is completed, unitholders during that taxable year would bear the expense ofthe adjustment even if they were not unitholders during the audited taxable year.Even if you, as a unitholder, do not receive any cash distributions from us, you will be required to pay taxes on your share of our taxable income.You will be required to pay federal income taxes and, in some cases, state and local income taxes, on your share of our taxable income, whether or notyou receive cash distributions from us. For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, you may beallocated taxable income and gain resulting from the sale and our cash available for distribution would not increase. Similarly, taking advantage ofopportunities to reduce our existing debt, such as debt exchanges, debt repurchases, or modifications of our existing debt could result in “cancellation ofindebtedness income” being allocated to our unitholders as taxable income without any increase in our cash available for distribution. You may not receivecash distributions from us equal to your share of our taxable income or even equal to the actual tax due from you with respect to that income.42 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 you dueto potential recapture items, including depreciation recapture. Thus, you may recognize both ordinary income and capital loss from the sale of your units ifthe 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, including IRAsand 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 prorate our items of income, gain, loss, and deduction between transferors and transferees of our common units each month based upon theownership of our common units on the first day of each month, 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 prorate our items of income, gain, loss, and deduction between transferors and transferees of our units each month based upon the ownership of ourunits on the first day of each month, instead of on the basis of the date a particular unit is transferred. The U.S. Department of the Treasury recently adoptedfinal Treasury Regulations allowing a similar monthly simplifying convention for taxable years beginning on or after August 3, 2015. However, suchregulations do not specifically authorize the use of the proration method we have adopted for our 2015 taxable year and may not specifically authorize allaspects of our proration method thereafter. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income,gain, loss, and deduction among our unitholders.A unitholder whose units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of units) may be considered to havedisposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan andcould recognize gain or loss from the disposition.Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a unitholder whose units are thesubject of a securities loan may be considered to have disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as apartner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from this disposition.Moreover, during the period of the loan, any of our income, gain, loss, or deduction with respect to those units may not be reportable by the unitholder andany cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status aspartners and avoid the risk of gain recognition from a securities loan are urged to modify any applicable brokerage account agreements to prohibit theirbrokers from borrowing their units.43 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 in ourcommon units.In addition to federal income taxes, you likely will be subject to other taxes, including state and local taxes, unincorporated business taxes and estate,inheritance, or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if youdo not live in any of those jurisdictions. We will initially own assets and conduct business in several states, many of which impose a personal income tax andalso impose income taxes on corporations and other entities. You may be required to file state and local income tax returns and pay state and local incometaxes in these jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. As we make acquisitions or expand ourbusiness, we may own assets or conduct business in additional states or foreign jurisdictions that impose a personal income tax. It is your responsibility to fileall U.S. federal, foreign, state, and local tax returns. ITEM 1B. UNRESOLVED STAFF COMMENTSNone. ITEM 3. LEGAL PROCEEDINGSAlthough we may, from time to time, be involved in various legal claims arising out of our operations in the normal course of business, we do 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. 44 PART II ITEM 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 SubordinatedUnit 2015 Second Quarter2 $19.00 $16.59 $0.1615 $0.1615 Third Quarter 17.50 13.27 $0.2625 $0.2625 Fourth Quarter 16.50 12.03 $0.2625 $0.18375 1Represents cash distributions attributable to the quarter. Cash distributions declared in respect of a quarter are paid in the following quarter.2The price range of our common units includes our $19.00 per common unit initial public offering price on April 30, 2015. Distributions were proratedfor the period from the completion of our initial public offering on May 6, 2015 through June 30, 2015.As of March 4, 2016, there were 96,965,879 common units outstanding held by 486 holders of record. Because many of our common units are heldby brokers and other institutions on behalf of unitholders, we are unable to estimate the total number of unitholders represented by these holders of record. Asof March 4, 2016, we had also outstanding 95,002,347 subordinated units, and 77,216 preferred units. There is no established public market in which thesubordinated units or the preferred units are traded.45 Common Unit Performance GraphThe graph below compares our cumulative total unitholder return on our common units beginning on April 30, 2015, the date of pricing for our IPO,through December 31, 2015 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 TotalReturnAssumes Initial Investment of $100As of December 31, 2015 As of April 30, 2015 As of December 31, 2015Black Stone Minerals, L.P. $100.00 $78.22S&P 500 Index 100.00 99.47Alerian MLP Index 100.00 66.99The information in this report appearing under the heading “Common Unit Performance Graph” is being furnished pursuant to Item 2.01(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 2.01(e) of Regulation S-K, or to the liabilities of Section 18 of the Exchange Act.Securities Authorized for Issuance under Equity Compensation PlansSee the information incorporated by reference under “Item 12. Security Ownership of Certain Beneficial Owners and Management and RelatedUnitholder Matters” regarding securities authorized for issuance under our equity compensation plans.46 Purchases of Equity Securities by the Issuer and Affiliated PurchasersThe following table sets forth purchases made by us of our preferred units during the three months ended December 31, 2015. Our preferred units maybe converted, at the option of the holder thereof, at any time, and without the payment of additional consideration, into common units and subordinated unitsat the then-effective conversion rate. The preferred units have a conversion rate of 30.3431 common units and 39.7427 subordinated units per preferred unit,subject to adjustment. Period Total Number of PreferredUnits Purchased Average Price PaidPer Unit Total Number of Preferred UnitsPurchased as Part of PubliclyAnnounced Plans or Programs Maximum Number of PreferredUnits That May Yet Be PurchasedUnder the Plans or Programs December 1 - December 31,20151 40,747 $1,019.45 40,747 — 1On November 6, 2015, we commenced a tender offer to purchase up to 100% of the 117,963 then outstanding preferred units from our preferredunitholders at the units’ par value of $1,000.00 per preferred unit, plus unpaid accrued yield. The tender offer expired on December 10, 2015. Wepurchased and cancelled 40,747 preferred units, representing 34.5% of our then outstanding preferred units. The tendered units were purchased for$1,019.45 per preferred unit for a total cost of approximately $41.5 million, excluding fees and expenses relating to the tender offer.Cash Distribution PolicyOur partnership agreement generally provides that we will pay any distributions each quarter during the subordination period in the followingmanner: ·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 amountsspecified below plus any arrearages from prior quarters; and ·third, to the holders of subordinated units, until each subordinated unit has received the applicable minimum quarterly distribution.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: Minimum Quarterly Distribution(per unit) Four Quarters Ending March 31, Per Quarter Annualized 2016 $0.2625 $1.05 2017 0.2875 1.15 2018 0.3125 1.25 2019 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,47 borrowings under our credit facility, and, in certain circumstances, proceeds from future equity and debt issuances. We may also borrow to make distributionsto our unitholders where, for example, we believe that the distribution level is sustainable over the long term, but short-term factors may cause cash generatedfrom operations to be insufficient to pay distributions at the applicable minimum quarterly distribution level on our common and subordinated units. Theboard of directors of our general partner can change the amount of the quarterly distributions, if any, at any time and from time to time. Our partnershipagreement does not require us to pay cash distributions on a quarterly or other basis. Please read Part I, Item 1A. “Risk Factors—Risks Inherent in anInvestment in Us—The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion. Ourpartnership 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.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 otherbasis, and if distributions are paid, common and subordinated unitholders will receive distributions only to the extent the distribution amountexceeds distributions 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 outstandingloans under our credit facility. Among other covenants, our credit facility requires we maintain a ratio of total debt to EBITDAX of 3.50:1.00 orless and a current ratio of 1.00:1.00 or greater. If we are unable to comply with these financial covenants or if we breach any other covenantunder our credit facility or any future debt agreements, we could be prohibited from making distributions notwithstanding our stateddistribution policy. ·Our general partner will have the authority to establish cash reserves for the prudent conduct of our business, and the establishment of, orincrease in, those reserves could result in a reduction in cash distributions to our unitholders. Our partnership agreement does not limit theamount of cash reserves that our general partner may establish. Any decision to establish cash reserves made by our general partner will bebinding 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 fairvalue of our assets. ·We may lack sufficient cash to pay distributions to our unitholders due to shortfalls in cash generated from operations attributable to a numberof operational, commercial, or other factors as well as increases in our operating or general and administrative expenses, principal and interestpayments on our outstanding debt, working-capital requirements, and anticipated cash needs.We expect to continue to distribute a substantial majority of our cash from operations to our unitholders on a quarterly basis, after, among otherthings, 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 orborrow under our credit facility. To the extent efforts to access capital externally are unsuccessful, our ability to grow could be significantly impaired.Any distributions paid on our common and subordinated units with respect to a quarter will be paid within 60 days after the end of such quarter.Subordinated 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 such48 quarter plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages. Ourcommon unitholders are only entitled to arrearages in the payment of the minimum quarterly distribution from prior quarters during the subordination period.To the extent we have cash generated from operations available for distribution in any quarter during the subordination period in excess of the amountnecessary to pay the applicable minimum quarterly distribution to holders of our common units, we will use this excess cash to pay any distributionarrearages on the common units related to prior quarters before any cash distribution is made on our subordinated units. Please read “Cash DistributionPolicy.” 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.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. Any additional distributions shall be distributed tothe 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 subordinated units, subordinatedunits, (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 Market Value equaledthe value as of such date, adjusted to reflect any increases in equity value resulting from the deemed conversion, exchange or exercise of convertiblesecurities, and (c) an amount equal to such value, as so adjusted, were distributed to the unitholders in accordance with the liquidation distributionprovisions 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 followingcertain events 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. 49 ITEM 6. SELECTED FINANCIAL DATAThe financial information below should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition andResults of Operations” and “Item 8. Financial Statements and Supplementary Data” of this Annual Report. At December 31, 2015 2014 2013 (In thousands, except per unit amounts) Total revenue $392,924 $548,321 $463,559 Net income (loss) (101,305) 169,187 168,963 Net loss attributable to the general partner and commonunits and subordinated units subsequent to initialpublic offering (108,017) * * Net loss attributable to limited partners per common andsubordinated unit (basic)1 Per common unit (basic) (0.56) * * Per subordinated unit (basic) (0.56) * * Net loss attributable to limited partners per common andsubordinated unit (diluted)1 Per common unit (diluted) (0.56) * * Per subordinated unit (diluted) (0.56) * * Cash distributions declared per common andsubordinated unit Per common unit 0.4240 * * Per subordinated unit 0.4240 * * Total assets2 1,061,436 1,326,782 1,444,413 Long-term debt 66,000 394,000 451,000 Total mezzanine equity 79,162 161,165 161,392 *Information is not applicable for the periods prior to our initial public offering.1See Note 15 – Earnings Per Unit in the consolidated financial statements included elsewhere in this Annual Report.2We recorded noncash impairments of oil and natural gas properties in the amounts of $249.6 million, $117.9 million, and $57.1 million, for the yearsended December 31, 2015, 2014, and 2013, respectively. 50 ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSThe following discussion and analysis of our financial condition and results of operations should be read in conjunction with our 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 1, 2015 our common units began trading on the New York Stock Exchange under the symbol “BSM.” On May 6, 2015, we completed ourinitial public offering of 22,500,000 common units representing limited partner interests.Our mineral and royalty interests consist of mineral interests in approximately 14.6 million acres, with an average 47.8% ownership interest in thatacreage, NPRIs in 1.3 million acres, and ORRIs in 1.4 million acres. These non-cost-bearing interests include ownership in over 45,000 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 DevelopmentsCommon Unit Repurchase ProgramOn March 4, 2016, the board of directors of our general partner authorized the repurchase of up to $50.0 million in common units over the next sixmonths. The repurchase program authorizes us to make repurchases on a discretionary basis as determined by management, subject to market conditions,applicable legal requirements, available liquidity, and other appropriate factors. All or a portion of any repurchases may be made under a Rule 10b5-1 plan,which would permit common units to be repurchased when we might otherwise be precluded from doing so under insider trading laws. The repurchaseprogram does not obligate us to acquire any particular amount of common units and may be modified or suspended at any time and could be terminated priorto completion. We will periodically report the number of common units repurchased. The repurchase program will be funded from our cash on hand oravailable revolving credit facility. Any repurchased common units will be cancelled.Cash Tender OfferOn November 6, 2015, we commenced a tender offer to purchase up to 100% of the 117,963 then outstanding preferred units from our preferredunitholders at the units’ par value of $1,000.00 per preferred unit, plus unpaid accrued yield. The tender offer expired on December 10, 2015. We purchasedand cancelled 40,747 preferred units, representing 34.5% of our then outstanding preferred units. The preferred units were purchased at a purchase price of$1,019.45 per preferred unit for a total cost of approximately $41.5 million, excluding fees and expenses relating to the tender offer.AcquisitionsWe closed five separate transactions to acquire unproved oil and natural gas properties in the Permian Basin during 2015 for a total $51.7 million. Weacquired acreage in the Eagle Ford Shale play through two transactions totaling $9.7 million during 2015, and we also acquired an overriding royalty interestin the Utica Shale and Marcellus plays for $1.8 million.Business EnvironmentThe information below is designed to give a broad overview of the oil and natural gas business environment as it affects us.51 Commodity PricesOil and natural gas prices have been historically volatile based upon the dynamics of supply and demand. During 2015, oil and natural gas priceshave remained significantly below prices seen over the past five years as global concerns of long-term supply imbalances and slowing demand growth havecontinued to weigh on prices. West Texas Intermediate (“WTI”) spot prices ranged from a low of $34.55 per Bbl on December 21, 2015 to a high of $61.36per Bbl on June 10, 2015. Oil prices have continued to be pressured downward following the end of the year, reaching a low of $26.19 per Bbl on February11, 2016. During 2015, Henry Hub spot natural gas prices ranged from a low of $1.63 per MMBtu on December 23, 2015 to a high of $3.32 per MMBtu onJanuary 15, 2015. The Henry Hub spot price closed at $1.62 per MMBtu on February 29, 2016. To manage the variability in cash flows associated with theprojected sale of our oil and natural gas production, we use various derivative instruments, which have generally consisted of fixed-price swaps and costlesscollars.The following table reflects commodity prices at the end of each of the four quarters for the most recently completed fiscal year: 2015 Benchmark Prices FirstQuarter SecondQuarter ThirdQuarter FourthQuarter WTI spot oil price ($/Bbl) $47.72 $59.48 $45.06 $37.13 Henry Hub spot natural gas ($/MMBtu) $2.65 $2.80 $2.47 $2.28 Source: EIA Rig CountSince we are not an operator, drilling on our acreage is dependent upon the exploration and production companies that lease our acreage. In additionto drilling plans that we seek from our operators, we monitor rig counts in an effort to identify existing and future leasing and drilling activity on our acreage.The following table shows the rig count at the end of each of the four quarters for the most recently completed fiscal year: 2015 U.S. Rotary Rig Count FirstQuarter SecondQuarter ThirdQuarter FourthQuarter Oil 813 628 641 536 Natural gas 233 228 197 162 Other 2 3 — — Total 1,048 859 838 698 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.52 The following table shows natural gas storage volumes by region at the end of each of the four quarters for the most recently completed fiscal year: 2015 Region FirstQuarter SecondQuarter ThirdQuarter FourthQuarter (Bcf) East 255 552 837 876 Midwest 261 546 952 1,025 Mountain 114 155 201 195 Pacific 269 333 355 338 South Central 562 993 1,192 1,322 Total 1,461 2,579 3,537 3,756 Source: 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 NGLs vary by geographical area. The relative prices of these products are determined by the factorsaffecting global and regional supply and demand dynamics, such as economic conditions, production levels, availability of transportation, weather cycles,and other factors. In addition, realized prices are influenced by product quality and proximity to consuming and refining markets. Any differences betweenrealized prices and NYMEX prices are referred to as differentials. All of our production is derived from properties located in the United States. As a result ofour geographic diversification, we are not exposed to concentrated differential risks associated with any single play, trend, or basin. ·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, variationsin chemical composition relative to the benchmark crude oil, usually WTI, will result in price adjustments, which are often referred to asquality differentials. The characteristics that most significantly affect quality differentials include the density of the oil, as characterized by itsAPI 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.53 ·Natural Gas. The NYMEX price quoted at Henry Hub is a widely used benchmark for the pricing of natural gas in the United States. The actualvolumetric prices realized from the sale of natural gas differ from the quoted NYMEX price as a result of quality and location differentials. Quality differentials result from the heating value of natural gas measured in Btus and the presence of impurities, such as hydrogen sulfide,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 made up of 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, costless collars, fixed-price contracts, and other contractual arrangements. We currently employ a“rolling hedge” strategy whereby we hedge a significant portion of our proved developed producing reserves 18 to 24 months into the future. The impact ofthese derivative instruments could affect the amount of revenue we ultimately realize. Throughout 2014, we entered into costless collars to allow us theability to participate in upward movements in commodity prices while also setting a price floor for a portion of our production. Costless collars are acombination of a purchased put option and a sold call option, in which the premiums paid and received net to zero. During the fourth quarter of 2014 and allof 2015, we also entered into fixed-price swap contracts. Under fixed-price swap contracts, a counterparty is required to make a payment to us if thesettlement price for any settlement period is less than the swap strike price; conversely, we are required to make a payment to the counterparty if thesettlement price for any settlement period is greater than the swap strike price. We may employ contractual arrangements other than costless collars and fixed-price swap contracts in the future to mitigate the impact of price fluctuations. If commodity prices decline in the future, our hedging contracts will partiallymitigate the effect of lower prices on our future revenue.Our open oil and natural gas derivative contracts as of December 31, 2015 are detailed in Note 5 – Derivatives and Financial Instruments to ourconsolidated financial statements included elsewhere in this Annual Report. Our credit facility agreement limits the extent to which we can hedge our futureproduction. Under the terms of our credit facility agreement, we are able to hedge estimated production from our proved developed producing reserves basedon our most recently completed reserve report provided to our lenders. We do not enter into derivative instruments for speculative purposes. Includingderivative contracts entered into subsequent to December 31, 2015, we have hedged 91.7%, and 44.2% of our estimated oil and condensate production and92.5%, and 46.5% of our estimated natural gas production from our proved developed producing reserves for 2016 and 2017, respectively.Non-GAAP Financial MeasuresEBITDA, Adjusted EBITDA, and cash available for distribution are supplemental non-GAAP financial measures used by our management and externalusers of our financial statements such as investors, research analysts, and others, to assess the financial performance of our assets and our ability to sustaindistributions 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 derivative instruments, andnon-cash equity-based compensation. We define cash available for distribution as Adjusted EBITDA plus or minus amounts for certain non-cash operatingactivities, borrowings for capital expenditures, 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 GAAPas measures of our financial performance. EBITDA, Adjusted EBITDA, and cash available for distribution have important limitations as analytical toolsbecause they exclude some but not all items that affect net income (loss), the most directly comparable GAAP financial measure. Our computation ofEBITDA, Adjusted EBITDA, and cash available for distribution may differ from computations of similarly titled measures of other companies. 54 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. Year Ended December 31, 2015 2014 2013 (In thousands) Net income (loss) $(101,305) $169,187 $168,963 Adjustments to reconcile to Adjusted EBITDA: Add: Depreciation, depletion and amortization 104,298 111,962 102,442 Interest expense 6,418 13,509 11,342 EBITDA 9,411 294,658 282,747 Add: Impairment of oil and natural gas properties 249,569 117,930 57,109 Accretion of asset retirement obligations 1,075 1,060 588 Equity-based compensation 18,000 11,340 6,782 Unrealized loss on commodity derivative instruments — — 7,350 Less: Unrealized gain on commodity derivative instruments (27,063) (39,283) — Adjusted EBITDA 250,992 385,705 354,576 Adjustments to reconcile to cash generated from operations: Add: Borrowings/cash used to fund additions to and acquisitions of oiland natural gas properties 116,522 119,753 195,212 Restructuring charges 4,208 — — Incremental general and administrative related to initial publicoffering 1,303 — — Loss on sales of assets, net — 32 — Less: Deferred revenue (660) (2,589) — Cash interest expense (5,483) (12,544) (10,374)Gain on sales of assets, net (4,873) — (18)Additions to oil and natural gas properties (54,244) (74,201) (73,650)Acquisitions of oil and natural gas properties (62,278) (45,552) (121,562)Cash generated from operations 245,487 370,604 344,184 Less: Cash paid to noncontrolling interests (208) (307) (767)Redeemable preferred unit distributions (11,562) (15,720) (15,742)Cash generated from operations available for distribution on common and subordinated units and reinvestment in our business $233,717 $354,577 $327,675 Factors Affecting the Comparability of Our Financial ResultsOur financial condition and results of operations for the periods presented may not be comparable, either from period to period or going forward,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; 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.55 Results of OperationsYear 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 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 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 $548,321 Realized prices: Oil and condensate ($/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 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%Per Boe: Lease operating expense $2.06 $2.11 $(0.05) (2.4%)Production costs and ad valorem taxes 3.42 4.93 (1.51) (30.6%)Depreciation, depletion, and amortization 9.97 11.14 (1.17) (10.5%)General and administrative 7.38 6.24 1.14 18.3% 1As a mineral-and-royalty-interest owner, we are often provided insufficient and inconsistent data by our operators. As a result, we are unable to reliablydetermine the total volumes of NGLs associated with the production of natural gas on our acreage. As such, the realized prices account for all salesattributable to NGLs. The oil and condensate production volumes and natural gas production volumes do not include NGL volumes.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. Mineral-and-royalty-56 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 the Wolfcamp, the Eagle Ford Shale, 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 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 increased slightly for theyear ended December 31, 2015 as compared to 2014, primarily due to higher oil and condensate production.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, 2015, production and ad valorem taxes decreased over the year ended December 31, 2014,generally as a result of lower realized commodity prices and estimated mineral reserve valuations.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 year ended December 31, 2015 increased from the yearended December 31, 2014, primarily due to costs incurred to acquire 3-D seismic information related to our mineral and royalty interests from a third-partyservice 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 decreased for the yearended December 31, 2015 as compared to 2014, 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 for the years ended December 31,2015 and 2014 primarily resulted from changes in reserve values due to declines in future expected realized net cash flows as a result of lower commodityprices.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, 2015, generaland administrative expenses increased compared to 2014. In 2015, personnel costs and costs attributable to our long-term incentive plans were $12.3 millionhigher primarily due to an increase in incentive compensation awards granted subsequent to our IPO and certain restructuring costs. We also incurred anadditional $2.5 million for our Sarbanes-Oxley Act compliance project 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.57 Year Ended December 31, 2014 Compared to Year Ended December 31, 2013The following table shows our production, revenues, and expenses for the periods presented: Year Ended December 31, 2014 2013 Variance (Dollars in thousands, except for realized prices and per BOE data) Production: Oil and condensate (MBbls)1 3,005 2,626 379 14.4%Natural gas (MMcf)1 42,273 45,400 (3,127) (6.9%)Equivalents (MBoe) 10,051 10,193 Revenue: Oil and condensate sales $257,390 $252,742 $4,648 1.8%Natural gas and natural gas liquids sales 207,456 184,868 22,588 12.2%Gain (loss) on commodity derivative instruments 37,336 (5,860) 43,196 NM Lease bonus and other income 46,139 31,809 14,330 45.1%Total revenue $548,321 $463,559 Realized prices: Oil and condensate ($/Bbl) $85.65 $96.25 $(10.60) (11.0%)Natural gas ($/Mcf)1 $4.91 $4.07 $0.84 20.6%Equivalents ($/Boe) $46.25 $42.93 Operating expenses: Lease operating expense $21,233 $21,142 $91 0.4%Production costs and ad valorem taxes 49,575 42,813 6,762 15.8%Exploration expense 631 174 457 262.6%Depreciation, depletion, and amortization 111,962 102,442 9,520 9.3%Impairment of oil and natural gas properties 117,930 57,109 60,821 106.5%General and administrative 62,765 59,501 3,264 5.5%Per Boe: Lease operating expense $2.11 $2.07 $0.04 1.9%Production costs and ad valorem taxes 4.93 4.20 0.73 17.4%Depreciation, depletion, and amortization 11.14 10.05 1.09 10.8%General and administrative 6.24 5.84 0.40 6.8% 1As a mineral-and-royalty-interest owner, we are often provided insufficient and inconsistent data by our operators. As a result, we are unable to reliablydetermine the total volumes of NGLs associated with the production of natural gas on our acreage. As such, the realized prices account for all salesattributable to NGLs. The oil and condensate production volumes and natural gas production volumes do not include NGL volumes.RevenuesTotal revenue. The increase in total revenues for the year ended December 31, 2014 compared to the year ended December 31, 2013 was made up of$43.2 million from commodity derivative instruments, $23.8 million resulting from higher production volumes, $14.3 million from higher lease bonus, and$3.4 million from higher realized commodity prices.Oil and condensate sales. Oil and condensate sales during the period were higher than the corresponding period in 2013 primarily due to an increasein production volumes. Our mineral-and-royalty-interest oil volumes accounted for 74.7% and 73.7% of total oil and condensate volumes for the year endedDecember 31, 2014 and the year ended December 31, 2013, respectively. The 16.1% increase in mineral-and-royalty-interest oil volumes, in 2014 relative to2013 was driven primarily by production increases from new wells in the Eagle Ford Shale. Our working-interest oil volumes increased by 9.8% during 2014versus 2013 primarily due to volumes added from new wells in the Bakken/Three Forks plays. The decrease in realized oil prices partially offset the impacton revenues from the increase in oil and condensate production.Natural gas and natural gas liquids sales. An increase in the realized natural gas price for the twelve months of 2014 versus the same period in 2013was responsible for the growth in our natural gas revenues. The favorable price variance was partially offset by a decrease in produced volumes. As weexpected, natural gas production declined from period to period. The decline in both mineral-and-royalty-interest and working-interest volumes wasprimarily driven by the run-off in production in the Hayneville/Bossier Shale58 plays. In 2008 and 2009, we entered into lease agreements which covered the majority of our Hayneville/Bossier Shale acreage in Louisiana and Texas. Asoperators drilled wells to hold acreage, our natural gas production increased significantly in the plays, with volumes peaking in 2012. With most acreage nowheld by production, many operators have moved drilling rigs out of the plays. Although these wells initially produce at high rates, they tend to declinerapidly. Without consistent drilling activity to replace the high decline rates of the individual wells, the overall production rate from the plays has declined.While operators have recently begun to increase the drilling activity on our acreage, production from these new wells has not yet reached the point ofoffsetting declines in existing wells. Mineral-and-royalty-interest production made up 67.8% and 62.7% of our natural gas volumes for the period endingDecember 31, 2014 and 2013, respectively. Gain (loss) on commodity derivative instruments. In 2014, global oil inventories increased to the largest level since 2008. Supply and demandimbalances caused oil prices to decline sharply during the latter half of the year. In addition, robust domestic natural gas production coupled with a warmerthan normal winter contributed to lower than average natural gas storage withdrawals. Natural gas prices reflected the abundant supplies. We used derivativeinstruments to mitigate the risk and resulting impact of such volatility. In 2014, we recognized $27.5 million of combined gains from oil commoditycontracts, virtually all of which were unrealized, compared to $3.5 million of combined losses in 2013. In 2014, we recognized $9.8 million of net gains fromnatural gas commodity contracts, of which $11.8 million were unrealized, compared to $2.4 million of net losses in 2013.Lease bonus and other income. The increase in lease bonus and other income for the year ended December 31, 2014 as compared to the same period in2013 was primarily due to the successful closing of several significant leases in the Canyon Lime and Canyon Wash plays in north Texas and the PermianBasin during 2014.Operating Expenses Lease operating expense. Lease operating expense was substantially consistent between periods.Production costs and ad valorem taxes. For the year ended December 31, 2014, production and ad valorem taxes increased over the year endedDecember 31, 2013 as a result of higher oil and natural gas sales.Exploration expense. Exploration expense for the year ended December 31, 2014 increased from the same period in 2013 due to costs related to a dryhole that was drilled during 2014.Depreciation, depletion, and amortization. Depreciation, depletion, and amortization increased primarily due to an increase in our overall averagedepletion rate by field. The average depletion rate increased because of downward reserve revisions, which resulted from adjustments to estimates made byNSAI for projected lease operating expenses and natural gas shrinkage. In addition, during the second half of 2014, we experienced higher depletion expensefor certain working-interest wells due to rapidly declining reservoir characteristics. Lower natural gas production volumes served to partially mitigate thisincrease in depletion rates.Impairment of oil and natural gas properties. Impairments totaled $117.9 million for the year ended December 31, 2014 primarily due to changes inreserve values resulting from the drop in commodity prices and other factors. Impairments totaled $57.1 million for the year ended December 31, 2013primarily due to the impact that changes in price had on the value of our reserve estimates.General and administrative. For the year ended December 31, 2014, general and administrative expenses increased as compared to 2013 primarilydue to higher personnel costs and costs attributable to our long-term incentive plans. While our overall general and administrative expenses increased for2014, our 2014 legal and broker fees were lower due to nonrecurring costs incurred to consummate our 2013 exchange offer and a one-time acquisition-related broker fee payment incurred in the prior period.Interest expense. Interest expense increased due to additional borrowings under our credit facility. Outstanding borrowings during 2014 were higherthan 2013, primarily due to increased expenditures for acquisitions, drilling activity, and common equity repurchases during 2013.Liquidity and Capital ResourcesOverviewOur primary sources of liquidity are cash generated from operations, borrowings under our credit facility, and proceeds from any future issuances ofequity and debt. Our primary uses of cash are for distributions to our unitholders and for investing in our59 business, specifically the acquisition of mineral-and-royalty and working interests and 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 the required distributions to the holders of our outstanding preferred units.However, we do not have a legal or contractual obligation to pay distributions quarterly or on any other basis, at the applicable minimum quarterlydistribution rate or at any other rate, and there is no guarantee that we will pay distributions to our unitholders in any quarter. Our minimum quarterlydistribution provides the common unitholders a specified priority right to distributions over the subordinated unitholders. The board of directors of ourgeneral partner may change the foregoing distribution policy at any time and from 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. We have set our distributionrate at a level we believe will allow us to retain in our business sufficient cash generated from our operations to satisfy our replacement capital expendituresneeds and to fund a portion of our growth capital expenditures. The board of directors of our general partner is responsible for establishing the amount of ourestimated replacement capital expenditures.Cash FlowsThe following table shows our cash flows for the periods presented: Year Ended December 31, 2015 2014 2013 (In thousands) Cash flows provided by operating activities $284,735 $396,125 $320,764 Cash flows used in investing activities (90,998) (101,110) (195,631)Cash flows used in financing activities (195,307) (310,335) (142,311) Year Ended December 31, 2015 Compared to Year Ended December 31, 2014Operating 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, 2015, cash flows from operating activities decreased by $111.4 million. This decrease was primarilydue 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 millionin higher cash collections related to the settlement of commodity derivative instruments partially offset the decrease resulting from lower oil and natural gassales 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.Year Ended December 31, 2014 Compared to Year Ended December 31, 2013Operating Activities. For the year ended December 31, 2014, cash flows from operating activities increased by $75.4 million as compared to the sameperiod in 2013 due to increased realized natural gas prices, higher oil and condensate volumes, and higher lease bonus revenue.Investing Activities. The net cash used in investing activities decreased by $94.5 million in 2014 as compared to 2013 primarily due to reducedcapital spent on acquisitions and lower capital expenditures under our working-interest participation program. For the60 year ended December 31, 2014, our cash expenditures for acquisitions totaled $45.6 million versus $121.6 million for the same period in 2013. Capitalexpenditures for our working interests, net of sale proceeds, decreased by $13.4 million for the year ended December 31, 2014 versus the comparable periodof 2013. Financing Activities. For the year ended December 31, 2014, the net cash used in financing activities increased $168.0 million compared to the sameperiod in 2013. During 2014, we made distributions to unitholders of $224.9 million, distributions on redeemable preferred units of $15.7 million, $57.0million of credit facility repayments, and equity repurchases of $5.2 million, and we paid $7.6 million of consulting and other costs directly related to ourinitial public offering. During 2013, we received $191.6 million in equity contributions as a result of our exchange offer and borrowed $134.0 million underour credit facility. These activities were partially offset by distributions to unitholders of $225.7 million, distributions on redeemable preferred units of $15.7million, equity repurchases of $118.1 million, repayments under our credit facility of $46.1 million, and purchases of noncontrolling interests of $60.7million. Please read the notes to the consolidated financial statements included elsewhere in this Annual Report for additional information regarding ourexchange and equity offerings.Capital ExpendituresAt the beginning of each calendar year, we establish a capital budget and then monitor it throughout the year. Our capital budgets are 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 internally generated cash, actual wells proposed by our operators for our participation, and the successful closing of acquisitions. The timing,size, and nature of acquisitions are unpredictable.During 2015, we spent approximately $63.2 million on eight acquisitions. We also incurred approximately $60.1 million related to drilling andcompletion costs, the majority of which was in the Haynesville/Bossier, Bakken/Three Forks, and Wilcox plays. Our 2016 capital budget for drillingexpenditures is approximately $60.0 million. Approximately 95% of our drilling capital budget will be spent in the Haynesville/Bossier and Bakken/ThreeForks plays, respectively, with the remainder spent in various plays including the Wolfcamp and Wilcox plays.During 2014, we spent $45.6 million on three cash acquisitions and completed another acquisition for $2.3 million with an issuance of equitysecurities. In 2014, we spent approximately $67.7 million on drilling and completion costs.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 or 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 semi-annual borrowing baseredetermination process resulted in a decrease of the borrowing base from $600.0 million to $550.0 million, effective October 28, 2015. Our next borrowingbase redetermination is scheduled for April 2016. As of December 31, 2015, we had outstanding borrowings of $66.0 million at a weighted-average interestrate of 1.92%. We used net proceeds from our IPO in May 2015 to repay substantially all indebtedness then outstanding under our third amended and restatedcredit facility.The borrowing base under the third amended and restated credit agreement is redetermined semi-annually, on April 1 and October 1 of each year, bythe 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 once in between scheduled redeterminations, to have the borrowing base redetermined.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 0.5%, or 1-month LIBOR plus 1.0%) or LIBOR, in each case plus theapplicable margin. The applicable margin ranges from 0.50% to 1.50% in the case of the alternative base rate and from 1.50% to 2.50% in the case of LIBOR,in each case depending on the amount of borrowings outstanding in relation to the borrowing base. We are obligated to pay a quarterly commitment feeranging from 0.375% to 0.500% per year on the unused portion of the borrowing base, depending on the amount of the borrowings outstanding in relation tothe borrowing base. Principal may be optionally repaid from time to time without premium or penalty, other than customary LIBOR breakage, and is requiredto be paid (a) if the amount outstanding exceeds the borrowing base, whether due to a borrowing base redetermination or otherwise, in some cases subject to acure period or (b) at the maturity date. The third amended and restated credit facility is secured by liens on substantially all of our properties.61 The 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. Distributions are notpermitted if there is a default under the third amended and restated credit agreement (including due to a failure to satisfy one of the financial covenants) orduring any time that our borrowing base is lower than the loans outstanding under the third amended and restated credit facility. The lenders have the right toaccelerate all of the indebtedness under the third amended and restated credit facility upon the occurrence and during the continuance of any event ofdefault, and the third amended and restated credit agreement contains customary events of default, including non-payment, breach of covenants, materiallyincorrect representations, cross-default, bankruptcy, and change of control. There are no cure periods for events of default due to non-payment of principaland breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cureperiods. As of December 31, 2015, we were in compliance with all debt covenants.Contractual ObligationsThe following table summarizes our minimum payments as of December 31, 2015 (in thousands): Payments due by period Total Less Than 1Year 1-3 Years 3-5 Years More Than 5Years Credit facility$66,000 $— $— $66,000 $— Operating lease obligations 4,751 1,416 3,334 1 — Purchase commitments 602 557 45 — — Total$71,353 $1,973 $3,379 $66,001 $— Off-Balance Sheet ArrangementsAt December 31, 2015, 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 havebeen prepared 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 economic conditions, operating methods, and governmentregulations. A sustained low price environment could decrease our estimate of proved reserves, which would increase the rate at which we record depletionexpense and reduce net income. Additionally, a decline in proved reserve estimates may impact the outcome of our assessment of producing properties forimpairment. We are unable to predict future commodity prices with any greater precision than the futures market. The impact of commodity prices can beillustrated as follows. If we assumed the average 12-month forward strip pricing as of December 31, 2015 was held constant in determining our reserves, ourestimated proved reserves on a Boe basis as of December 31, 2015 would have declined by approximately 2%.62 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 content of natural gas, and prevailing supply and demand conditions, so that the price of natural gas fluctuates to remaincompetitive with other available natural gas supplies. 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 further63 obligation 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 18 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.New and Revised Financial Accounting StandardsThe effects of new accounting pronouncements are discussed in Note 2 – Summary of Significant Accounting Policies within the consolidatedfinancial statements included elsewhere in this Annual Report. Item 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 primarilydriven by the prevailing worldwide price for oil and U.S. spot market prices for natural gas and natural gas64 liquids. Prices for oil, natural gas, and natural gas liquids are volatile, and we expect this unpredictability to continue in the future. The prices that ouroperators receive for production depend on many factors outside 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 to reduce our exposure toprice risk in the spot market for oil and natural gas. The counterparties to the contracts are unrelated third parties. The contracts settle monthly in cash basedon a designated index price. The designated index price has been based off the NYMEX benchmark for oil and natural gas. We have not designated any ofour 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 the change.An average increase in the commodity price of $10.00 per barrel of oil and $1.00 per MMBtu of natural gas from the commodity prices at December 31, 2015would have resulted in a decrease in the fair value of our commodity derivative assets of approximately $18.5 million. A decrease in the average forward NYMEX oil and natural gas prices below those at December 31, 2015 would increase the fair value of ourcommodity derivative assets from their recorded balance at December 31, 2015. Changes in the recorded fair value of our commodity derivative instrumentsare marked to market through earnings as gains or losses. The potential increase in our commodity derivative assets would be recorded in earnings as again. However, an increase in the average forward NYMEX oil and natural gas prices above those at December 31, 2015, would decrease the fair value of ourcommodity derivative assets from their recorded balance at December 31, 2015. The potential decrease would be recorded in earnings as a loss. We are unableto estimate the effects on future-period earnings resulting from changes in the market value of our commodity derivative instruments. See Note 5 –Derivatives and Financial Instruments and Note 6 – Fair Value Measurement within the consolidated financial statements included elsewhere in this AnnualReport for additional information.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, 2015, we had ten counterparties, all of which are rated Baa2 or better byMoody’s. Seven of our counterparties are lenders under our credit facility.Our principal exposure to credit risk results from receivables generated by the production activities of our operators. The inability or failure of oursignificant operators to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. However, we believe thecredit risk associated with our operators and customers is acceptable.Interest Rate RiskWe have exposure to changes in interest rates on our indebtedness. As of December 31, 2015, we had $66.0 million of outstanding borrowings underour credit facility, bearing interest at a weighted-average interest rate of 1.92%. 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 $0.7 million for the year ended December 31,2015, 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. ITEM 9A. CONTROLS AND PROCEDURESEvaluation of Disclosure Controls and ProceduresAs required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of management of ourgeneral partner, including our general partner’s principal executive officer and principal financial officer, the effectiveness of the design and operation of ourdisclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under65 the Exchange Act) as of the end of the period covered by this Annual Report. Our disclosure controls and procedures are designed to provide reasonableassurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated tomanagement, including our general partner’s principal executive officer and principal financial officer, as appropriate, to allow timely decisions regardingrequired disclosure and is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the SEC. Based upon thatevaluation, our general partner’s principal executive officer and principal financial officer concluded that our disclosure controls and procedures wereeffective as of December 31, 2015. Management’s Annual Report on Internal Control over Financial ReportingThis Annual Report does not include a report of management’s assessment regarding internal control over financial reporting due to a transitionperiod established by the rules of the SEC for newly public companies.Attestation Report of the Independent Registered Public Accounting FirmThis Annual Report does not include an attestation report of our independent registered public accounting firm due to a transition period establishedby the rules of the SEC for newly public companies. Further, our independent registered public accounting firm will not be required to formally attest to theeffectiveness of our internal control over financial reporting for as long as we are an “emerging growth company” pursuant to the provisions of the JOBS Act.Changes in Internal Control over Financial ReportingThere were no changes in our internal control over financial reporting during the quarter ended December 31, 2015 that materially affected, or arereasonably likely to materially affect, our internal control over financial reporting. ITEM 9B. OTHER INFORMATIONNone. 66 PART III ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCEInformation required by this item is incorporated by reference to the material appearing in our Proxy Statement for the 2016 Annual Meeting ofLimited Partners (“2016 Proxy Statement”), which will be filed with the SEC not later than 120 days after December 31, 2015.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 thatapplies to our Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer and the other senior financial officers, each as required by SEC andNYSE rules. Each of the foregoing is available on our website at www.blackstoneminerals.com in the “Corporate Governance” section. We will providecopies, free of charge, of any of the foregoing upon receipt of a written request to Black Stone Minerals, L.P., 1001 Fannin Street, Suite 2020, Houston, Texas77002, 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 2016 Proxy Statement, which will be filed with the SEC not later than 120 daysafter December 31, 2015. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERSInformation required by this item is incorporated by reference to the 2016 Proxy Statement, which will be filed with the SEC not later than 120 daysafter December 31, 2015. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCEInformation required by this item is incorporated by reference to the 2016 Proxy Statement, which will be filed with the SEC not later than 120 daysafter December 31, 2015. ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICESInformation required by this item is incorporated by reference to the 2016 Proxy Statement, which will be filed with the SEC not later than 120 daysafter December 31, 2015. 67 PART IV ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES(a)(1) Financial StatementsOur Consolidated Financial Statements are included under Part II, Item 8 of this Annual Report. For a listing of these statements and accompanyingnotes, please read “Index to Financial Statements” on page F-1 of this Annual Report.(a)(2) Financial Statement SchedulesAll schedules have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidatedfinancial statements or notes thereto.68 (a)(3) ExhibitsThe following documents are filed as a part of this Annual Report or incorporated by reference: ExhibitNumber 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 amongBlack Stone Minerals GP, L.L.C. and Black Stone Minerals Company, L.P. (incorporated herein by reference to Exhibit 3.1 ofBlack Stone Minerals, L.P.’s Current Report on Form 8-K filed on May 6, 2015 (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. (incorporatedherein by reference 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, Bank of America, N.A. andCompass Bank, as Co-Syndication Agents, Wells Fargo Bank, N.A. and Amegy Bank National Association, as Co-DocumentationAgents, and a syndicate of lenders (incorporated herein by reference to Exhibit 10.1 of Black Stone Minerals, L.P.’s CurrentReport on Form 8-K filed on October 28, 2015 (SEC File No. 001-37362)). 10.3 Third Amended and Restated Credit Agreement among Black Stone Minerals Company, L.P., as Borrower, Wells Fargo Bank,National Association, as Administrative Agent, Bank of America, N.A. and Compass Bank, as Co-Syndication Agents, WellsFargo Bank, N.A. and Amegy Bank National Association, as Co-Documentation Agents, and a syndicate of lenders dated as ofJanuary 23, 2015 (incorporated herein by reference to Exhibit 10.2 to Black Stone Minerals, L.P.’s Registration Statement onForm S-1 filed on March 19, 2015 (SEC File No. 333-202875)). 10.4^ 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 filedon March 19, 2015 (SEC File No. 333-202875)). 10.5^ First Amendment to Employment Agreement by and between Black Stone Minerals Company, L.P. and Thomas L. Carter, Jr.effective as of June 25, 2014 (incorporated herein by reference to Exhibit 10.4 to Black Stone Minerals, L.P.’s RegistrationStatement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)). 10.6^ Black Stone Minerals Company, L.P. 2012 Executive Incentive Plan (incorporated herein by reference to Exhibit 10.5 to BlackStone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)). 10.7^ Restricted Unit Award Agreement by and between Black Stone Minerals Company, L.P. and Thomas L. Carter, Jr. effective as ofJanuary 1, 2012 (incorporated herein by reference to Exhibit 10.6 to Black Stone Minerals, L.P.’s Registration Statement on FormS-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 Marc Carroll effective as of January1, 2012 (incorporated herein by reference to Exhibit 10.7 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1filed on March 19, 2015 (SEC File No. 333-202875)). 10.9^ Restricted Unit Award Agreement by and between Black Stone Minerals Company, L.P. and Holbrook F. Dorn effective as ofJanuary 1, 2012 (incorporated herein by reference to Exhibit 10.8 to Black Stone Minerals, L.P.’s Registration Statement on FormS-1 filed on March 19, 2015 (SEC File No. 333-202875)).69 ExhibitNumber Description 10.10^ Form of IPO Award Grant Notice and Award Agreement for Senior Management (Restricted Units) (incorporated herein byreference to Exhibit 10.9 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on April 13, 2015 (SEC FileNo. 333-202875)). 10.11^ Form of IPO Award Grant Notice and Award Agreement for Senior Management (Performance Units) (incorporated herein byreference to Exhibit 10.10 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on April 13, 2015 (SEC FileNo. 333-202875)). 10.12^ Form of Non-Employee Director Unit Grant Notice and Award Agreement (incorporated herein by reference to Exhibit 10.11 toBlack 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 Severance Agreement for Thomas L. Carter, Jr. (incorporated herein by reference to Exhibit 10.12 to Black StoneMinerals, 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 Senior Vice Presidents (incorporated herein by reference to Exhibit 10.13 to Black StoneMinerals, L.P.’s Registration Statement on Form S-1 filed on April 13, 2015 (SEC File No. 333-202875)). 10.15^ Form of STI Award Grant Notice and STI Award Agreement (Leadership) under the Black Stone Minerals, L.P. Long-TermIncentive Plan (incorporated herein by reference to Exhibit 10.1 to Black Stone Minerals, L.P.’s Current Report on Form 8-K filedon February 2, 2016 (SEC File No. 001-37362). 10.16^ Form of LTI Award Grant Notice and LTI Award Agreement (Leadership) under the Black Stone Minerals, L.P. Long-TermIncentive Plan (incorporated herein by reference to Exhibit 10.2 to Black Stone Minerals, L.P.’s Current Report on Form 8-K filedon February 2, 2016 (SEC File No. 001-37362). 21.1* List of Subsidiaries of Black Stone Minerals, L.P. 23.1* Consent of BDO USA, LLP 23.2* Consent of UHY 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, as adopted 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. 70 SIGNATURESPursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned,thereunto duly authorized. BLACK STONE MINERALS, L.P. By: Black Stone Minerals GP, L.L.C.,its general partner Date: March 8, 2016 By: /s/ Thomas L. Carter, Jr. Thomas L. Carter, Jr. President, Chief Executive Officer, and Chairman Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report has been signed below by the following persons on behalf of theregistrant and in the capacities and on the dates indicated. Signature Title Date /s/ Thomas L. Carter, Jr. President, Chief Executive Officer, and Chairman March 8, 2016Thomas L. Carter, Jr. (Principal Executive Officer) /s/ Marc Carroll Senior Vice President and Chief Financial Officer March 8, 2016Marc Carroll (Principal Financial Officer) /s/ Dawn K. Smajstrla Vice President and Chief Accounting Officer March 8, 2016Dawn K. Smajstrla (Principal Accounting Officer) /s/ William G. Bardel Director March 8, 2016William G. Bardel /s/ Carin M. Barth Director March 8, 2016Carin M. Barth /s/ D. Mark DeWalch Director March 8, 2016D. Mark DeWalch /s/ Ricky J. Haeflinger Director March 8, 2016Ricky J. Haeflinger /s/ Jerry V. Kyle, Jr. Director March 8, 2016Jerry V. Kyle, Jr. /s/ Michael C. Linn Director March 8, 2016Michael C. Linn /s/ John H. Longmaid Director March 8, 2016John H. Longmaid /s/ William N. Mathis Director March 8, 2016William N. Mathis /s/ Robert E. W. Sinclair Director March 8, 2016Robert E. W. Sinclair /s/ Alexander D. Stuart Director March 8, 2016Alexander D. Stuart /s/ Alison K. Thacker Director March 8, 2016Alison K. Thacker 71 INDEX TO CONSOLIDATED FINANCIAL STATEMENTSBLACK STONE MINERALS, L.P. Reports of Independent Registered Public Accounting Firms F-2 Consolidated Balance Sheets as of December 31, 2015 and December 31, 2014 F-4 Consolidated Statements of Operations for the Years Ended December 31, 2015, 2014 and 2013 F-5 Consolidated Statements of Equity for the Years Ended December 31, 2015, 2014, and 2013 F-6 Consolidated Statements of Cash Flows for the Years Ended December 31, 2015, 2014 and 2013 F-7 Notes to Consolidated Financial Statements F-8 F-1 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMThe Partners ofBlack Stone Minerals, L.P.Houston, TexasWe have audited the accompanying consolidated balance sheets of Black Stone Minerals, L.P. and subsidiaries (the “Partnership”) as of December 31, 2015and 2014, and the related consolidated statements of operations, equity, and cash flows for the years then ended. These consolidated financial statements arethe responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements based on ouraudits.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 suchopinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements,assessing the accounting 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 2014, and the results of its operations and its cash flows for the years then ended, in conformity withaccounting principles generally accepted in the United States of America./s/ BDO USA, LLPHouston, TexasMarch 8, 2016 F-2 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMThe General Partner ofBlack Stone Minerals, L.P.Houston, TexasWe have audited the accompanying consolidated statements of operations, equity, and cash flows of Black Stone Minerals Company, L.P. and subsidiaries(the “Company”), the predecessor to Black Stone Minerals, L.P., for the year ended December 31, 2013. These consolidated financial statements are theresponsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require thatwe plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. TheCompany is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included considerationof internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose ofexpressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An auditalso includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, assessing the accountingprinciples used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believethat our audit provides a reasonable basis for our opinion.In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the results of the Company’s operations and itscash flows for the year ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America./s/ UHY LLPHouston, TexasOctober 7, 2014 F-3 BLACK STONE MINERALS, L.P. AND SUBSIDIARIESCONSOLIDATED BALANCE SHEETS(in thousands) As of December 31, 2015 2014 ASSETS CURRENT ASSETS Cash and cash equivalents $13,233 $14,803 Accounts receivable 41,246 74,092 Commodity derivative assets 48,260 37,471 Prepaid expenses and other current assets 856 8,538 TOTAL CURRENT ASSETS 103,595 134,904 PROPERTY AND EQUIPMENT Oil and natural gas properties, at cost, using the successful efforts method of accounting, includesunproved properties of $524,563 and $626,376 at December 31, 2015 and 2014, respectively 2,482,211 2,379,543 Accumulated depreciation, depletion, amortization, and impairment (1,543,796) (1,191,861)Oil and natural gas properties, net 938,415 1,187,682 Other property and equipment, net of accumulated depreciation of $14,660 and $12,994 at December31, 2015 and 2014, respectively 179 1,664 NET PROPERTY AND EQUIPMENT 938,594 1,189,346 DEFERRED CHARGES AND OTHER LONG-TERM ASSETS 19,247 2,532 TOTAL ASSETS $1,061,436 $1,326,782 LIABILITIES, MEZZANINE EQUITY AND EQUITY CURRENT LIABILITIES Accounts payable $5,036 $5,434 Accrued liabilities 58,003 40,233 Accrued distribution payable to Predecessor unitholders — 52,905 TOTAL CURRENT LIABILITIES 63,039 98,572 LONG-TERM LIABILITIES Credit facility 66,000 394,000 Accrued incentive compensation 7,902 6,530 Deferred revenue 3,257 3,917 Asset retirement obligations 10,585 9,381 TOTAL LIABILITIES 150,783 512,400 COMMITMENTS AND CONTINGENCIES (Note 12) MEZZANINE EQUITY Partners' equity - redeemable preferred units, 77 and 157 units outstanding at December 31, 2015 and2014, respectively 79,162 161,165 EQUITY Predecessor equity - common limited partner units, no units and 164,484 units outstanding atDecember 31, 2015 and 2014, respectively — 653,217 Partners' equity - general partner interest — — Partners' equity - common units, 96,162 and no units outstanding at December 31, 2015 and 2014,respectively 574,648 — Partners' equity - subordinated units, 95,057 and no units outstanding at December 31, 2015 and2014, respectively 255,699 — Noncontrolling interests 1,144 — TOTAL EQUITY 831,491 653,217 TOTAL LIABILITIES, MEZZANINE EQUITY AND EQUITY $1,061,436 $1,326,782 The accompanying notes to consolidated financial statements are an integral part of these financial statements. F-4 BLACK STONE MINERALS, L.P. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF OPERATIONS(in thousands, except per unit amounts) Year Ended December 31, 2015 2014 2013 REVENUE Oil and condensate sales$163,538 $257,390 $252,742 Natural gas and natural gas liquids sales 116,018 207,456 184,868 Gain (loss) on commodity derivative instruments 90,288 37,336 (5,860)Lease bonus and other income 23,080 46,139 31,809 TOTAL REVENUE 392,924 548,321 463,559 OPERATING (INCOME) EXPENSE Lease operating expense 21,583 21,233 21,142 Production costs and ad valorem taxes 35,767 49,575 42,813 Exploration expense 2,592 631 174 Depreciation, depletion and amortization 104,298 111,962 102,442 Impairment of oil and natural gas properties 249,569 117,930 57,109 General and administrative 77,175 62,765 59,501 Accretion of asset retirement obligations 1,075 1,060 588 (Gain) loss on sale of assets, net (4,873) 32 (18)Other expense 1,593 1,424 — TOTAL OPERATING EXPENSE 488,779 366,612 283,751 INCOME (LOSS) FROM OPERATIONS (95,855) 181,709 179,808 OTHER INCOME (EXPENSE) Interest and investment income 58 28 90 Interest expense (6,418) (13,509) (11,342)Other income 910 959 407 TOTAL OTHER EXPENSE (5,450) (12,522) (10,845)NET INCOME (LOSS) (101,305) 169,187 168,963 NET INCOME ATTRIBUTABLE TO PREDECESSOR (450) (169,187) (168,963)NET LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS SUBSEQUENT TOINITIAL PUBLIC OFFERING 1,260 — — DISTRIBUTIONS ON REDEEMABLE PREFERRED UNITS SUBSEQUENT TO INITIALPUBLIC OFFERING (7,522) — — NET LOSS ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON ANDSUBORDINATED UNITS SUBSEQUENT TO INITIAL PUBLIC OFFERING$(108,017) $— $— ALLOCATION OF LOSS SUBSEQUENT TO INITIAL PUBLIC OFFERING ATTRIBUTABLETO: General partner interest$— Common units (54,326) Subordinated units (53,691) $(108,017) NET LOSS ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON ANDSUBORDINATED UNIT: Per common unit (basic and diluted)$(0.56) Weighted average common units outstanding (basic and diluted) 96,182 Per subordinated unit (basic and diluted)$(0.56) Weighted average subordinated units outstanding (basic and diluted) 95,057 DISTRIBUTIONS DECLARED AND PAID SUBSEQUENT TO INITIAL PUBLIC OFFERING: Per common unit$0.4240 Per subordinated unit$0.4240 The accompanying notes to consolidated financial statements are an integral part of these financial statements. F-5 BLACK STONE MINERALS, L.P. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF EQUITY(in thousands) Predecessor Black Stone Minerals, L.P. Predecessorunits Partners'equity Commonunits Subordinatedunits Partners'equity—commonunits Partners'equity—subordinatedunits Noncontrollinginterests Totalequity BALANCE AT DECEMBER 31, 2012 93,498 $326,663 — — $— $— $— $326,663 Contributions—cash 18,801 412,233 — — — — — 412,233 Contributions—limited partner interests 46,481 1,019,340 — — — — — 1,019,340 Issuance of Predecessor units for acquisition of oil andnatural gas properties 10,359 227,119 — — — — — 227,119 Repurchase of Predecessor units (5,410) (118,108) — — — — — (118,108)Restricted Predecessor units granted, net of forfeitures 404 — — — — — — — Equity-based compensation — 6,782 — — — — — 6,782 Distributions to Predecessor unitholders and noncontrollinginterests — (235,078) — — — — — (235,078)Distributions—property — (19,029) — — — — — (19,029)Purchases of Predecessor noncontrolling interests — (37,400) — — — — — (37,400)Exchange of Predecessor noncontrolling interests — (1,019,340) — — — — — (1,019,340)Net income attributable to Predecessor — 168,963 — — — — — 168,963 Distributions on Predecessor redeemable preferred units — (15,742) — — — — — (15,742)BALANCE AT DECEMBER 31, 2013 164,133 716,403 — — — — — 716,403 Conversion of Predecessor redeemable preferred units 15 221 — — — — — 221 Issuance of Predecessor units for acquisition of oil andnatural gas properties 104 2,258 — — — — — 2,258 Repurchase of Predecessor units (239) (5,199) — — — — — (5,199)Restricted Predecessor units granted, net of forfeitures 471 — — — — — — — Equity-based compensation — 11,340 — — — — — 11,340 Distributions to Predecessor unitholders and noncontrollinginterests — (225,273) — — — — — (225,273)Net income attributable to Predecessor — 169,187 — — — — — 169,187 Distributions on Predecessor redeemable preferred units — (15,720) — — — — — (15,720)BALANCE AT DECEMBER 31, 2014 164,484 653,217 — — — — — 653,217 Conversion of Predecessor redeemable preferred units 2,750 39,240 — — — — — 39,240 Restricted Predecessor units granted 562 — — — — — — — Repurchases of Predecessor units (164) (3,015) — — — — — (3,015)Distributions to Predecessor unitholders and noncontrollinginterests — (73,205) — — — — — (73,205)Distributions on Predecessor redeemable preferred units — (4,040) — — — — — (4,040)Net income attributable to Predecessor — 450 — — — — — 450 Allocation 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 public offering, net ofoffering costs — — 22,500 — 391,500 — — 391,500 Restricted common units granted, net of forfeitures — — 1,087 — — — — — Equity-based compensation — — — — 14,181 3,819 — 18,000 Distributions — — — — (40,783) (40,304) (133) (81,220)Charges to partners' equity for accrued distributionequivalent 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 $831,491 The accompanying notes to consolidated financial statements are an integral part of these financial statements. F-6 BLACK STONE MINERALS, L.P. AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF CASH FLOWS(in thousands) Year Ended December 31, 2015 2014 2013 CASH FLOWS FROM OPERATING ACTIVITIES Net income (loss) $(101,305) $169,187 $168,963 Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation, depletion, and amortization 104,298 111,962 102,442 Impairment of oil and natural gas properties 249,569 117,930 57,109 Accretion of asset retirement obligations 1,075 1,060 588 Amortization of deferred charges 935 965 968 Gain (loss) on commodity derivative instruments (90,288) (37,336) 5,860 Net cash received (paid) on settlement of commodity derivative instruments 63,225 (1,947) 1,490 Equity-based compensation 18,000 11,340 6,782 (Gain) loss on sale of assets, net (4,873) 32 (18)Changes in operating assets and liabilities: Accounts receivable 33,586 17,210 (15,046)Prepaid expenses and other current assets 95 453 (1,256)Accounts payable and accrued liabilities 11,221 8,003 (7,085)Deferred revenue (660) (2,589) — Settlement of asset retirement obligations (143) (145) (33)NET CASH PROVIDED BY OPERATING ACTIVITIES 284,735 396,125 320,764 CASH FLOWS FROM INVESTING ACTIVITIES Additions to oil and natural gas properties (54,244) (74,201) (73,650)Purchase of other property and equipment (181) (827) (493)Proceeds from the sale of oil and natural gas properties 25,705 19,470 74 Acquisitions of oil and natural gas properties (62,278) (45,552) (121,562)NET CASH USED IN INVESTING ACTIVITIES (90,998) (101,110) (195,631)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) — Net (repayments) borrowings under senior line of credit (328,000) (57,000) 134,000 Distributions to Predecessor unitholders (126,383) (224,926) (225,704)Distributions to Black Stone Minerals, L.P. common and subordinated unitholders (81,087) — — Distributions to preferred unitholders (13,578) (15,724) (15,732)Distributions to noncontrolling interests (208) — — Redemption of redeemable preferred units (40,747) — — Repurchases of Predecessor units (3,015) (5,199) (118,108)Debt issuance costs (1,376) — (1,660)Note receivable-officers — 101 101 Repayments of revolving credit facilities — — (46,100)Contributions from Predecessor unitholders — — 191,611 Purchases of noncontrolling interests — — (60,719)NET CASH USED IN FINANCING ACTIVITIES (195,307) (310,335) (142,311)NET CHANGE IN CASH AND CASH EQUIVALENTS (1,570) (15,320) (17,178)CASH AND CASH EQUIVALENTS - beginning of the year 14,803 30,123 47,301 CASH AND CASH EQUIVALENTS - end of the year $13,233 $14,803 $30,123 SUPPLEMENTAL DISCLOSURE Interest paid $5,478 $12,754 $10,344 NON-CASH ACTIVITIES Accrued Predecessor distributions payable $(53,248) $347 $9,374 Conversion of redeemable preferred units $(39,240) $(221) $— Accrued distributions payable for redeemable preferred units $(2,016) $(4) $10 Property additions and acquisitions financed through accounts payable and accrued liabilities $21,496 $14,130 $23,029 Public offering costs capitalized and offset against proceeds from initial public offering $7,587 $— $— Asset retirement obligations incurred $272 $2,505 $164 Accrued distribution equivalent rights $159 $— $— Liabilities assumed as consideration for oil and natural gas properties acquired $— $7,000 $— Acquisition of oil and natural gas properties financed through issuance of Predecessor units $— $2,258 $227,119 Deferred revenue (settled) assumed through acquisition of oil and natural gas properties $— $(2,657) $902 Contributions through exchange of noncontrolling interests $— $— $1,019,340 Distributions—property $— $— $19,029 The accompanying notes to consolidated financial statements are an integral part of these financial statements. F-7 BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 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.The Partnership’s assets include mineral interests, nonparticipating royalty interests, and overriding royalty interests. These non-cost-bearing interestsare collectively referred to as “mineral and royalty interests.” The Partnership’s mineral and royalty interests are located in most of the major onshore oil andnatural gas producing basins spread across 41 states and 61 onshore oil and natural gas producing basins of the continental U.S. The Partnership also ownsnon-operated working interests in certain oil and natural gas properties.Basis of presentation: The accompanying financial statements of the Partnership have been prepared in accordance with generally acceptedaccounting principles (“GAAP”) in the United States. The financial statements include the consolidated results of the Partnership. All intercompany balancesand transactions have been eliminated.The Partnership evaluates the significant terms of its investments to determine the method of accounting to be applied to each respective investment.Investments in which the Partnership has less than a 20% ownership interest and does not have control or exercise significant influence are accounted forunder the cost method. The Partnership’s cost method investment is included in deferred charges and other long-term assets in the consolidated balancesheets. Investments in which the Partnership exercises control are consolidated, and the noncontrolling interests of such investments, which are notattributable directly or indirectly to the Partnership, are presented as a separate component of net income and equity in the accompanying consolidatedfinancial statements.The consolidated financial statements include undivided interests in oil and natural gas property rights. The Partnership accounts for its share of 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.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.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 operating decision maker allocates resources and assesses performance based upon financial information at theconsolidated level. F-8 BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 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 determined accurately, actual results coulddiffer significantly 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 cashequivalent balances, accounts receivable, and commodity derivative financial instruments. The Partnership maintains cash and cash equivalent balances withmajor financial institutions. At times, those balances exceed federally insured limits; however, no losses have been incurred. The Partnership attempts to limitthe amount of credit exposure to any one company through procedures that include credit approvals, credit limits and terms, and prepayments. ThePartnership’s customer base is made up of its lessees, which are primarily major integrated and international oil and natural gas companies and otheroperators, though the Partnership’s credit risk may extend to the eventual purchasers of oil and natural gas produced from the Partnership’s properties. ThePartnership believes the credit quality of its customer base is high and has not experienced significant write-offs in its accounts receivable balances. See Note8 – Significant Customers for further discussion. Derivative instruments may expose the Partnership to credit risk. However, the Partnership monitors thecreditworthiness of its 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.Prepaid expenses and other current assets: Prepaid expenses and other current assets as of December 31, 2014 included $7.6 million of capitalizedissuance costs, including underwriting, legal, and accounting fees, directly related to the Partnership’s IPO.F-9 BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS Oil 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 $102.7 million,$109.9 million and $100.6 million for the years ended December 31, 2015, 2014, and 2013, 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 field-by-field basis. The Partnership compares the undiscounted projected future cash flowsexpected in connection with a field to the carrying amount to determine recoverability. When the carrying amount of a field exceeds its estimatedundiscounted future cash flows, the carrying amount is written down to its fair value, which is measured as the present value of the projected future cash flowsof such properties. The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, futurecapital expenditures, and a risk-adjusted discount rate.Impairment of proved oil and natural gas properties was $127.8 million, $117.9 million and $57.1 million for the years ended December 31, 2015,2014, and 2013, 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$121.8 million for the year ended December 31, 2015. There was no impairment of unproved properties for the years ended December 31, 2014 and 2013.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 $1.6 million, $2.1 million, and $1.8 million for the years ended December 31, 2015,2014, and 2013, 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 distribution payable to Predecessor unitholders: Accrued distribution payable to Predecessor unitholders consisted of distributions due to thePredecessor’s partners based on the partnership agreement that have not been paid out as of the respective balance sheet dates.F-10 BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS Debt issuance costs: Debt issuance costs consist of costs directly associated with obtaining credit with financial institutions. These costs arecapitalized and are generally 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, $1.0 million, and $1.0 million for the years ended December 31, 2015, 2014, and 2013, 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, 2015 and 2014. 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.Income 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 and, therefore, it is exempt from the Texas margin tax. As a result, each unitholder that is considered a taxableentity under the Texas margin tax would generally be required to include its portion of the Partnership’s revenues in its own Texas margin tax computation.The Texas Administrative Code provides such income is sourced according to the principal place of business of the Partnership, which would be the state ofTexas.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, 2015 and 2014 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 equity-based compensation awards using either straight-line or acceleratedF-11 BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS attribution over the requisite service period (generally the vesting period of the awards) depending on the given terms of the award, based on their grant-datefair values, in general and administrative expense.Liability awards are awards that are expected to be settled in cash on their vesting dates. Liability awards are recorded as accrued liabilities based onthe vested portion of the estimated fair value of the awards as of the grant date, which is subject to revision based on the impact of certain performanceconditions associated with the incentive plans. The Partnership may also recognize liability awards as a result of repurchase options given to the recipientsparticipating 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 as of the earliest period presented, or “modified retrospective” adoption,meaning the standard is applied only to the most current period presented in the financial statements with a cumulative catch-up as of the current period. InJuly 2015, the FASB decided to defer the original effective date by one year to be effective for annual reporting periods beginning after December 15, 2017instead of December 15, 2016 for public entities. The Partnership is still evaluating the impact that the new accounting guidance will have on itsconsolidated financial statements and related disclosures and has not yet determined the method by which it will adopt the standard.In November 2014, the FASB issued an accounting standards update that clarifies how U.S. GAAP should be applied in determining whether thenature of a host contract is more akin to debt or equity and in evaluating whether the economic characteristics and risks of an embedded feature are "clearlyand closely related" to its host contract. The guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15,2015. The Partnership adopted this guidance on January 1, 2016, and there was no material impact to the Partnership’s consolidated financial statements andrelated disclosures.In April 2015, the FASB issued an accounting standards update that requires debt issuance costs related to a recognized debt liability to be presentedin the balance sheet as a direct deduction from the carrying value of that debt liability, consistent with debt discounts. The guidance is effectiveretrospectively for fiscal years, and interim periods within those years, beginning after December 15, 2015. Early adoption is permitted for financialstatements that have not been previously issued. The Partnership does not expect the impact of adopting this guidance will be material to the Partnership’sconsolidated financial statements and related disclosures.In September 2015, the FASB issued an accounting standards update that requires that adjustments to provisional amounts identified during themeasurement period of a business combination be recognized in the reporting period in which those adjustmentsF-12 BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS are determined, including the effect on earnings, if any, calculated as if the accounting had been completed at the acquisition date. This eliminates theprevious requirement to retrospectively account for such adjustments. The new standard also requires additional disclosures related to the income statementeffects of adjustments to provisional amounts identified during the measurement period. The guidance is effective for public companies during interim andannual reporting periods beginning after December 15, 2015. Early adoption is permitted. The Partnership does not expect the impact of adopting thisguidance will be material to the Partnership’s consolidated financial statements and related disclosures. NOTE 3—ASSET RETIREMENT OBLIGATIONSThe ARO liability reflects the present value of estimated costs of dismantlement, removal, site reclamation, and similar activities associated with thePartnership’s oil and natural gas properties. The Partnership utilizes current retirement costs to estimate the expected cash outflows for retirement obligations.The Partnership estimates the ultimate productive life of the properties, a risk-adjusted discount rate, and an inflation factor in order to determine the currentpresent value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a correspondingadjustment 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, 2015 2014 (In thousands) Beginning asset retirement obligations$9,381 $5,961 Liabilities incurred 272 167 Liabilities settled (143) (145)Accretion expense 1,075 1,060 Revisions in estimated costs — 2,338 Ending asset retirement obligations$10,585 $9,381 NOTE 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 historicalcost.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.In 2004, the Predecessor and third-party investors acquired an interest in the producing and non-producing oil and natural gas properties of PurePartners, L.P. and Pure Resources, L.P. (“Pure”). As of December 31, 2012, the Predecessor owned 86.4% of the oil and natural gas properties of Pure. Third-party investors owned the remaining 13.6% of the oil and natural gas properties. Effective January 1, 2013, the Predecessor purchased the remainingownership interest in the Pure oil and natural gas properties through the issuance of $227.1 million of Predecessor units. The fair value of the assets acquiredwas determined based on discounted cash flows, including assumptions as to the estimated ultimate recovery of oil and natural gas reserves, expectations fortiming of futureF-13 BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS development and operating costs, and risk-adjusted discount rates. The following table summarizes the fair values assigned to the assets acquired as ofJanuary 1, 2013: (In thousands) Proved oil and natural gas properties$51,573 Unproved oil and natural gas properties 169,150 Net working capital 6,396 Total net assets acquired$227,119 NOTE 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 given commodity price riskassociated with its operations, the Partnership uses derivative instruments. From time to time, such instruments may include fixed price contracts, variable tofixed price swaps, costless collars, and other contractual arrangements. The Partnership does not enter into derivative instruments for speculative purposes.A fixed-price-swap contract between the Partnership and the counterparty specifies a fixed commodity price and a future settlement date. ThePartnership will receive from, or pay to, the counterparty the difference between the fixed swap price and the market price on the settlement date. Costlesscollars are a combination of a purchased put option and a sold call option, in which the premiums net to zero. With a costless collar, the counterparty isrequired to make a payment to the Partnership if the settlement price for any settlement period is below the exercise price of the purchased put. ThePartnership is required to make a payment to the counterparty if the settlement price for any settlement period is above the exercise price for the sold call ofthe collar. The settlement paid or received is the difference between the market price on the settlement date and the related exercise price. All derivativeinstruments that have not yet been settled in cash are reflected as either derivative assets or liabilities in the Partnership’s accompanying consolidatedbalance sheets as of December 31, 2015 and 2014, respectively. See Note 6 – Fair Value Measurement for further discussion.The table below summarizes the fair value and classification of the Partnership’s derivative instruments: As of December 31, 2015 Classification Balance Sheet Location Gross FairValue Effect ofCounterpartyNetting Net CarryingValue onBalance Sheet (In thousands) Assets: Current asset Commodity derivative assets $48,260 $— $48,260 Long-term asset Deferred charges and otherlong-term assets 16,274 — 16,274 Total assets $64,534 $— $64,534 Liabilities: Current liability Commodity derivative liabilities $— $— $— Long-term liability Commodity derivative liabilities — — — Total liabilities $— $— $—F-14 BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS As of December 31, 2014 Classification Balance Sheet Location Gross FairValue Effect ofCounterpartyNetting Net CarryingValue onBalance Sheet (In thousands) Assets: Current asset Commodity derivative assets $37,656 $(185) $37,471 Long-term asset Deferred charges and otherlong-term assets — — — Total assets $37,656 $(185) $37,471 Liabilities: Current liability Commodity derivative liabilities $185 $(185) $— Long-term liability Commodity derivative liabilities — — — Total liabilities $185 $(185) $— 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: For the year ended December 31, Derivatives not designated as hedging instruments 2015 2014 2013 (In thousands) Beginning fair value of commodity derivative instruments $37,471 $(1,812) $5,538 Gain on oil derivative instruments 57,681 27,548 (3,469)Gain on natural gas derivative instruments 32,607 9,788 (2,391)Net cash received on settlements of oil derivative instruments (41,786) (46) 505 Net cash (received) paid on settlements of natural gas derivative instruments (21,439) 1,993 (1,995)Net change in fair value of commodity derivative instruments 27,063 39,283 (7,350)Ending fair value of commodity derivative instruments $64,534 $37,471 $(1,812) The Partnership had the following open derivative contracts for oil as of December 31, 2015: Volume WeightedAverage Range (Per Bbl) Period and Type of Contract (Bbl) (Per Bbl) Low High Oil Collar Contracts: Q4 2015 Call Options 10,000 $102.00 $102.00 $102.00 Put Options 10,000 85.00 85.00 85.00 Oil Swap Contracts: Q4 2015 173,000 59.67 48.65 61.71 Q1 2016 502,000 55.88 48.54 61.34 Q2 2016 455,000 57.30 50.14 61.96 Q3 2016 424,000 58.38 51.27 62.53 Q4 2016 398,000 59.43 52.40 63.07 FY 2017 703,000 58.50 52.73 63.65 F-15 BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS The Partnership had the following open derivative contracts for natural gas as of December 31, 2015: Volume WeightedAverage Range (Per MMBtu) Period and Type of Contract (MMBtu) (Per MMBtu) Low High Natural Gas Swap Contracts: Q1 2016 6,780,000 $3.26 $3.16 $3.38 Q2 2016 6,240,000 3.07 3.00 3.14 Q3 2016 5,830,000 3.13 3.06 3.17 Q4 2016 5,400,000 3.25 3.10 3.41 FY 2017 9,650,000 3.33 3.14 3.52 The Partnership entered into the following derivative contracts for oil subsequent to December 31, 2015: Volume WeightedAverage Range (Per Bbl) Period and Type of Contract (Bbl) (Per Bbl) Low High Oil Swap Contracts: Q1 2016 28,000 $29.56 $29.07 $29.79 Q2 2016 81,000 32.60 31.25 33.93 Q3 2016 65,000 35.20 34.41 36.09 Q4 2016 50,000 37.00 36.31 37.73 The Partnership entered into the following derivative contracts for natural gas subsequent to December 31, 2015: Volume WeightedAverage Range (Per MMBtu) Period and Type of Contract (MMBtu) (Per MMBtu) Low High Natural Gas Swap Contracts: Q1 2016 340,000 $1.98 $1.96 $1.99 Q2 2016 970,000 2.10 2.03 2.19 Q3 2016 780,000 2.26 2.23 2.28 Q4 2016 550,000 2.42 2.29 2.61 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, 2015 and 2014.F-16 BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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, 2015 Financial Assets Commodity derivative instruments $— $64,534 $— $— $64,534 Financial Liabilities Commodity derivative instruments — — — — — As of December 31, 2014 Financial Assets Commodity derivative instruments $— $37,656 $— $(185) $37,471 Financial Liabilities Commodity derivative instruments — 185 — (185) — 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, measurements of oil and natural gas property impairments, and the initial recognition of ARO, for which fair value is used. TheseARO estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activityto support the assumptions used, the Partnership has designated these measurements as Level 3.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 market-based weighted average cost of capital. The Partnership has designated these measurements as Level 3.Oil and natural gas properties are measured at fair value on a nonrecurring basis using the income approach when measuring 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. Significant Level 3 assumptions used to determine fair value include estimates of proved reserves, future commodityprices, the timing and amount of future production and capital expenditures, and a discount rate commensurate with the risk associated with the respective oiland natural gas properties.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, 2015 and 2014.F-17 BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS The following table presents information about the Partnership’s assets measured at fair value on a non-recurring basis: Fair Value Measurements Using Net Book Level 1 Level 2 Level 3 Value1 Impairment (In thousands) Year Ended December 31, 2015 Impaired oil and natural gas properties $— $— $156,689 $406,258 $249,569 Year Ended December 31, 2014 Impaired oil and natural gas properties $— $— $81,864 $199,794 $117,930 Year Ended December 31, 2013 Impaired oil and natural gas properties $— $— $56,318 $113,427 $57,109 1Amount represents net book value at the date of assessment. The carrying value of all debt as of December 31, 2015 and 2014 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. No customer represented 10.0% or more of total revenue for the year ended December 31, 2015. One company, Chesapeake EnergyCorporation, represented 10.0% and 10.9% of total revenue for the years ended December 31, 2014 and 2013, respectively.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 strip prices. The borrowing base was $700.0 million at December 31,2014. The Partnership’s semi-annual borrowing base redetermination process resulted in a decrease of the borrowing base to $600.0 million, effective April10, 2015. Effective October 28, 2015, the borrowing base was further decreased to $550.0 million. Drawings on the Senior Line of Credit are used for theacquisition of oil and natural gas properties and for other general business purposes.Borrowings under the Senior Line of Credit bear interest at LIBOR plus a margin between 1.50% and 2.50%, or prime rate plus a margin between0.50% and 1.50%, with the margin depending on the borrowing base utilization percentage of the loan, as detailed in the table below. The prime rate isdetermined to be the higher of the financial institution’s prime rate or the federal funds effective rate plus 0.50% per annum. F-18 BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS Borrowing Base Utilization Borrowing type <25% ≥25%<50% ≥50%<75% ≥75%<90% ≥90% Eurodollar Margin 1.50% 1.75% 2.00% 2.25% 2.50%Base Rate Margin 0.50% 0.75% 1.00% 1.25% 1.50% The weighted-average interest rate of the Senior Line of Credit was 1.92% and 2.41% as of December 31, 2015 and 2014, 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 a majority 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, 2015, the Partnership was in compliance with all financialcovenants in the Senior Line of Credit.The aggregate principal balance outstanding was $66.0 million and $394.0 million at December 31, 2015 and 2014, respectively. The unused portionof the available borrowings under the Senior Line of Credit was $484.0 million and $306.0 million at December 31, 2015 and 2014, respectively. Refer toNote 1 – Business and Basis of Presentation for a discussion of the use of proceeds from the IPO.BSNR II-B Revolving Credit FacilityBlack Stone Natural Resources II-B, L.P., a consolidated subsidiary of the Predecessor, obtained a $50.0 million five-year revolving credit facilitydated November 9, 2005, as amended, on November 3, 2010, (“BSNR II-B Revolving Credit Facility”) with a financial institution as the administrative agentand the lender. The Predecessor repaid the outstanding principal balance of $19.1 million on March 28, 2013, and the BSNR II-B Revolving Credit Facilitywas terminated on April 30, 2013.BSNR III-B Revolving Credit FacilityBlack Stone Natural Resources III-B, L.P., a consolidated subsidiary of the Predecessor, obtained a $100.0 million revolving credit facility datedOctober 10, 2008 (“BSNR III-B Revolving Credit Facility”), with a financial institution as the administrative agent and the lender. On December 27, 2012,the BSNR III-B Revolving Credit Facility was amended and extended through November 30, 2017. The Predecessor repaid the outstanding principal balanceof $27.0 million and terminated the BSNR III-B Revolving Credit Facility on May 15, 2013. 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).F-19 BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 totaling $2.7 million with service-based graded vesting requirements through March 31, 2019 were also granted tocertain 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. Award recipients have all the rights of a unitholder in thePartnership with respect to the converted restricted units, including the right to receive distributions thereon, if and when distributions are made by thePartnership to its limited partners. For awards granted prior to December 31, 2014, recipients could request that the Partnership, at its discretion, repurchaseup to fifty percent of the restricted common units that are scheduled to vest. As a result of the repurchase option, fifty percent of the equity awards to bevested on each vesting date were classified as a liability during the corresponding year prior to the vesting date until a request for the Partnership torepurchase was made by the recipient, or the repurchase option period ended, which was 30 days prior to the vesting date. The liability was measuredperiodically at fair value. In conjunction with the adoption of the 2015 LTIP, the provision in certain of the Predecessor’s restricted unit agreements thatallowed award recipients to request cash settlement for up to 50% of their restricted unit awards was removed; as such, these awards are no longer classified asliability awards. Non-employee directors of the Partnership’s general partner received compensation under the 2015 LTIP in the form of fully vested commonunits 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.The following table summarizes information about restricted units for the year ended December 31, 2015. Units Weighted-Average Grant-Date FairValue per Unit Units Predecessor Common Subordinated Predecessor Common Subordinated Unvested at December 31, 2014 668,119 — — $20.81 $— $— Granted 441,900 1,110,877 — 18.30 18.98 — Vested (329,190) (63,156) — 20.87 19.00 — Converted1 (780,829) 338,051 442,778 19.36 19.36 19.36 Forfeited — (23,681) — — 19.00 — Unvested at December 31, 2015 — 1,362,091 442,778 $— $19.08 $19.36 1Consistent with all outstanding Predecessor units, the Predecessor restricted unit award agreements were converted into common and subordinatedunits of the Partnership at a conversion ratio of 12.9465:1 for 0.4329 common units and 0.5671 subordinated units as described in Note 1 – Businessand Basis of Presentation.F-20 BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS The weighted-average grant-date fair value for unit-based awards was $18.79, $20.73, and $20.78 for the years ended December 31, 2015, 2014, and2013, respectively. Unrecognized compensation cost associated with restricted common and subordinated unit awards was $19.6 million and $4.7 million,respectively, as of December 31, 2015, which the Partnership expects to recognize over a weighted-average period of 2.99 years and 1.86 years for commonunits and subordinated units, respectively. The fair value of units vested for the years ended December 31, 2015, 2014, and 2013 was $9.4 million, $8.6million, and $4.3 million, respectively. Cash payments of $0.4 million were made for vested units in 2014. There were no cash payments made for vestedunits during the years ended December 31, 2015 and 2013.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% of the performance units may become earned in each of the 12-month performance periods that end on March 31, 2016, March 31, 2017, and March 31, 2018, respectively. The remaining 50% of the restrictedperformance units are eligible to become earned during the final 12-month performance period that ends on March 31, 2019. If the performance criteria arenot met for the final performance period, the awards allow for a make-up period ending on March 31, 2020. Compensation expense related to the restrictedperformance unit awards is determined by multiplying the number of common units underlying such awards that, based on the Partnership’s estimate, arelikely to vest, by the grant-date fair value and recognized using the accelerated attribution method. Distribution equivalent rights for the restrictedperformance unit awards that are expected to vest are charged to partners’ capital.The following table summarizes information about performance units for the year ended December 31, 2015. Performance units Units Weighted-Average Grant-Date Fair Valueper Unit Unvested at December 31, 2014 — $— Granted 947,142 19.00 Vested — — Forfeited — — Unvested at December 31, 2015 947,142 $19.00 Unrecognized compensation cost associated with performance unit awards was $2.4 million as of December 31, 2015, which the Partnership expects torecognize over a weighted-average period of 0.56 years. No performance units have vested as of December 31, 2015.Incentive Compensation SummaryThe table below summarizes incentive compensation expense recorded in general and administrative expenses in the consolidated statements ofoperations for the years ended December 31, 2015, 2014, and 2013. Year Ended December 31, Incentive compensation expense 2015 2014 2013 (In thousands) Cash—long-term incentive plan $15,064 $13,927 $10,205 Equity-based compensation—restricted common and subordinated units 10,137 7,194 4,754 Equity-based compensation—restricted performance units 4,743 — — Board of Directors incentive plan 3,120 4,146 2,028 Total incentive compensation expense $33,064 $25,267 $16,987 F-21 BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS 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 $0.6 million, $0.6 million, and $0.5 million for the years ended December 31,2015, 2014, and 2013, 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 $1.8 million for theyear ended December 31, 2015 and $1.9 million for both of the years ended December 31, 2014 and 2013. Such amounts are included in general andadministrative expense on the consolidated statements of operations.Future minimum lease commitments under non-cancelable leases are as follows: Year Ending December 31, (In thousands) 2016 $1,416 2017 1,651 2018 1,683 2019 1 2020 — Total $4,751 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.LitigationFrom time to time, the Partnership is involved in legal actions and claims arising in the ordinary course of business. The Partnership believes existingclaims as of December 31, 2015 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 77,216 and 157,203 Series A preferred units (the “Redeemable Preferred Units”) with a book value of $79.2 millionand $161.2 million as of December 31, 2015 and 2014, respectively. The aforementioned amounts include accrued distributions of $1.9 million and $4.0million as of December 31, 2015 and 2014, respectively. The Redeemable Preferred Units are classified as mezzanine equity on the consolidated balancesheets since redemption can occur outside the control of the Partnership. The Redeemable Preferred Units are entitled to an annual distribution of 10% of thefunded capital of the Redeemable Preferred Units, payable on a quarterly basis in arrears.The Redeemable Preferred Units are convertible into common and subordinated units at the option of the preferred unitholders. The RedeemablePreferred Units have an adjusted conversion price of $14.2683 and an adjusted conversion rate of 30.3431 commonF-22 BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS units and 39.7427 subordinated units per Redeemable Preferred Unit, which reflects the reverse split described in Note 1 – Business and Basis of Presentationand the capital restructuring related to the IPO. The unitholders of the Redeemable Preferred Units can elect to have the Partnership redeem up to 25% peryear of their initial balance of Redeemable Preferred Units at face value, plus any accrued and unpaid distributions, on December 31 of each year from 2014to 2017. 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 25% of Redeemable Preferred Units not redeemed on December 31shall automatically convert to common and subordinated units on January 1 of the following year.For the year ended December 31, 2015, 39,240 Redeemable Preferred Units totaling $39.2 million were converted into 2,750,166 Predecessor units,which included units automatically converted on January 1, 2015. For the year ended December 31, 2014, 221 Redeemable Preferred Units totaling $0.2million 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 cancelled 40,747 Redeemable PreferredUnits for $1,019.45 per unit for a total cost of $41.5 million, excluding fees and expenses related to the tender offer. NOTE 14—PREDECESSOR EXCHANGE AND EQUITY OFFERINGSDuring 2012, the Predecessor presented a proposal to purchase the noncontrolling interests in certain subsidiaries in exchange for cash or commonunits of the Predecessor (the “Predecessor Exchange Offer”). The Predecessor Exchange Offer resulted in a majority of the noncontrolling investors electing toexchange their interests in the subsidiaries for cash or common units of the Predecessor. The Predecessor Exchange Offer consisted of the issuance of $1,019.3million of Predecessor units on January 1, 2013. The Predecessor used borrowings under the Senior Line of Credit and proceeds from a concurrent $412.2million unit offering (“Predecessor Equity Offering”), effective January 1, 2013, to fund the purchase of the noncontrolling interests. Cash from thePredecessor Equity Offering in excess of the amounts needed for the Predecessor Exchange Offer was used to repay a portion of the Senior Line of Credit andprovided additional capital for future acquisitions. NOTE 15—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 2.3 million common units and 3.1 million subordinated units as of December 31, 2015. At December 31, 2015, 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, 2015, 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.F-23 BLACK STONE MINERALS, L.P. AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS The following table sets forth the computation of basic and diluted earnings per unit: For the Year Ended December 31, 2015 2014 2013 (In thousands, except per unit amounts) Net income (loss) $(101,305) $169,187 $168,963 Net income attributable to Predecessor (450) (169,187) (168,963)Net loss attributable to noncontrolling interests subsequent to initial public offering 1,260 — — Distributions on redeemable preferred units subsequent to initial public offering (7,522) — — Net loss attributable to the general partner and common and subordinated unitssubsequent to initial public offering $(108,017) $— $— Allocation of net loss subsequent to initial public offering attributable to: General partner interest $— Common units (54,326) Subordinated units (53,691) $(108,017) Net loss attributable to common and subordinated units per unit: Per common unit (basic and diluted) $(0.56) Weighted average common units outstanding (basic and diluted) 96,182 Per subordinated unit (basic and diluted) $(0.56) Weighted average subordinated units outstanding (basic and diluted) 95,057 NOTE 16—SUBSEQUENT EVENTSOn January 8, 2016, the Partnership acquired mineral and royalty interests in the Permian Basin for $10.0 million.On February 9, 2016, the Board approved a distribution for the period October 1, 2015 to December 31, 2015 of $0.2625 per common unit and$0.18375 per subordinated unit. Distributions were paid on February 26, 2016 to unitholders of record at the close of business on February 19, 2016.On February 19, 2016, the Board granted 717,654 restricted common units and 717,654 restricted performance units at a grant-date fair value of$11.25 per unit under the 2015 LTIP. On March 4, 2016, the Board authorized the repurchase of up to $50.0 million in common units over the next six months. F-24 BLACK STONE MINERALS, L.P. AND SUBSIDIARIESSUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES—UNAUDITED Geographic 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, 2015 2014 2013 (In thousands) Acquisition Costs of Properties:1 Proved$2,302 $13,215 $77,580 Unproved 60,994 35,706 264,710 Exploration Costs 2,592 631 174 Development Costs 60,056 50,595 50,440 Total$125,944 $100,147 $392,904 1See 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, 2015 2014 (In thousands) Proved properties$1,957,648 $1,753,167 Unproved properties 524,563 626,376 Total 2,482,211 2,379,543 Accumulated depreciation, depletion, amortization, and impairment (1,543,796) (1,191,861)Oil and natural gas properties, net$938,415 $1,187,682 F-25 BLACK STONE MINERALS, L.P. AND SUBSIDIARIESSUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES—UNAUDITED Oil 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, 2012 14,811 273,800 60,444 Revisions of previous estimates1 1,616 (16,760) (1,177)Purchases of minerals in place2 883 5,472 1,795 Extensions, discoveries and other additions3 4,265 22,848 8,073 Production (2,626) (45,400) (10,193)Net proved reserves at December 31, 2013 18,949 239,960 58,942 Revisions of previous estimates1 (1,904) (20,764) (5,365)Purchases of minerals in place4 89 7,439 1,329 Extensions, discoveries and other additions5 2,938 19,894 6,254 Production (3,005) (42,273) (10,051)Net proved reserves at December 31, 2014 17,067 204,256 51,109 Revisions of previous estimates1 (197) (17,043) (3,037)Purchases of minerals in place6 8 367 69 Extensions, discoveries and other additions7 2,529 57,484 12,110 Production (3,565) (41,389) (10,463)Net proved reserves at December 31, 2015 15,842 203,675 49,788 Net Proved Developed Reserves8 December 31, 2013 17,290 232,777 56,086 December 31, 2014 16,700 202,888 50,514 December 31, 2015 15,497 174,555 44,590 Net Proved Undeveloped Reserves9 December 31, 2013 1,659 7,183 2,856 December 31, 2014 367 1,368 595 December 31, 2015 345 29,120 5,198 1Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and otherfactors. The most notable technical revisions are related to well performance in certain Haynesville/Bossier wells.2Includes the acquisition of mineral interests primarily in the Haynesville/Bossier plays as part of the Predecessor Exchange Offer and additionalmineral acreage located in the Eagle Ford Shale in Texas. Additionally, this line includes adjustments to reserves related to the pro rata distribution ofassets to unrelated third-party investors who chose to take their interests in-kind rather than participate in the Predecessor Exchange Offer.3Includes discoveries and additions primarily related to active drilling in the Haynesville/Bossier, Bakken/Three Forks, Wilcox, Granite Wash, andFayetteville plays.4Includes the acquisition of mineral-and-royalty reserves primarily located throughout Texas, including in the Eagle Ford Shale and Wolfcamp playsand working interest reserves, the substantial majority of which is located in the Haynesville/Bossier play in San Augustine County, Texas.5Includes discoveries and additions primarily related to active drilling in the Haynesville/Bossier, Bakken/Three Forks, Eagle Ford Shale, Wilcox,Granite Wash, and Fayetteville plays.6Includes the acquisition of mineral-and-royalty reserves primarily in the Marcellus and Wolfcamp plays.7Includes discoveries and additions primarily related to active drilling in the Haynesville/Bossier, Bakken/Three Forks, Wilcox, Eagle Ford, andFayetteville plays.8Proved developed reserves of 84 MBoe, 87 MBoe, and 119 MBoe as of December 31, 2015, 2014, and 2013, respectively, were attributable tononcontrolling interests in the Partnership’s consolidated subsidiaries.9As of December 31, 2015, 2014, and 2013, no proved undeveloped reserves were attributable to noncontrolling interests.F-26 BLACK STONE MINERALS, L.P. AND SUBSIDIARIESSUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES—UNAUDITED Standardized 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, 2015 2014 2013 (In thousands) Future cash inflows$1,211,290 $2,493,294 $2,693,511 Future production costs (205,861) (405,833) (393,347)Future development costs (84,746) (64,968) (53,160)Future net cash flows (undiscounted) 920,683 2,022,493 2,247,004 Annual discount 10% for estimated timing (365,711) (879,399) (1,061,747)Total1$554,972 $1,143,094 $1,185,257 1Includes standardized measure of discounted future net cash flows of approximately $0.7 million for December 31, 2015 and $1.4 million for bothDecember 31, 2014 and 2013, 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, 2015 2014 2013 (In thousands) Standardized measure, beginning of year$1,143,094 $1,185,257 $928,518 Sales, net of production costs (222,206) (391,983) (373,655)Net changes in prices and production costs related to future production (621,065) 75,284 208,291 Extensions, discoveries and improved recovery, net of future production anddevelopment costs 165,020 209,651 223,482 Previously estimated development costs incurred during the period 7,084 12,162 22,456 Revisions of estimated future development costs 669 7,854 1,620 Revisions of previous quantity estimates, net of related costs (67,911) (110,431) (22,687)Accretion of discount 114,309 118,526 92,852 Purchases of reserves in place, less related costs 584 24,210 62,887 Other 35,394 12,564 41,493 Standardized measure, end of year$554,972 $1,143,094 $1,185,257 The data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since thecomputations are based on a significant amount of estimates and assumptions. The required projection of production and related expenditures over timerequires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to besubstantially different from historical prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amountsshould give specific recognition to the computational methods utilized and the limitations inherent therein. F-27 BLACK STONE MINERALS, L.P. AND SUBSIDIARIESSELECTED QUARTERLY FINANCIAL INFORMATION—UNAUDITED Selected Quarterly Financial Information—UnauditedQuarterly financial data was as follows for the periods indicated. First Quarter Second Quarter Third Quarter Fourth Quarter (In thousands, except for per unit data) 2015 Total revenue $91,061 $64,803 $137,020 $100,040 Net income (loss) 17,299 (122,766) 53,892 (49,730)Net income (loss) attributable to the general partner and common andsubordinated units subsequent to initial public offering * (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 and paid per limited partner unit Per common unit * * 0.1615 0.2625 Per subordinated unit * * 0.1615 0.2625 Total assets 1,274,291 1,118,569 1,161,446 1,061,436 Long-term debt 389,000 6,000 43,000 66,000 Total mezzanine equity 120,889 120,904 120,936 79,162 2014 Total revenue $127,412 $118,937 $132,795 $169,177 Net income (loss) 69,884 62,111 57,905 (20,713)Net income (loss) attributable to the general partner and common andsubordinated units subsequent to initial public offering * * * * Net income (loss) attributable to common and subordinated units per unit(basic)1 Per common unit (basic) * * * * Per subordinated unit (basic) * * * * Net income (loss) attributable to common and subordinated units per unit(diluted)1 Per common unit (diluted) * * * * Per subordinated unit (diluted) * * * * Cash distributions declared per limited partner unit Per common unit * * * * Per subordinated unit * * * * Total assets 1,468,856 1,466,769 1,444,467 1,326,782 Long-term debt 462,500 453,000 430,000 394,000 Total mezzanine equity 161,306 161,122 161,165 161,165 *Information is not applicable for the periods prior to the initial public offering.1See Note 15 – Earnings Per Unit in the consolidated financial statements. F-28 Exhibit 21.1SUBSIDIARIES OF BLACK STONE MINERALS, L.P. Entity Jurisdiction of OrganizationBlack Stone Energy Company, L.L.C. TexasBlack Stone Minerals Company, L.P. DelawareBlack Stone Minerals GP, L.L.C. DelawareBlack Stone Natural Resources, L.L.C. DelawareBlack Stone Natural Resources Management Company TexasBSAP II GP, L.L.C. DelawareBSMC GP, L.L.C. DelawareBSML Partnership TexasO’Connell Holdings, L.L.C. DelawareO’Connell Partners, L.P. DelawareTLW Investments, L.L.C. Oklahoma Exhibit 23.1 Consent of Independent Registered Public Accounting Firm Black Stone Minerals, L.P.Houston, TexasWe hereby consent to the incorporation by reference in the Registration Statement on Form S-8 (No. 333-203909) of Black Stone Minerals, L.P. of our reportdated March 8, 2016, relating to the 2015 and 2014 consolidated financial statements, which appears in this Form 10-K./s/ BDO USA, LLPHouston, TexasMarch 8, 2016 Exhibit 23.2CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM We hereby consent to the incorporation by reference in the Registration Statement on Form S-8 (File No. 333-203909) of Black Stone Minerals, L.P. of ourreport dated October 7, 2014, with respect to the consolidated financial statements of Black Stone Minerals Company, L.P., the predecessor to Black StoneMinerals, L.P., as of December 31, 2013, and for the year then ended. /s/ UHY LLP Farmington Hills, MichiganMarch 8, 2016 Exhibit 23.3 CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTSWe hereby consent to the use of the name Netherland, Sewell & Associates, Inc., the references to our report of Black Stone Minerals, L.P.’s proved oil andnatural gas reserves estimates and future net revenue as of December 31, 2015, and the inclusion of our corresponding report letter, dated February 5, 2016, inthe 2015 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) 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 Vice PresidentHouston, TexasMarch 8, 2016 Exhibit 31.1CERTIFICATION OF CHIEF EXECUTIVE OFFICERPURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A) OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDEDI, Thomas L. Carter, Jr., certify that:1.I have reviewed this report on Form 10-K of Black Stone Minerals, L.P. (the “registrant”);2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by thisreport;3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respectsthe financial 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)) 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.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 suchevaluation; and c.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 8, 2016 /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, Marc Carroll, 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 respectsthe financial 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)) 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.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 suchevaluation; and c.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 8, 2016 /s/ Marc Carroll Marc Carroll 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 OF CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER UNDER SECTION 906 OF THE SARBANES 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 Marc Carroll, 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 8, 2016 /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 8, 2016 /s/ Marc Carroll Marc Carroll Senior Vice President and Chief Financial Officer Black Stone Minerals GP, L.L.C.,the general partner of Black Stone Minerals, L.P. Exhibit 99.1February 5, 2016 Mr. Brock E. MorrisBlack Stone Minerals, L.P.1001 Fannin, Suite 2020Houston, Texas 77002 Dear Mr. Morris: In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2015, 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 BlackStone's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report areappropriate for such purpose. We estimate the net reserves and future net revenue to the Black Stone interest in these properties, as of December 31, 2015, to be: Net Reserves Future Net Revenue (M$) Oil Gas Present WorthCategory (MBBL) (MMCF) Total at 10% Proved Developed Producing 15,497.5 170,172.0 938,041.8 542,560.7Proved Developed Non-Producing 0.0 4,382.7 8,690.5 6,536.0Proved Undeveloped 344.8 29,119.8 30,892.8 15,505.0 Total Proved 15,842.4 203,674.5 977,625.1 564,601.7 Totals 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 tablesfollowing the definitions set forth our estimates of net reserves and future net revenue, by acquisition, to the Black Stone interest for eachreserves category. 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 2015. For oil volumes, the average West Texas Intermediate spot price of $50.28 per barrel is adjusted for quality,transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $2.587 per MMBTU is adjusted for energycontent, transportation fees, and market differentials. When applicable, gas prices have been adjusted to include the value for natural gasliquids. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over theremaining lives of the properties are $45.02 per barrel of oil and $2.445 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 andwell equipment 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 Stoneinterest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; ourprojections are based on Black Stone receiving its net revenue interest share of estimated future gross production. 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 reservoirperformance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, butnot limited to, that the properties will be developed consistent with current development plans as provided to us by Black Stone, that the propertieswill be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interestowner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves arerecovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmentalpolicies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reservesmay vary from assumptions made while preparing this report. For the purposes of this report, we used technical and economic data including, but not limited to, well logs, well test data, production data,historical 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. and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the propertiesor independently confirmed the actual degree or type of interest owned. The technical person primarily responsible for preparing the estimatespresented herein meets the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. J.Carter Henson, Jr., a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since1989 and has over 8 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists;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 By: /s/ C.H. (Scott) Rees III C.H. (Scott) Rees III, P.E.Chairman and Chief Executive Officer By: /s/ J. Carter Henson, Jr. J. Carter Henson, Jr., P.E. 73964Senior Vice President Date Signed: February 5, 2016 Please 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 documentis intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditionsstated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede thedigital document.JCH:LRG DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4‑10(a). Also included issupplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) 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 relativelyminor compared 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 bymeans not involving 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 timeof the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.Developed Non-Producing Reserves – Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to berecovered from (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 formarket conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recoveredfrom zones in existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can be initiatedor restored with relatively low expenditure compared to the cost of drilling a new well. Definitions - Page 1 of 7 DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) (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 and applicable operating costs of support equipment and facilities andother 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 theextent necessary in developing the proved reserves. (ii)Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platformsand of well equipment 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, measuringdevices, 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 salariesand other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimesreferred to as geological and geophysical or "G&G" costs. (ii)Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for 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. Definitions - Page 2 of 7 DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) (15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological 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 common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localizedgeological features as opposed 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 statesand original locations; (B)The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oilor gas from such properties; (C)The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs,including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as: (1)Lifting the oil and gas to the surface; and (2)Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and (D)Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or othernonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertakenwith 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, ora marine terminal; and b.In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are deliveredto a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, arefinery, a marine 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 thatdoes not have the 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 oiland gas can be 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 exceedingproved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability thatthe total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. Definitions - Page 3 of 7 DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) (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 todefine clearly the area and vertical limits of commercial production from the reservoir by a defined project. (iii)Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in placethan the recovery quantities assumed for probable reserves. (iv)The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternativetechnical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisonsto results in successful similar projects. (v)Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir withinthe same accumulation that may be separated from proved areas by faults with displacement less than formation thickness orother geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacentportions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurallyhigher or lower than the 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 reservoirabove the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of thereservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based onreservoir fluid properties and pressure gradient interpretations. (18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which,together 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 ofestimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that theactual quantities recovered 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 ofavailable data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonablecertainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas arein communication with 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 operatingcosts of support equipment and facilities and other costs of operating and maintaining those wells and related equipment andfacilities. They become 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. Definitions - Page 4 of 7 DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) (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 equipment and facilities are used in oil and gas producingactivities, their depreciation and applicable operating costs become exploration, development or production costs, asappropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are notproduction costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above. (21) Proved area. The part of a property to which proved reserves have been specifically attributed. (22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience 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 tocontain economically 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) asseen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contactwith reasonable certainty. (iii)Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for anassociated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience,engineering, or performance 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,fluid injection) are included in the proved classification when: (A)Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir asa whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliabletechnology establishes the reasonable 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. Theprice shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determinedas an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices aredefined by contractual 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 confidenceDefinitions - Page 5 of 7 DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological,geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EURis 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. (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 endof the year: a.Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B) b.Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in theoperation of the 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 inaccordance with paragraphs 932-235-50-3 through 50-11B: a.Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-endquantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence atyear-end. b.Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing andproducing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economicconditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs. c.Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration offuture tax 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 theproperties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity'sproved 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 expensesfrom future cash 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 toproved oil and gas reserves. f.Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount. Definitions - Page 6 of 7 DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) (27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined byimpermeable rock or water barriers and is individual and separate from other reservoirs. (28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may 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 completed for hydrocarbon production. The classification also includestests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratorytype" 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 economicproducibility at greater distances. (ii)Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating thatthey are scheduled 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 sensitivelocations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take intoconsideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should bethe 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 fiveyears include, but are not limited to, the following: ·The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wellsnecessary to maintain the lease generally would not constitute significant development activities); ·The company's historical record at completing development of comparable long-term projects; ·The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities; ·The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development planseveral times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not beappropriate); and ·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 developproperties with higher priority). (iii)Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluidinjection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actualprojects in the same reservoir or an analogous Definitions - Page 7 of 7 DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a) reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonablecertainty. (32) Unproved properties. Properties with no proved reserves.Definitions - Page 8 of 7

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