Black Stone Minerals, L.P. - Annual Report: 2017 (Form 10-K)

Year Ended December 31,

Exxon Mobil Corporation

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K



x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2017



¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934

For the transition period _______________ to _______________

Commission file number 001-37362

Black Stone Minerals, L.P.

(Exact Name of Registrant As Specified in Its Charter)



Delaware		47-1846692
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)
1001 Fannin Street, Suite 2020 Houston, Texas		77002
(Address of Principal Executive Offices)		(Zip Code)

Registrant’s telephone number, including area code: (713) 445-3200

Securities registered pursuant to Section 12(b) of the Act:



Title of each class		Name of each exchange on which registered
Common Units Representing Limited Partner Interests		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check One):



Large Accelerated Filer	x		Accelerated Filer	¨
Non-Accelerated Filer	¨	(Do not check if a smaller reporting company)	Smaller Reporting Company	¨
			Emerging Growth Company	¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

The aggregate market value of the common units held by non-affiliates was $1,197,800,850 on June 30, 2017, the last business day of the registrant’s most recently completed second fiscal quarter, based on a closing price of $15.76 per unit as reported by the New York Stock Exchange on such date. As of February 20, 2018, 104,258,290 common units, 95,388,424 subordinated units, 24,803 Series A redeemable preferred units, and 14,711,219 Series B cumulative convertible preferred units of the registrant were outstanding.

Documents Incorporated by Reference: Certain information called for in Items 10, 11, 12, 13, and 14 of Part III are incorporated by reference from the registrant’s definitive proxy statement for the annual meeting of unitholders.

BLACK STONE MINERALS, L.P.

TABLE OF CONTENTS



		PAGE
PART I

ITEMS 1 AND 2.	BUSINESS AND PROPERTIES	2
ITEM 1A.	RISK FACTORS	30
ITEM 1B.	UNRESOLVED STAFF COMMENTS	51
ITEM 3.	LEGAL PROCEEDINGS	51
ITEM 4.	MINE SAFETY DISCLOSURES	51

PART II

ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES	52
ITEM 6.	SELECTED FINANCIAL DATA	58
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	59
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	76
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	76
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	76
ITEM 9A.	CONTROLS AND PROCEDURES	77
ITEM 9B.	OTHER INFORMATION	77

PART III

ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	78
ITEM 11.	EXECUTIVE COMPENSATION	78
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS	78
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	78
ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	78

PART IV

ITEM 15.	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	79

GLOSSARY OF TERMS

The following list includes a description of the meanings of some of the oil and gas industry terms used in this Annual Report on Form 10-K (“Annual Report”).

Basin. A large depression on the earth’s surface in which sediments accumulate.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume.

Bbl/d. Bbl per day.

Bcf. One billion cubic feet of natural gas.

Boe. Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil. This “Btu-equivalent” conversion metric is based on an approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas.

Boe/d. Boe per day.

British Thermal Unit (Btu). The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Completion. The process of treating a drilling well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

Crude oil. Liquid hydrocarbons retrieved from geological structures underground to be refined into fuel sources.

Delaware Act. Delaware Revised Uniform Limited Partnership Act.

Delay rental. Payment made to the lessor under a non-producing oil and natural gas lease at the end of each year to defer a drilling obligation and continue the lease for another year during its primary term.

Deterministic method. The method of estimating reserves or resources under which a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

Development costs. Capital costs incurred in the acquisition, exploitation, and exploration of proved oil and natural gas reserves.

Development well. A well drilled within the proved area of an oil and natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Differential. An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.

Dry hole or dry well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Economically producible. A resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.

Exploitation. A drilling or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

iii

GLOSSARY OF TERMS

Extension well. A well drilled to extend the limits of a known reservoir.

Farmout agreement. An agreement with a working interest owner, called the "farmor," whereby the farmor agrees to assign some or all of the working interest to another party, called the "farmee," in exchange for certain contractually agreed services with respect to such acreage or for payment for drilling operations on the acreage.

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Formation. A layer of rock which has distinct characteristics that differs from other nearby rock.

Gross acres or gross wells. The total acres or wells, as the case may be, in which an interest is owned.

Horizontal drilling. A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

Hydraulic fracturing. A process used to stimulate production of hydrocarbons. The process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production.

Lease bonus. Usually a one-time payment made to a mineral owner as consideration for the execution of an oil and natural gas lease.

Lease operating expense. All direct and allocated indirect costs of lifting hydrocarbons from a producing formation to the surface constituting part of the current operating expenses of a working interest. Such costs include labor, supplies, repairs, maintenance, allocated overhead charges, workover costs, insurance, and other expenses incidental to production, but exclude lease acquisition or drilling or completion costs.

Log. An analysis that provides information on porosity, hydraulic conductivity, and fluid content of formations drilled in fluid-filled boreholes.

MBbls. One thousand barrels of oil or other liquid hydrocarbons.

MBoe. One thousand Boe.

MBoe/d. MBoe per day.

Mcf. One thousand cubic feet of natural gas.

Mineral interests. Real-property interests that grant ownership of the oil and natural gas under a tract of land and the rights to explore for, drill for, and produce oil and natural gas on that land or to lease those exploration and development rights to a third party.

MMBtu. Million British Thermal Units.

MMcf. Million cubic feet of natural gas.

Net acres or net wells. The sum of the fractional interest owned in gross acres or gross wells, respectively.

Net revenue interest. An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty, overriding royalty, and other non-cost-bearing interests.

Natural gas. A combination of light hydrocarbons that, in average pressure and temperature conditions, is found in a gaseous state. In nature, it is found in underground accumulations, and may potentially be dissolved in oil or may also be found in its gaseous state.

NGLs. Natural gas liquids.

GLOSSARY OF TERMS

Nonparticipating royalty interest (NPRI). A type of non-cost-bearing royalty interest, which is carved out of the mineral interest and represents the right, which is typically perpetual, to receive a fixed cost-free percentage of production or revenue from production, without an associated right to lease.

NYMEX. New York Mercantile Exchange.

Oil. Crude oil and condensate.

Oil and natural gas properties. Tracts of land consisting of properties to be developed for oil and natural gas resource extraction.

Operator. The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.

Overriding royalty interest (ORRI). A fractional, undivided interest or right of participation in the oil or natural gas, or in the proceeds from the sale of the oil or gas, produced from a specified tract or tracts, which are limited in duration to the terms of an existing lease and which are not subject to any portion of the expense of development, operation, or maintenance.

PDP. Proved developed producing, used to characterize reserves.

Play. A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic, and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism, and hydrocarbon type.

Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

Pooling. The majority of our producing acreage is pooled with third-party acreage. Pooling refers to an operator’s consolidation of multiple adjacent leased tracts, which may be covered by multiple leases with multiple lessors, in order to maximize drilling efficiency or to comply with state mandated well spacing requirements. Pooling dilutes our royalty in a given well or unit, but it also increases both the acreage footprint and the number of wells in which we have 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 the production 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 be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Reliable technology. A grouping of one or more technologies (including computation methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

GLOSSARY OF TERMS

Reserves. Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to the market, and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

Resource play. A set of discovered or prospective oil and/or natural gas accumulations sharing similar geologic, geographic, and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism, and hydrocarbon type.

Royalty interest. An interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development.

Seismic data. Seismic data is used by scientists to interpret the composition, fluid content, extent, and geometry of rocks in the subsurface. Seismic data is acquired by transmitting a signal from an energy source, such as dynamite or water, into the earth. The energy so transmitted is subsequently reflected beneath the earth’s surface and a receiver is used to collect and record these reflections.

Shale. A fine grained sedimentary rock formed by consolidation of clay- and silt-sized particles into thin, relatively impermeable layers. Shale can include relatively large amounts of organic material compared with other rock types and thus has the potential to become rich hydrocarbon source rock. Its fine grain size and lack of permeability can allow shale to form a good cap rock for hydrocarbon traps.

Spacing. The distance between wells producing from the same reservoir, often established by regulatory agencies.

Standardized measure. The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the Securities and Exchange Commission (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Because we are a limited partnership, we are generally not subject to federal or state income taxes and thus make no provision for federal or state income taxes in the calculation of 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 been generally defined, having geological characteristics that have been ascertained through supporting geological, geophysical, or other data to contain the potential for oil and/or natural gas reserves in a particular formation or series of formations.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Working interest. An operating interest that gives the owner the right to drill, produce, and conduct operating activities on the property, and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

Workover. Operations on a producing well to restore or increase production.

WTI. West Texas Intermediate oil, which is a light, sweet crude oil, characterized by an American Petroleum Institute (“API”) gravity between 39 and 41 and a sulfur content of approximately 0.4% by weight that is used as a benchmark for the other crude oils.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements and information in this Annual Report may constitute “forward-looking statements.” The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could,” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:


•	our ability to execute our business strategies;


•	the volatility of realized oil and natural gas prices;


•	the level of production on our properties;


•	the overall supply and demand for oil and natural gas, and regional supply and demand factors, delays, or interruptions of production;


•	our ability to replace our oil and natural gas reserves;


•	our ability to identify, complete, and integrate acquisitions;


•	general economic, business, or industry conditions;


•	competition in the oil and natural gas industry;


•	the ability of our operators to obtain capital or financing needed for development and exploration operations;


•	title defects in the properties in which we invest;


•	the availability or cost of rigs, equipment, raw materials, supplies, oilfield services, or personnel;


•	restrictions on the use of water for hydraulic fracturing;


•	the availability of pipeline capacity and transportation facilities;


•	the ability of our operators to comply with applicable governmental laws and regulations and to obtain permits and governmental approvals;


•	federal and state legislative and regulatory initiatives relating to hydraulic fracturing;


•	future operating results;


•	future cash flows and liquidity, including our ability to generate sufficient cash to pay quarterly distributions;


•	exploration and development drilling prospects, inventories, projects, and programs;


•	operating hazards faced by our operators;


•	the ability of our operators to keep pace with technological advancements; and


•	certain factors discussed elsewhere in this Annual Report.

For additional information regarding known material factors that could cause our actual results to differ from our projected results, please read Part I, Item 1A. “Risk Factors.”

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events, or otherwise.

PART I

Unless the context clearly indicates otherwise, references in this Annual Report on Form 10-K to “BSMC,” “Black Stone Minerals, L.P. Predecessor,” or “our predecessor,” refer to Black Stone Minerals Company, L.P. and its subsidiaries for time periods prior to the initial public offering of Black Stone Minerals, L.P. on May 6, 2015 (the “IPO”), and references to “BSM,” “Black Stone,” “we,” “our,” “us,” “the Partnership,” or like terms refer to Black Stone Minerals, L.P. and its subsidiaries for time periods subsequent to the IPO.

ITEMS 1 AND 2. BUSINESS AND PROPERTIES

General

We are one of the largest owners and managers of oil and natural gas mineral interests in the United States. Our principal business is maximizing the value of our existing mineral and royalty assets through active management and expanding our asset base through acquisitions of additional mineral and royalty interests. We maximize value through marketing our mineral assets for lease, creatively structuring 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 interests. Our primary business objective is to grow our reserves, production, and cash generated from operations over the long term, while paying, to the extent practicable, a growing quarterly distribution to our unitholders.

We own mineral interests in approximately 16.8 million acres, with an average 43.4% ownership interest in that acreage. We also own NPRIs in 1.9 million acres and ORRIs in 2.1 million acres. These non-cost-bearing interests, which we refer to collectively as our “mineral and royalty interests,” include ownership in approximately 55,728 producing wells. Our mineral and royalty interests are located in 41 states and in 64 onshore basins in the continental United States. Many of these interests are in active resource plays, including the Haynesville/Bossier Shales in East Texas/Western Louisiana, the Wolfcamp/Spraberry/Bone Spring in the Permian Basin, the Bakken/Three Forks in the Williston Basin, the Eagle Ford Shale in South Texas, the Niobrara/Codell Shales in the DJ Basin, and the Fayetteville Shale in the Arkoma Basin, as well as emerging plays such as the Lower Wilcox play in East Texas and the Canyon Lime play in the Texas Panhandle. The combination of the breadth of our asset base, the long-lived, non-cost-bearing nature of our mineral and royalty interests, and our active management expose us to potential additional 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 6, 2015, we completed our initial public offering of 22,500,000 common units representing limited partner interests at a price to the public of $19.00 per common unit. Our common units trade on the New York Stock Exchange under the symbol "BSM."

BSM files or furnishes annual reports on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K, as well as any amendments to these reports with the U.S. Securities and Exchange Commission (“SEC”). Through our website, http://www.blackstoneminerals.com, we make available electronic copies of the documents we file or furnish to the SEC. Access to these electronic filings is available free of charge as soon as reasonably practicable after filing or furnishing them to the SEC.

Our Assets

As of December 31, 2017, our total estimated proved oil and natural gas reserves were 67,945 MBoe based on a reserve report prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), an independent third-party petroleum engineering firm. Of the reserves as of December 31, 2017, approximately 83.5% were proved developed reserves (approximately 82.4% proved developed producing and 1.1% proved developed non-producing) and approximately 16.5% were proved undeveloped reserves. At December 31, 2017, our estimated proved reserves were 26.3% oil and 73.7% natural gas.

The locations of our oil and natural gas properties are presented on the following map. Additional information related to these properties follows this map.

Mineral and Royalty Interests

Mineral interests are real-property interests that are typically perpetual and grant ownership of the oil and natural gas under a tract of land and the rights to explore for, drill for, and produce oil and natural gas on that land or to lease those exploration and development rights to a third party. When those rights are leased, usually for a three-year term, we typically receive an upfront cash payment, known as lease bonus, and we retain a mineral royalty, which entitles us to a cost-free percentage (usually ranging from 20% to 25%) of production or revenue from production. A lessee can extend the lease beyond the initial lease term with continuous drilling, production, or other operating activities, or by making an extension payment. When production or drilling ceases, the lease terminates, allowing us to lease the exploration and development rights to another party. Mineral interests generate the substantial majority of our revenue and are also the assets that we have the most influence over.

In addition to mineral interests, we also own other types of non-cost-bearing royalty interests, which include:


•	Nonparticipating royalty interests (“NPRIs”), which are royalty interests that are carved out of the mineral estate and represent the right, which is typically perpetual, to receive a fixed, cost-free percentage of production or revenue from production, without an associated right to lease or receive lease bonus; and


•	Overriding royalty interests (“ORRIs”), which are royalty interests that burden working interests and represent the right to receive a fixed, cost-free percentage of production or revenue from production from a lease. ORRIs remain in effect until the associated leases expire.

Working-Interest Participation Program

We own working interests related to our mineral interests in various plays across our asset base. Many of these working interests were acquired through working-interest participation rights, which we often include in the terms of our leases. This participation right complements our core mineral-and-royalty-interest business because it allows us to realize additional value from our minerals. Under the terms of the relevant leases, we are typically granted a unit-by-unit or a well-by-well option to participate on a non-operated working-interest basis in drilling opportunities on our mineral acreage. This right to participate in a unit or well is exercisable at our sole discretion. We generally only exercise this option when the results from prior drilling and production activities have substantially reduced the economic risk associated with development drilling and where we believe the probability of achieving attractive economic returns is high. A small portion of our working interests, unrelated to our mineral and royalty assets, were acquired because of the attractive working-interest investment opportunities on those properties. The majority of these assets are focused in the Anadarko Basin, and to a lesser extent, in the Permian and Powder River Basins.

We collectively refer to these working interests as our “working-interest participation program.” When we participate in non-operated working-interest opportunities, we are required to pay our portion of the costs associated with drilling and operating these wells. Working interest production represented 40.0% of our total production volumes during the year ended December 31, 2017. As of December 31, 2017, we owned non-operated working interests in 9,688 gross (352 net) wells.

Our 2018 drilling capital expenditure budget associated with our working-interest participation program is expected to range between $15 million and $25 million. Approximately 99% of our 2018 drilling capital budget will be spent in the Haynesville/Bossier play with the remainder spent in various plays including the Bakken/Three Forks and Wolfcamp plays. In 2018, we also expect to spend an additional $10 million to $12 million to drill two 100% working interest exploratory wells to evaluate a Lower Wilcox prospect in East Texas.

Farmout Agreements

On February 21, 2017, we announced that we entered into a farmout agreement with Canaan Resource Partners ("Canaan", and such farmout, the "Canaan Farmout"), which covers certain Haynesville and Bossier shale acreage in San Augustine County, Texas operated by XTO Energy Inc. We have an approximate 50% working interest in the acreage. A total of 18 wells are anticipated to be drilled over an initial phase, beginning with wells spud after January 1, 2017. As of December 31, 2017, 10 wells had been drilled during the initial phase. At its option, Canaan may participate in two additional phases with each phase continuing for the lesser of 2 years or until 20 wells have been drilled. During the first three phases of the agreement, Canaan will commit on a phase-by-phase basis and fund 80% of our drilling and completion costs and will be assigned 80% of our working interests in such wells (40% working interest on an 8/8ths basis). After the third phase, Canaan can earn 40% of our working interest (20% working interest on an 8/8ths basis) in additional wells drilled in the area by continuing to fund 40% of our costs for those wells on a well-by-well basis. We will receive a base ORRI before payout and an additional ORRI after payout on all wells drilled under the agreement. The Canaan Farmout is anticipated to reduce our future capital expenditures by approximately $40 to $50 million annually during the term of the agreement.

On November 21, 2017, we entered into a farmout agreement with a portfolio company of Tailwater Capital, LLC, Pivotal Petroleum Partners (“Pivotal”), that covers substantially all of our remaining working interests under active development in the Shelby Trough area of East Texas targeting the Haynesville and Bossier shale acreage after giving effect to the Canaan Farmout (discussed above) over the next eight years. In wells operated by XTO Energy Inc. in San Augustine County, Texas, Pivotal will earn our remaining approximate 20% working interest (10% working interest on an 8/8ths basis) not covered by the Canaan Farmout, as well as 100% of our working interests (ranging from approximately 12.5% to 25% on an 8/8ths basis) in wells operated by our other major operator in the area. Initially, Pivotal will be obligated to fund the development of up to 80 wells across several development areas and then will have options to continue funding our working interest across those areas for the duration of the eight year term. After the funding of a designated group of wells by Pivotal and once Pivotal achieves a specified payout for such well group, the Partnership will obtain a majority of the original working interest in the designated group of wells.

As a result of the farmout agreements with Canaan and Pivotal, we expect capital requirements associated with non-operated working interests to be minimal beyond the first quarter of 2018.

Our Properties

Material Basins and Producing Regions

We may own more than one type of interest in the same tract of land. For example, where we have acquired working interests through our working-interest participation program in a given tract, our working-interest acreage in that tract will relate to the same acres as our mineral-interest acreage in 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 can be significant, while overlap between the different types of mineral and royalty interests is not significant. The following table describes our mineral and royalty interests and working interests:



	Acreage as of December 31, 2017					Average Daily Production (Boe/d) For the Year Ended December 31, 2017
	Mineral and Royalty Interests			Working Interests¹
USGS Petroleum Province²	Mineral Interests	NPRIs	ORRIs	Gross	Net
Louisiana-Mississippi Salt Basins	5,408,632	238,426	26,104	59,117	7,999	4,752
Western Gulf (onshore)	1,732,750	297,303	282,208	122,167	18,692	5,561
Permian Basin	1,647,573	800,654	185,069	8,113	5,051	2,820
Williston Basin	1,543,797	65,974	34,099	59,875	7,895	3,624
Palo Duro Basin	1,024,913	22,791	1,120	—	—	87
East Texas Basin	598,717	55,155	78,960	148,121	50,693	13,704
Anadarko Basin	577,264	13,723	280,283	30,939	21,254	1,652
Appalachian Basin	495,843	416	14,861	—	—	853
Arkoma Basin	357,394	9,999	38,109	9,045	2,333	1,337
Bend Arch-Fort Worth Basin	149,260	56,703	43,514	52,885	13,475	353
Southwestern Wyoming	22,338	—	77,529	14,056	2,050	483
Other	3,235,453	314,539	1,033,649	39,152	8,742	1,785
Total	16,793,934	1,875,683	2,095,505	543,470	138,184	37,011


¹	Excludes acreage for which we have incomplete seller records.


²	The basins and regions shown in the table are consistent with U.S. Geological Survey (“USGS”) delineations of petroleum provinces of onshore and state 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 Arkansas through south central and southern Mississippi, southern Alabama, and the Florida Panhandle. The Haynesville/Bossier plays, which have been extensively delineated through drilling, are the most prospective and most active unconventional plays for natural gas production and reserves within this region. Approximately half of the Haynesville/Bossier plays’ prospective acreage is within the Louisiana-Mississippi Salt Basins region, where we own significant mineral and royalty interests and working interests. There are a number of additional conventional and unconventional plays in this region 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 both conventional and unconventional plays. We have extensive exposure to the Eagle Ford Shale in South Texas, where we are experiencing a significant level of development drilling on our mineral interests within the oil and rich-gas and condensate areas of the play. In addition to the Eagle Ford Shale play, there are a number of other conventional and unconventional plays to which we have exposure to in the region, including the Austin Chalk, Buda, Eaglebine (or Maness) Shale, Frio, Glenrose, Olmos, Woodbine, Vicksburg, Wilcox, and Yegua plays.

•

Permian Basin. The Permian Basin ranges from southeastern New Mexico into West Texas and is currently one of the most active areas for drilling in the United States. It includes three geologic provinces: the Midland Basin to the east, the Delaware Basin to the west, and the Central Basin Platform in between. Our acreage underlies prospective areas for the Wolfcamp play in the Midland and Delaware Basins, the Spraberry formation in the Midland Basin, and the Bone Spring formation in the Delaware Basin, which are among the plays most actively targeted by drillers within the basin. In addition to these plays, we own mineral and royalty interests that are prospective for a number of other conventional and unconventional plays in the Permian Basin, including the Atoka, Clearfork, Ellenberger, San Andres, Strawn, and Wichita Albany plays.

•

Williston Basin. The Williston Basin stretches through the western half of North Dakota, the northwest part of South Dakota, and eastern Montana and includes plays such as the Bakken/Three Forks plays, where we have significant exposure through our mineral and royalty interests as well as through 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 and extends partially into New Mexico to the west. We have a significant acreage position in the Palo Duro Basin, much of which underlies an unconventional oil play in the Canyon Lime. We are also well positioned relative to a number of other conventional and unconventional plays in the Palo Duro Basin, including the Brown Dolomite, Canyon Wash, Cisco Sand, and Strawn Wash plays.

•

East Texas Basin. The East Texas Basin ranges from central East Texas to northeast Texas and includes the Haynesville/Bossier plays and the Cotton Valley play, which are among the most prolific natural gas plays in the basin. We own a material acreage position in the southern Shelby Trough area of the Haynesville/Bossier plays located in San Augustine, Nacogdoches, and Angelina Counties, which is one of the most active areas being drilled today 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.

•

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 the Granite Wash, Atoka, Cleveland, Meramac, and Woodford Shale plays. Other plays in which we hold interests in prospective acreage include the Cottage 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 are the Marcellus Shale and Utica plays, which cover most of western Pennsylvania, northern West Virginia, and eastern Ohio. In addition to the Marcellus Shale, there are a number of other conventional and unconventional plays to which we have material exposure in the Appalachian Basin, including the Berea, Big Injun, Devonian, Huron, Rhinestreet, and Utica plays.

•

Arkoma Basin. The Arkoma Basin stretches from southeast Oklahoma through central Arkansas. The Fayetteville Shale play is one of the basin’s most significant unconventional natural gas plays. We own material mineral and royalty interests within the prospective area of the Fayetteville Shale. In addition, we have exposure to a number of other conventional and unconventional plays in the basin, including the Atoka, Cromwell, Dunn, Hale, and Woodford Shale plays.

•

Bend Arch-Fort Worth Basin. The Bend Arch-Fort Worth Basin covers much of north central Texas and includes the Barnett Shale play as its most active unconventional play. Through our mineral and royalty interests in this basin, we have significant exposure to the Barnett Shale as well 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 of the 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 plays as well, including the Mesaverde, Niobrara, and Wasatch plays.

Interests by USGS Petroleum Province

The following tables present information about our mineral-and-royalty-interest and non-operated working-interest acreage, production, and well count by USGS petroleum province.

Mineral Interests

The following table sets forth information about our mineral interests:



	As of December 31, 2017					Average Daily Production (Boe/d) for the Year Ended December 31,
USGS Petroleum Province¹	Acres	Average Ownership Interest²		Average Ownership Leased³		2017	2016	2015
Louisiana-Mississippi Salt Basins	5,408,632	53.3	%	8.7	%	3,867	3,415	3,384
Western Gulf (onshore)	1,732,750	52.7	%	36.0	%	4,668	4,526	5,021
Permian Basin	1,647,573	11.6	%	79.2	%	2,443	1,035	585
Williston Basin	1,543,797	14.6	%	44.7	%	2,906	2,534	2,430
Palo Duro Basin	1,024,913	46.2	%	8.7	%	75	24	23
East Texas Basin	598,717	53.0	%	32.3	%	3,098	1,854	884
Black Warrior Basin	594,906	54.6	%	2.3	%	38	—	39
Anadarko Basin	577,264	31.7	%	61.8	%	745	673	959
Eastern Great Basin	567,909	96.7	%	0.1	%	—	39	—
Appalachian Basin	495,843	39.4	%	15.3	%	191	163	80
Arkoma Basin	357,394	52.9	%	31.6	%	1,172	1,302	1,458
Western Great Basin	338,303	90.5	%	—		—	—	—
North-Central Montana	182,868	13.5	%	32.5	%	3	9	4
Piedmont	179,879	67.8	%	—		—	—	—
Atlantic Coastal Plain	171,791	12.5	%	31.7	%	—	199	—
Bend Arch-Fort Worth Basin	149,260	20.8	%	34.7	%	198	—	392
Cherokee Platform	112,384	13.8	%	33.6	%	26	34	41
Florida Peninsula	90,744	12.1	%	47.6	%	—	2	—
Illinois Basin	80,864	53.1	%	8.0	%	2	3	2
Powder River Basin	80,239	11.2	%	26.7	%	6	—	56
Other	857,904	30.6	%	27.2	%	967	1,295	301
Total	16,793,934	43.4	%	26.4	%	20,405	17,107	15,659


¹	The basins and regions shown in the table are consistent with USGS petroleum-province delineations.

Ownership interest is equal to the percentage that our undivided ownership interest in a tract bears to the entire tract. The average ownership interests shown reflects the weighted averages of our ownership interests in all tracts in the basin or region. Our weighted-average mineral royalty for all of our mineral interests is approximately 20%, which may be multiplied by our ownership interest to approximate the average royalty interest in our mineral and royalty interests.


³	The average percent leased reflects the weighted average of our leased acres relative to our total acreage on a tract-by-tract basis in the basin or region.

NPRIs

The following table sets forth information about our NPRIs:



	As of December 31, 2017					Average Daily Production (Boe/d) for the Year Ended December 31,
USGS Petroleum Province¹	Acres	Average Royalty Interest²		Average Percent Leased³		2017	2016	2015
Permian Basin	800,654	1.9	%	61.6	%	39	19	31
Western Gulf (onshore)	297,303	3.5	%	61.2	%	7	14	10
Louisiana-Mississippi Salt Basins	238,426	4.1	%	64.9	%	4	1	—
North-Central Montana	138,027	3.0	%	11.6	%	—	—	—
Marathon Thrust Belt	117,442	4.9	%	1.6	%	—	—	—
Williston Basin	65,974	2.7	%	38.0	%	108	92	106
Bend Arch-Fort Worth Basin	56,703	4.1	%	14.4	%	1	1	—
East Texas Basin	55,155	2.6	%	79.9	%	556	179	381
Powder River Basin	33,467	6.1	%	7.2	%	—	—	—
Palo Duro Basin	22,791	3.8	%	1.7	%	—	—	—
Anadarko Basin	13,723	3.6	%	94.3	%	32	18	8
Arkoma Basin	9,999	2.4	%	85.3	%	9	13	21
Cambridge Arch-Central Kansas Uplift	8,903	5.5	%	83.7	%	—	—	—
Southwest Montana	4,367	6.2	%	7.3	%	—	—	—
Cherokee Platform	2,555	4.7	%	31.3	%	—	—	—
Nemaha Uplift	2,334	1.6	%	41.4	%	—	—	—
Montana Thrust Belt	2,242	4.1	%	—	%	—	—	—
Sedgwick Basin	1,850	2.5	%	82.2	%	—	—	—
Black Warrior Basin	1,500	0.3	%	100.0	%	—	—	—
Uinta-Piceance Basin	560	1.0	%	—	%	—	—	—
Other	1,708	5.2	%	29.9	%	169	180	185
Total	1,875,683	3.0	%	51.3	%	925	518	742


¹	The basins and regions shown in the table are consistent with USGS petroleum-province delineations.

Average royalty interest is equal to the weighted-average percentage of production or revenues (before operating costs) that we are entitled to on a tract-by-tract basis in the basin or region. NPRIs may be denominated as a “fractional royalty,” which entitles the owner to the stated fraction of gross production, or a “fraction of royalty,” where the stated fraction is multiplied by the lease royalty. In cases where our land documentation does not specify the form of NPRI, we have assumed a fractional royalty for purposes of the average royalty interests shown above.


³	The average percent leased reflects the weighted average of our leased acres relative to our total acreage on a tract-by-tract basis in the basin or region.

ORRIs

The following table sets forth information about our ORRIs:



	As of December 31, 2017			Average Daily Production (Boe/d) for the Year Ended December 31,
USGS Petroleum Province¹	Acres	Average Royalty Interest²		2017	2016	2015
North-Central Montana	457,897	2.5	%	2	13	35
Western Gulf (onshore)	282,208	2.8	%	246	157	262
Anadarko Basin	280,283	3.4	%	188	200	232
Permian Basin	185,069	1.0	%	106	64	72
Uinta-Piceance Basin	174,701	2.5	%	21	24	37
Powder River Basin	120,722	3.8	%	26	45	98
East Texas Basin	78,960	6.9	%	97	96	81
Southwestern Wyoming	77,529	2.0	%	415	451	529
Michigan Basin	56,512	1.0	%	20	18	21
Denver Basin	45,608	4.4	%	156	117	83
Bend Arch-Fort Worth Basin	43,514	4.7	%	100	108	160
Paradox Basin	43,301	1.3	%	1	—	2
Arkoma Basin	38,109	3.0	%	20	23	29
San Juan Basin	37,644	1.1	%	4	6	3
Williston Basin	34,099	2.1	%	62	59	76
Louisiana-Mississippi Salt Basins	26,104	3.8	%	405	705	1,185
Northern Alaska	24,214	3.5	%	28	28	32
Wind River Basin	8,528	1.1	%	34	27	33
Cambridge Arch-Central Kansas Uplift	17,469	4.9	%	3	3	5
Appalachian Basin	14,861	2.5	%	706	693	—
Other	48,173	1.4	%	91	156	911
Total	2,095,505	2.8	%	2,731	2,993	3,886


¹	The basins and regions shown in the table are consistent with USGS petroleum-province delineations.


²	Average royalty interest is equal to the weighted-average percentage of production or revenues (before operating costs) that we are entitled to on a tract-by-tract basis in the basin or region.

Working Interests

The following table sets forth information about our non-operated working interests:



	As of December 31, 2017		Average Daily Production (Boe/d) for the Year Ended December 31,
USGS Petroleum Province¹	Gross Acres²	Net Acres²	2017	2016	2015
East Texas Basin	148,121	50,693	9,803	4,776	2,341
Western Gulf (onshore)	122,167	18,692	640	1,494	1,234
Williston Basin	59,875	7,895	548	1,377	1,425
Louisiana-Mississippi Salt Basins	59,117	7,999	476	932	1,007
Bend Arch-Fort Worth Basin	52,885	13,475	54	118	108
Anadarko Basin	30,939	21,254	687	1,018	1,205
Southwestern Wyoming	14,056	2,050	24	11	1
Michigan Basin	13,287	1,330	—	6	6
Powder River Basin	12,936	3,382	68	103	169
Arkoma Basin	9,045	2,333	136	277	341
Permian Basin	8,113	5,051	232	323	214
Denver Basin	4,923	1,040	133	130	5
Paradox Basin	2,602	1,281	2	4	5
North-Central Montana	2,080	605	—	1	1
Uinta-Piceance Basin	1,005	482	50	68	—
San Juan Basin	960	334	—	15	11
Wind River Basin	440	43	—	—	—
Southern Oklahoma	390	92	97	132	174
Cherokee Platform	328	137	—	1	5
Illinois Basin	200	16	—	—	—
Other	1	—	—	279	128
Total	543,470	138,184	12,950	11,065	8,380


¹	The basins and regions shown in the table are consistent with USGS petroleum-province delineations.


²	Excludes acreage that is not quantifiable due to incomplete seller records.

Wells

The following tables set forth information about our mineral-and-royalty-interest and working-interest wells as of December 31, 2017:



Mineral and Royalty Interests		Working Interests
USGS Petroleum Province¹	Gross Well Count²	USGS Petroleum Province¹	Gross Well Count²
Permian Basin	23,685	Anadarko Basin	2,898
Anadarko Basin	4,068	Uinta-Piceance Basin	1,378
East Texas Basin	3,992	Permian Basin	908
Williston Basin	3,561	East Texas Basin	907
Louisiana-Mississippi Salt Basin	3,504	Arkoma Basin	751
Western Gulf (onshore)	3,494	Western Gulf (onshore)	640
Arkoma Basin	2,009	Louisiana-Mississippi Salt Basin	546
Uinta-Piceance Basin	1,750	Williston Basin	542
Bend Arch-Fort Worth Basin	1,230	Southern Oklahoma	389
Michigan Basin	924	Bend Arch-Fort Worth Basin	228
Appalachian Basin	846	Appalachian Basin	189
Southwestern Wyoming	783	Nemaha Uplift	104
Denver Basin	707	Powder River Basin	63
Cherokee Platform	642	Michigan Basin	62
San Juan Basin	627	Denver Basin	21
North-Central Montana	605	Cherokee Platform	16
Powder River Basin	490	Palo Duro Basin	11
Wyoming Thrust Belt	391	North-Central Montana	10
Southern Oklahoma	369	Paradox Basin	8
San Joaquin Basin	363	Black Warrior Basin	5
Other	1,688	Other	12
Total	55,728	Total	9,688


¹	The basins and regions shown in the table are consistent with USGS petroleum-province delineations.


²	We own both mineral and royalty interests and working interests in 3,973 of the wells shown in each column above.

Material Resource Plays

We may own more than one type of interest in the same tract of land. For example, where we have acquired working interests through our working-interest participation program in a given tract, our working-interest acreage in that tract will relate to the same acres as our mineral-interest acreage in that tract. Consequently, some of the acreage shown for one type of interest above may also be included in the acreage shown for another type of interest. Because of our working-interest participation program, overlap between working-interest acreage and mineral-and-royalty-interest acreage can be significant, while overlap between the different types of mineral and royalty interests is not significant. The following table presents information about our mineral-and-royalty-interest and working-interest acreage by the resource plays we consider most material to our current and future business. These plays accounted for 70% of our aggregate production for the year ended December 31, 2017.



	Acreage as of December 31, 2017¹
	Mineral and Royalty Interests			Working Interests
Resource Play²	Mineral Interests	NPRIs	ORRIs	Gross	Net
Bakken Shale	366,359	40,022	15,450	55,220	7,239
Haynesville Shale	360,587	7,335	28,741	191,523	55,169
Three Forks	355,665	37,203	13,810	55,422	6,866
Bossier Shale	329,717	1,896	20,530	178,902	53,753
Wolfcamp — Midland	288,718	134,284	124,272	160	4
Marcellus Shale	246,542	—	13,467	—	—
Canyon Lime	226,149	—	—	—	—
Tuscaloosa Marine Shale	189,147	23,397	2,192	—	—
Wolfcamp — Delaware	137,759	38,021	6,403	2,642	1,291
Granite Wash	109,876	5,031	104,308	4,840	1,254
Fayetteville Shale	74,401	4,789	11,861	—	—
Eagle Ford Shale	67,478	107,019	49,613	1,147	87
Barnett Shale	61,788	4,164	37,633	13,417	7,747


¹	Excludes acreage for which we have incomplete seller records.


²	The plays above have been delineated based on information from the Energy Information Administration ("EIA"), the USGS, or state agencies, or according to areas of the most active industry development.

Interests by Resource Play

The following tables present information about our mineral-and-royalty-interest and non-operated working-interest acreage, and production by resource play. As with the acreage shown for the basins and regions above, we may own more than one type of interest in the same tract of land. Consequently, some of the acreage shown for one type of interest below may also be included in the acreage shown for another type of interest.

Mineral Interests

The following table sets forth information about our mineral interests:



	As of December 31, 2017					Average Daily Production (Boe/d) for the Year Ended December 31,
Resource Play¹	Acres	Average Ownership Interest²		Average Ownership Leased³		2017	2016	2015
Bakken Shale	366,359	17.2	%	76.6	%	1,877	1,659	1,746
Haynesville Shale	360,587	63.7	%	52.2	%	5,391	3,727	2,728
Three Forks	355,665	16.8	%	78.5	%	991	968	823
Bossier Shale	329,717	68.1	%	49.1	%	337	330	351
Wolfcamp — Midland	288,718	4.6	%	98.1	%	659	136	76
Marcellus Shale	246,542	14.4	%	26.9	%	118	111	71
Canyon Lime	226,149	30.5	%	30.2	%	67	16	8
Tuscaloosa Marine Shale	189,147	58.1	%	43.8	%	35	52	46
Wolfcamp — Delaware	137,759	9.7	%	97.0	%	785	437	148
Granite Wash	109,876	15.0	%	60.6	%	136	167	194
Fayetteville Shale	74,401	56.0	%	78.6	%	1,014	1,181	1,349
Eagle Ford Shale	67,478	14.1	%	85.4	%	1,743	2,095	2,355
Barnett Shale	61,788	15.8	%	57.2	%	172	181	239


¹	The plays above have been delineated based on information from the EIA, the USGS, or state agencies, or according to areas of the most active industry development.

Ownership interest is equal to the percentage that our undivided ownership interest in a tract bears to the entire tract. The per-play average ownership interests shown above reflect the weighted average of our ownership interests in all tracts in the play. Our weighted-average mineral royalty for all of our mineral interests is approximately 20%, which may be multiplied by our ownership interest to approximate the average royalty interest in our mineral and royalty interests.


³	The average percent leased reflects the weighted average of our leased acres relative to our total acreage on a tract-by-tract basis in the play.

NPRIs

The following table sets forth information about our NPRIs:



	As of December 31, 2017					Average Daily Production (Boe/d) for the Year Ended December 31,
Resource Play¹	Acres	Average Royalty Interest²		Average Percent Leased³		2017	2016	2015
Wolfcamp — Midland	134,284	0.7	%	82.8	%	25	11	22
Eagle Ford Shale	107,019	1.2	%	42.4	%	6	14	3
Bakken Shale	40,022	1.3	%	57.7	%	74	63	56
Wolfcamp — Delaware	38,021	0.6	%	86.7	%	7	4	1
Three Forks	37,203	1.2	%	61.3	%	37	36	50
Tuscaloosa Marine Shale	23,397	0.5	%	93.3	%	—	—	—
Haynesville Shale	7,335	4.2	%	96.1	%	443	167	325
Granite Wash	5,031	0.8	%	100.0	%	31	16	5
Fayetteville Shale	4,789	0.1	%	100.0	%	9	13	—
Barnett Shale	4,164	2.7	%	86.9	%	1	1	—
Bossier Shale	1,896	2.9	%	51.8	%	113	11	53
Canyon Lime	—	—		—		—	—	—
Marcellus Shale	—	—		—		—	—	—


¹	The plays above have been delineated based on information from the EIA, the USGS, or state agencies, or according to areas of the most active industry development.

Average royalty interest is equal to the weighted-average percentage of production or revenues (before operating costs) that we are entitled to on a tract-by-tract basis for the given area. NPRIs may be denominated as a “fractional royalty,” which entitles the owner to the stated fraction of gross production, or a “fraction of royalty,” where the stated fraction is multiplied by the lease royalty. In cases where our land documentation does not specify the form of NPRI, we have assumed a fractional royalty for purposes of the average royalty interests shown above.


³	The average percent leased reflects the weighted average of our leased acres relative to our total acreage on a tract-by-tract basis in the play.

ORRIs

The following table sets forth information about our ORRIs:



	As of December 31, 2017			Average Daily Production (Boe/d) for the Year Ended December 31,
Resource Play¹	Acres	Average Royalty Interest²		2017	2016	2015
Wolfcamp — Midland	124,272	0.4	%	31	<1	5
Granite Wash	104,308	1.6	%	72	155	115
Eagle Ford Shale	49,613	2.2	%	193	95	204
Barnett Shale	37,633	5.0	%	99	109	158
Haynesville Shale	28,741	4.9	%	383	686	1,111
Bossier Shale	20,530	5.7	%	8	28	57
Bakken Shale	15,450	1.3	%	32	34	41
Three Forks	13,810	1.3	%	25	21	27
Marcellus Shale	13,467	2.3	%	19	37	6
Fayetteville Shale	11,861	4.0	%	—	—	—
Wolfcamp — Delaware	6,403	2.1	%	4	—	—
Tuscaloosa Marine Shale	2,192	13.5	%	—	<1	—
Canyon Lime	—	—		—	—	—


¹	The plays above have been delineated based on information from the EIA, the USGS, or state agencies, or according to areas of the most active industry development.


²	Average royalty interest is equal to the weighted-average percentage of production or revenues (before operating costs) that we are entitled to on a tract-by-tract basis in this play.

Working Interests

The following table sets forth information about our working interests.



	As of December 31, 2017		Average Daily Production (Boe/d) for the Year Ended December 31,
Resource Play¹	Gross Acres²	Net Acres²	2017	2016	2015
Haynesville Shale	191,523	55,169	9,631	5,077	2,909
Bossier Shale	178,902	53,753	690	309	135
Three Forks	55,422	6,866	194	491	551
Bakken Shale	55,220	7,239	347	864	792
Barnett Shale	13,417	7,747	51	87	104
Granite Wash	4,840	1,254	283	429	537
Wolfcamp — Delaware	2,642	1,291	143	150	23
Eagle Ford Shale	1,147	87	—	76	11
Wolfcamp — Midland	160	4	2	1	—
Canyon Lime	—	—	14	—	—
Fayetteville Shale	—	—	—	23	—
Marcellus Shale	—	—	—	<1	—
Tuscaloosa Marine Shale	—	—	—	—	—


¹	The plays above have been delineated based on information from the EIA, the USGS, or state agencies, or according to areas of the most active industry development.


²	Excludes acreage that is not quantifiable due to incomplete seller records.

Estimated Proved Reserves

Evaluation and Review of Estimated Proved Reserves

The reserves estimates as of December 31, 2017, 2016, and 2015 shown herein have been independently evaluated by NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical person primarily responsible for preparing the estimates set forth in the NSAI summary reserves report incorporated herein is Mr. J. Carter Henson, Jr. Mr. Henson, a Licensed Professional Engineer in the State of Texas (License No. 73964), has been practicing consulting petroleum engineering at NSAI since 1989 and has over 8 years of prior industry experience. He graduated from Rice University in 1981 with Bachelor of Science Degree in Mechanical Engineering. As technical principal, Mr. Henson meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in judiciously applying industry standard practices to engineering evaluations as well as applying SEC and other industry reserves definitions and guidelines. NSAI does not own an interest in us or any of our properties, nor is it employed by us on a contingent basis. A copy of NSAI’s estimated proved reserve report as of December 31, 2017 is attached as an exhibit to this Annual Report.

We maintain an internal staff of petroleum engineers and geoscience professionals who worked closely with our third-party reserve engineers to ensure the integrity, accuracy, and timeliness of the data used to calculate our estimated proved reserves. Our internal technical team members met with our third-party reserve engineers periodically during the period covered by the above referenced reserve report to discuss the assumptions and methods used in the reserve estimation process. We provided historical information to the third-party reserve engineers for our properties, such as oil and natural gas production, well test data, realized commodity prices, and operating and development costs. We also provided ownership interest information with respect to our properties. Brock Morris, our Senior Vice President, Engineering and Geology, is primarily responsible for overseeing the preparation of all of our reserve estimates. Mr. Morris is a petroleum engineer with approximately 32 years of reservoir-engineering and operations experience.

Our historical proved reserve estimates were prepared in accordance with our internal control procedures. Throughout the year, our technical team met with NSAI to review properties and discuss evaluation methods and assumptions used in the proved reserves estimates, in accordance with our prescribed internal control procedures. Our internal controls over the reserves estimation process include verification of input data used in the reserves evaluation software as well as reviews by our internal engineering staff and management, which include the following:


•	Comparison of historical operating expenses from the lease operating statements to the operating costs input in the reserves database;


•	Review of working interests and net revenue interests in the reserves database against our well ownership system;


•	Review of historical realized commodity prices and differentials from index prices compared to the differentials used in the reserves database;


•	Evaluation of capital cost assumptions derived from Authority for Expenditure estimates received;


•	Review of actual historical production volumes compared to projections in the reserve report;


•	Discussion of material reserve variances among our internal reservoir engineers and our Senior Vice President, Engineering and Geology; and


•	Review of preliminary reserve estimates by our President and Chief Executive Officer with our internal technical staff.

Estimation of Proved Reserves

In accordance with rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” means deterministically, the quantities of oil and/or natural gas are much more likely to be achieved than not, and probabilistically, there should be at least a 90% probability of recovering volumes equal to or exceeding the estimate. All of our estimated proved reserves as of December 31, 2017, 2016, and 2015 are based on deterministic methods. Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by using reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

In order to establish reasonable certainty with respect to our estimated net proved reserves, NSAI employed technologies including, but not limited to, well logs, core analysis, geologic maps, and available down hole pressure and production data, seismic data, and well test data. Reserves attributable to producing wells with sufficient production history were estimated using appropriate decline curves or other performance relationships. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using performance from analogous wells in the surrounding area and geologic data to assess the reservoir continuity. In addition to assessing reservoir continuity, geologic data from well logs, core analyses, and seismic data were used to estimate original oil and natural gas in place.

Summary of Estimated Proved Reserves

Reserve estimates do not include any value for probable or possible reserves that may exist. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses, and quantities of recoverable oil and natural gas may vary substantially from these estimates.

The following table presents our estimated proved oil and natural gas reserves:



	As of December 31,
	2017¹		2016²		2015³
	(Unaudited)
Estimated proved developed reserves⁴:
Oil (MBbls)	17,891		18,150		15,497
Natural gas (MMcf)	233,017		223,057		174,555
Total (MBoe)	56,727		55,327		44,590
Estimated proved undeveloped reserves⁵:
Oil (MBbls)	8		218		345
Natural gas (MMcf)	67,257		47,282		29,120
Total (MBoe)	11,218		8,098		5,198
Estimated proved reserves:
Oil (MBbls)	17,899		18,368		15,842
Natural gas (MMcf)	300,274		270,339		203,675
Total (MBoe)	67,945		63,425		49,788
Percent proved developed	83.5	%	87.2	%	89.6	%

Estimates of reserves as of December 31, 2017, were prepared using oil and natural gas prices equal to the unweighted arithmetic average of the first-day-of-the-month market price for each month in the period from January through December 2017. For oil volumes, the average WTI spot oil price of $51.34 per barrel is used for estimates of reserves for all the properties as of December 31, 2017. This average price is adjusted for quality, transportation fees, and market differentials. For natural gas volumes, the average Henry Hub price of $2.98 per MMBTU is used for estimates of reserves for all the properties as of December 31, 2017. This average price is adjusted for energy content, transportation fees, and market differentials. Natural gas prices are also adjusted to account for NGL revenue since there is not sufficient data to account for NGL volumes separately in the reserve estimates. These reserve estimates exclude NGL quantities. When taking these adjustments into account, the average adjusted prices weighted by production over the remaining lives of the properties are $46.59 per barrel for oil and $2.70 per Mcf for natural gas as of December 31, 2017.

Estimates of reserves as of December 31, 2016 were prepared using oil and natural gas prices equal to the unweighted arithmetic average of the first-day-of-the-month market price for each month in the period January through December 2016. For oil volumes, the average WTI spot oil price of $42.75 per barrel is used for estimates of reserves for all the properties as of December 31, 2016. These average prices are adjusted for quality, transportation fees, and market differentials. For natural gas volumes, the average Henry Hub price of $2.48 per MMBTU is used for estimates of reserves for all the properties as of December 31, 2016. These average prices are adjusted for energy content, transportation fees, and market differentials. Natural gas prices are also adjusted to account for NGL revenue since there is not sufficient data to account for NGL volumes separately in the reserve estimates. These reserve estimates exclude NGL quantities. When taking these adjustments into account, the average adjusted prices weighted by production over the remaining lives of the properties are $37.50 per barrel for oil and $2.14 per Mcf for natural gas.

Estimates of reserves as of December 31, 2015 were prepared using oil and natural gas prices equal to the unweighted arithmetic average of the first-day-of-the-month market price for each month in the period January through December 2015. For oil volumes, the average WTI spot oil price of $50.28 per 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 of reserves for all the properties as of December 31, 2015. These average prices are adjusted for energy content, transportation fees, and market differentials. Natural gas prices are also adjusted to account for NGL revenue since there is not sufficient data to account for NGL volumes separately in the reserve estimates. These reserve estimates exclude NGL quantities. When taking these adjustments into account, the average adjusted gas price weighted by production over the remaining lives of the properties is $2.45 per Mcf.


⁴	Proved developed reserves of 61, 74, and 84 MBoe as of December 31, 2017, 2016, and 2015, respectively, were attributable to noncontrolling interests in our consolidated subsidiaries.


⁵	As of December 31, 2017, 2016, and 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 that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary for the same property. In addition, the results of drilling, testing, and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices, and future production rates and costs. Please read Part I, Item 1A. “Risk Factors.”

Additional information regarding our estimated proved reserves can be found in the notes to our consolidated financial statements included elsewhere in this Annual Report and the estimated proved reserve report as of December 31, 2017, which is included as an exhibit to this Annual Report.

Estimated Proved Undeveloped Reserves

As of December 31, 2017, our PUDs comprised 8 MBbls of oil and 67,257 MMcf of natural gas, for a total of 11,218 MBoe. PUDs will be converted from undeveloped to developed as the applicable wells begin production.

The following tables summarizes our changes in PUDs during the year ended December 31, 2017 (in MBoe):



	Estimated Proved Undeveloped Reserves
	(Unaudited)
As of December 31, 2016	8,098
Acquisitions of reserves	920
Divestiture of reserves	(672	)
Extensions and discoveries	4,564
Revisions of previous estimates	945
Transfers to estimated proved developed	(2,637	)
As of December 31, 2017	11,218

New PUD reserves totaling 4,564 MBoe were added during the year ended December 31, 2017, resulting from development activities in the Haynesville/Bossier play. There were 920 MBoe of PUD reserves acquired in the Haynesville/Bossier play. This was partially offset by the divestiture of 672 MBoe of PUD reserves associated with the farmouts to Canaan and to Pivotal.

During the year ended December 31, 2017, we had reductions of 127 Mboe PUD reserves, primarily as a result of updated operator information. This was offset by increases in previous estimates of 1,072 Mboe based on performance from offset and analog production. This resulted in a total upward revision of 945 Mboe comprised of an increase of 5,831 MMcf natural gas reserves and a decrease of 27 Mbbl of oil reserves.

Costs incurred relating to the development of locations that were classified as PUDs at December 31, 2016 were $29.3 million during the year ended December 31, 2017. Additionally, during the year ended December 31, 2017, we incurred $26.7 million drilling and completing other wells which were not classified as PUDs as of December 31, 2016. Estimated future development costs relating to the development of PUD reserves at December 31, 2017 are projected to be approximately $20.5 million. All of our PUD drilling locations as of December 31, 2017 are scheduled to be drilled within five years or 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 limited to those relatively few locations for which we have received and approved an authorization for expenditure and which remained undrilled as of December 31, 2017. As of December 31, 2017, approximately 16.5% of our total proved reserves were classified as PUDs.

Oil and Natural Gas Production Prices and Production Costs

Production and Price History

For the year ended December 31, 2017, 26.3% of our production and 47.1% of our oil and natural gas revenues were related to oil and condensate production and sales, respectively. During the same period, natural gas and NGL sales were 73.7% of our production and 52.9% of our oil and natural gas revenues.

The following table sets forth information regarding production of oil and natural gas and certain price and cost information for each of the periods indicated:



	Year Ended December 31,
	2017		2016		2015
Production:
Oil and condensate (MBbls)¹	3,552		3,680		3,565
Natural gas (MMcf)¹	59,779		47,498		41,389
Total (MBoe)	13,515		11,596		10,463
Average daily production (MBoe/d)	37.0		31.7		28.7
Realized Prices²:
Oil and condensate (per Bbl)	$	47.78	$	38.69	$	45.87
Natural gas and natural gas liquids (per Mcf)¹	$	3.19	$	2.59	$	2.80
Unit Cost per Boe:
Production costs and ad valorem taxes	$	3.51	$	3.06	$	3.42

As a mineral-and-royalty interest owner, we are often provided insufficient and inconsistent data by our operators related to NGLs. As a result, we are unable to reliably determine the total volumes of NGLs associated with the production of natural gas on our acreage. As such, the realized prices for natural gas account for all value attributable to NGLs. The oil and condensate production volumes and natural gas production volumes do not include NGL volumes.


²	Excludes the effect of commodity derivative instruments.

Productive Wells

Productive wells consist of producing wells, wells capable of production, and exploratory, development, or extension wells that are not dry wells. As of December 31, 2017, we owned mineral and royalty interests or working interests in 61,443 productive wells, which consisted of 38,112 oil wells and 23,331 natural gas wells. As of December 31, 2017, we owned mineral and royalty interests in 55,728 productive wells, which consisted of 37,189 oil wells and 18,539 natural gas wells, and working interests in 9,688 gross productive wells and 352 net productive wells, which consisted of 3,693 gross (65 net) productive oil wells and 5,995 gross (287 net) productive natural gas wells. We own both mineral and royalty interests and working interests in 3,973 of these wells.

Acreage

Mineral and Royalty Interests

The following table sets forth information relating to our acreage for our mineral interests as of December 31, 2017:



State	Developed Acreage	Undeveloped Acreage	Total Acreage
Texas	342,912	4,717,981	5,060,893
Oklahoma	116,555	458,278	574,833
Louisiana	35,259	498,331	533,590
Montana	20,844	545,925	566,769
North Dakota	18,016	1,141,046	1,159,062
Arkansas	4,887	1,274,169	1,279,056
Mississippi	4,576	2,403,176	2,407,752
Alabama	2,859	2,057,740	2,060,599
Nevada	—	792,588	792,588
Florida	—	743,452	743,452
Other	82,555	1,532,785	1,615,340
Total	628,463	16,165,471	16,793,934

The following table sets forth information relating to our acreage for our NPRIs as of December 31, 2017:



State	Developed Acreage	Undeveloped Acreage	Total Acreage
Texas	203,805	1,104,471	1,308,276
Oklahoma	6,976	5,829	12,805
Louisiana	10,508	86,521	97,029
Montana	11,684	172,876	184,560
North Dakota	20,100	20,898	40,998
Arkansas	3,974	30,122	34,096
Mississippi	10,533	137,299	147,832
Wyoming	1,360	17,160	18,520
New Mexico	14,289	960	15,249
Kansas	9,042	2,983	12,025
Other	367	3,926	4,293
Total	292,638	1,583,045	1,875,683

The following table sets forth information relating to our acreage for our ORRIs as of December 31, 2017:



State	Developed Acreage	Undeveloped Acreage	Total Acreage
Texas	289,062	243,733	532,795
Oklahoma	142,300	94,240	236,540
Louisiana	15,907	93,997	109,904
Montana	295,401	183,588	478,989
Wyoming	133,461	100,516	233,977
New Mexico	46,151	19,240	65,391
Utah	40,510	153,317	193,827
Michigan	55,272	1,239	56,511
Colorado	27,108	23,647	50,755
Alaska	7,664	16,550	24,214
Other	75,808	36,794	112,602
Total	1,128,644	966,861	2,095,505

Working Interests

The following table sets forth information relating to our acreage for our non-operated working interests as of December 31, 2017:



	Developed Acreage		Undeveloped Acreage		Total Acreage
State	Gross	Net	Gross	Net	Gross	Net
Texas	206,581	55,208	140,227	43,234	346,808	98,442
Louisiana	41,683	4,638	14,662	2,812	56,345	7,450
North Dakota	48,510	6,505	7,565	793	56,075	7,298
Wyoming	22,210	4,161	4,902	994	27,112	5,155
Michigan	13,208	1,330	79	—	13,287	1,330
Oklahoma	11,623	3,030	10	3	11,633	3,033
Colorado	7,725	2,601	—	—	7,725	2,601
Kansas	6,480	6,213	921	—	7,401	6,213
New Mexico	6,238	3,622	160	80	6,398	3,702
South Dakota	2,160	504	880	55	3,040	559
Other	6,436	2,127	1,210	274	7,646	2,401
Total	372,854	89,939	170,616	48,245	543,470	138,184

The following table lists the net undeveloped acres, the net acres expiring in the years ending December 31, 2018, 2019, and 2020, and, where applicable, the net acres expiring that are subject to extension options:



	2018 Expirations		2019 Expirations		2020 Expirations
Net Undeveloped Acreage	Net Acreage without Ext. Opt.	Net Acreage with Ext. Opt.	Net Acreage without Ext. Opt.	Net Acreage with Ext. Opt.	Net Acreage without Ext. Opt.	Net Acreage with Ext. Opt.
48,245	13,828	9	2,328	300	1,355	582

Drilling Results for Our Working Interests

The following table sets forth information with respect to the number of wells completed on our properties during the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled, the quantities of reserves found, and the economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return.



	Year Ended December 31,
	2017	2016	2015
Gross development wells:
Productive	23.0	47.0	74.0
Dry	—	—	1.0
Total	23.0	47.0	75.0
Net development wells:
Productive	6.1	4.7	2.9
Dry	—	—	<0.1
Total	6.1	4.7	2.9

For the years ended December 31, 2017, 2016, and 2015, we did not have any productive or dry exploratory wells on a gross or net basis. As of December 31, 2017, we had 20 wells in the process of drilling, completing or dewatering, or shut in awaiting infrastructure that are not reflected in the above table.

Environmental Matters

Oil and natural gas exploration, development, and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. These laws and regulations have the potential to impact production on our properties, which could materially adversely affect our business and our prospects. Numerous federal, state, and local governmental agencies, such as the U.S. Environmental Protection Agency (“EPA”), issue regulations that often require compliance measures that carry substantial administrative, civil, and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities, and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive, and other protected areas, require action to prevent, or remediate pollution from current or historic operations, such as plugging abandoned wells or closing earthen pits, result in the suspension or revocation of necessary permits, licenses, and authorizations, require that additional pollution controls be installed, and impose substantial liabilities for pollution resulting from operations. The strict, joint, and several liability nature of such laws and regulations could impose liability upon our operators, or us as working-interest owners if the operator fails to perform, regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons, or other waste products into the environment. In addition, many environmental statues contain citizen suit provisions, and environmental groups frequently use these provisions to oppose oil and natural gas exploration and development activities and related projects. The long-term trend in environmental regulation has been towards more stringent regulations, and any changes that impact our operators and result in more stringent and costly pollution control or waste handling, storage, transport, disposal, or cleanup requirements could materially adversely affect our business and prospects. Below is a summary of environmental laws applicable to operations on our properties.

Waste Handling

The Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development, and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal, and cleanup of hazardous and non- hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development, and production of oil and natural gas are exempt from regulation as hazardous wastes under RCRA, these wastes typically constitute “solid wastes” that are subject to less stringent non-hazardous waste requirements. However, it is possible that RCRA could be amended or the EPA or state environmental agencies could adopt policies to require oil and natural gas exploration, development, and production wastes to become subject to more stringent waste handling requirements. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and natural gas wastes from regulation as hazardous wastes under RCRA. The consent decree requires EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and natural gas wastes or to sign a determination that revision of the regulations is not necessary. Pursuant to the consent decree, EPA must complete any revisions to RCRA's Subtitle D regulations by 2021. Removal of RCRA’s exemption for exploration and production wastes has the potential to significantly increase waste disposal costs, which in turn will result in increased operating costs and could adversely impact production on our properties. Administrative, civil, and criminal penalties can be imposed for failure to comply with waste handling requirements. Any changes in the laws and regulations could have a material adverse effect on our operators’ capital expenditures and operating expenses, which in turn could affect production from our properties and adversely affect our business and prospects.

Remediation of Hazardous Substances

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, and analogous state laws generally impose strict, joint, and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility (which can include working-interest owners), a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” may be subject to strict and joint and several liability for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and

property damage allegedly caused by the hazardous substances released into the environment. Oil and natural gas exploration and production activities on our properties use materials that, if released, would be subject to CERCLA and comparable state statutes. Therefore, governmental agencies or third parties may seek to hold our operators, or us as working-interest owners if the operator fails to perform, responsible under CERCLA and comparable state statutes for all or part of the costs to clean-up sites at which these “hazardous substances” have been released.

Water Discharges

The Federal Water Pollution Control Act of 1972, also known as the “Clean Water Act” (“CWA”), the Safe Drinking Water Act (“SDWA”), the Oil Pollution Act (“OPA”), and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. In June 2015, the EPA and the U.S. Army Corps of Engineers (the “Corps”) published a final rule attempting to clarify the federal jurisdictional reach over waters of the United States, but legal challenges to this rule followed and the rule was stayed nationwide by the U.S. Sixth Circuit Court of Appeals in October 2015 pending resolution of the court challenges. In January 2017, the U.S. Supreme Court accepted review of the rule to determine whether jurisdiction rests with the federal district or appellate courts. Additionally, following the issuance of a presidential executive order to review the rule, the EPA and the Corps proposed a rulemaking to repeal the June 2015 rule in June 2017. The EPA and Corps also announced their intent to issue a new rule defining the CWA’s jurisdiction. In January 2018, the U.S. Supreme Court held that jurisdiction to hear challenges to the rule rests with federal district courts. In addition, the EPA has proposed to stay implementation of the June 2015 rule during the rulemaking process for the repeal. All of the actions of the EPA and the Corps are subject to legal challenge. As a result, future implementation of the June 2015 rule is uncertain at this time. To the extent this rule or a revised rule expands the scope of the CWA’s jurisdiction, operations on our properties could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas in connection with any expansion activities. In addition, spill prevention, control, and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture, or leak. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges.

The OPA is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint, and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil into surface waters.

In addition, while the SDWA, generally excludes hydraulic fracturing from the definition of underground injection, it does not exclude hydraulic fracturing involving the use of diesel fuels. In 2014, the EPA published draft permitting guidance governing hydraulic fracturing with diesel fuels. While our operators do not use diesel fuels in their hydraulic fracturing fluids, they may become subject to federal permitting under SDWA if their fracturing formula changes. In addition, the SDWA grants the EPA broad authority to take action to protect public health when an underground source of drinking water is threatened with pollution that presents an imminent and substantial endangerment to humans, which could result in orders prohibiting or limiting the operations of oil and natural gas production facilities. Moreover, the SDWA also regulates saltwater disposal wells under the Underground Injection Control Program. Recent concerns related to the operation of saltwater disposal wells and induced seismicity have led some states to impose limits on the total volume of produced water such wells can dispose of, order disposal wells to cease operations, or limited the construction of new wells. These seismic events have also resulted in environmental groups and local residents filing lawsuits against operators in areas where the events occur seeking damages and injunctions limiting or prohibiting saltwater disposal well construction activities and operations. A lack of saltwater disposal wells in production areas could result in increased disposal costs for our operators if they are forced to transport produced water by truck, pipeline, or other method over long distances, or force them to curtail operations.

Noncompliance with the Clean Water Act, SDWA, or the OPA may result in substantial administrative, civil, and criminal penalties, as well as injunctive obligations, all of which could affect production from our properties and adversely affect our business and prospects.

Air Emissions

The federal Clean Air Act and comparable state laws and regulations regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, in August 2012, the EPA adopted new regulations under the Clean Air Act that established new emission control requirements for oil and natural gas production and processing operations. In addition, in October 2015, the EPA lowered the National Ambient Air Quality Standard, (“NAAQS”) for ozone from 75 to 70 parts per billion for both the 8- hour primary and secondary standards. The EPA is still in the process of designating the attainment status of air quality areas with the new ozone NAAQS, but has stated that the agency intends to complete the process during the first half of 2018. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit the ability of our operators to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. More recently, in June 2016, the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and natural gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements. These laws and regulations may increase the costs of compliance for oil and natural gas producers and impact production on our properties, and federal and state regulatory agencies can impose administrative, civil, and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. Moreover, obtaining or renewing permits has the potential to delay the development of oil and natural gas exploration and development projects. All of these factors could impact production on our properties and adversely affect our business and results of operations.

Climate Change

In response to findings that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, require preconstruction and operating permits for certain large stationary sources. Facilities required to obtain preconstruction permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established on a case-by-case basis. These EPA rulemakings could adversely affect operations on our properties and restrict or delay the ability of our operators to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis, which include gathering and boosting facilities as well as GHG emissions from completions and workovers of hydraulically fractured wells. Also, in June 2016, the EPA finalized rules that establish new air emission controls for methane emissions from certain new, modified or reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities. However, in June 2017, the EPA proposed to stay the requirements for a period of two years and revisit implementation of the federal methane rules in their entirety. Several states, including Colorado, where we hold interests, have also adopted rules to control and minimize methane emissions from the production of oil and natural gas. Moreover, in response to public concerns regarding methane emissions, many operators have recently voluntarily agreed to implement methane controls with respect to their operations. State and existing federal methane rules have substantial similarities with respect to pollution control equipment and leak detection and repair (“LDAR”) requirements. These rules could result in increased compliance costs for our operators and require them to make expenditures to purchase pollution control equipment and hire additional personnel to assist with complying with LDAR requirements, such as increased frequency of inspections and repairs for certain processes and equipment. Consequently, these and other regulations related to controlling GHG emissions could have an adverse impact on production on our properties, our business, and results of operations.

effects of climate change have directed their attention at sources of funding for energy companies, which has resulted in certain financial institutions, funds, and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult for operators on our properties to secure funding for exploration and production activities. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and gas will continue to represent a substantial percentage of global energy use over that time. Exploration and production activities are capital intensive, and capital constraints of our operators could have a material adverse impact on production from our properties. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts, and other extreme climatic events; if any of these effects were to occur, they could have a material adverse effect on our properties and operations.

Hydraulic Fracturing

Our operators engage in hydraulic fracturing. Hydraulic fracturing is a common practice that is used to stimulate production of hydrocarbons from tight formations, including shales. The process involves the injection of water, sand, and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and natural gas commissions, but recently the EPA and other federal agencies have asserted jurisdiction over certain aspects of hydraulic fracturing. For example, the EPA has issued final regulations under the federal Clean Air Act governing performance standards, including standards for the capture of air released during hydraulic fracturing; finalized effluent limitation guidelines in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants; and issued in May 2014 an Advanced Notice of Proposed Rulemaking (“ANPRM”) seeking comment on its intent to develop regulations under the Toxic Substances Control Act (“TSCA”) to require companies to disclose information regarding the chemicals used in hydraulic fracturing. However, no further action has been taken by EPA with respect to the TSCA ANPRM and additional federal regulation of hydraulic fracturing is uncertain at this time.

In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals, or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. The EPA has not proposed to take any action in response to the report’s findings.

Several states where we own interests in oil and gas producing properties, including Colorado, North Dakota, Louisiana, Oklahoma, and Texas, have adopted regulations that could restrict or prohibit hydraulic fracturing in certain circumstances or require the disclosure of the composition of hydraulic-fracturing fluids. For example, in Texas, the Texas Railroad Commission (“RRC”) published a final rule in October 2014 governing permitting or re-permitting of disposal wells that requires, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections, and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the RRC may deny, modify, suspend, or terminate the permit application or existing operating permit for that well. These existing or any new legal requirements establishing seismic permitting requirements or similar restrictions on the construction or operation of disposal wells for the injection of produced water likely will result in added costs to comply and affect our operators’ rate of production, which in turn could have a material adverse effect on our results of operations and financial position. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general or hydraulic fracturing in particular. In the event state, local, or municipal legal restrictions are adopted in areas where our operators conduct operations, our operators may incur substantial costs to comply with these requirements, which may be significant in nature, experience delays, or curtailment in the pursuit of exploration, development, or production activities and perhaps even be precluded from the drilling of wells.

There has been increasing public controversy regarding hydraulic fracturing with regard to increased risks of induced seismicity, the use of fracturing fluids, impacts on drinking water supplies, use of water, and the potential for impacts to surface water, groundwater, and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic-fracturing practices. If new laws or regulations are adopted that significantly restrict hydraulic fracturing, those laws could make it more difficult or costly for our operators to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing is further regulated at the federal or state level, fracturing activities on our properties could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements, and also to attendant permitting delays and potential increases in costs. Legislative changes could cause operators to incur substantial compliance costs. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.

Occupational Safety and Health Act

The Occupational Safety and Health Act (“OSHA”) and comparable state laws and regulations govern the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard, the Emergency Planning and Community Right to Know Act and implementing regulations, and similar state statutes and regulations require that information be maintained about hazardous materials used or produced in operations on our properties and that this information be provided to employees, state and local government authorities, and citizens.

Endangered Species

The Endangered Species Act (“ESA”) and analogous state laws restrict activities that may affect endangered or threatened species or their habitats. Pursuant to a settlement with environmental groups, the U.S. Fish and Wildlife Service (“USFWS”) was required to determine whether over 250 species required listing as threatened or endangered under the ESA. USFWS has not yet completed its review, but the potential remains for new species to be listed under the ESA. Some of our properties may be located in areas that are or may be designated as habitats for endangered or threatened species, and previously unprotected species may later be designated as threatened or endangered in areas where we hold mineral interests. This could cause our operators to incur increased costs arising from species protection measures, delay the completion of exploration and production activities, and/or result in limitations on operating activities that could have an adverse impact on our business.

Title to Properties

Prior to completing an acquisition of oil and natural gas properties, we perform title reviews on high-value tracts. Our title reviews are meant to confirm quantum of oil and natural gas properties being acquired, lease status, and royalties as well as encumbrances and other related burdens. Depending on the materiality of properties, we may obtain a title opinion if we believe additional title due diligence is necessary. As a result, title examinations have been obtained on a significant portion of our properties. After an acquisition, we review the assignments from the seller for scrivener’s and other errors and execute and record corrective assignments as necessary.

In addition to our initial title work, our operators conduct a thorough title examination prior to leasing and drilling a well. Should our operators’ title work uncover any title defects, either we or our operators will perform curative work with respect to such defects. Our operators generally will not commence drilling operations on a property until any material title defects on such property have been cured.

We believe that the title to our assets is satisfactory in all material respects. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions, and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens, and encumbrances will materially detract from the value of these properties or from our interest in these properties or materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects.

Marketing and Major Customers

If we were to lose a significant customer, such loss could impact revenue derived from our mineral-and-royalty-interest or working-interest properties. The loss of any single lessee is mitigated by our diversified customer base. The following table indicates our significant customers that accounted for 10% or more of our total revenues for the periods indicated:


*	Accounted for less than 10% of total revenues for the period indicated.

Competition

The oil and natural gas business is highly competitive in the exploration for and acquisition of reserves, the acquisition of minerals and oil and natural gas leases, and personnel required to find and produce reserves. Many companies not only explore for and produce oil and natural gas, but also conduct midstream and refining operations and market petroleum and other products on a regional, national, or worldwide basis. Certain of our competitors may possess financial or other resources substantially larger than we possess. Our ability to acquire additional minerals and properties and to discover reserves in the future will be dependent upon our ability to identify and evaluate suitable acquisition prospects and to consummate transactions in a highly competitive environment. Oil and natural gas products compete with other sources of energy available to customers, primarily based on price. These alternate sources of energy include coal, nuclear, solar, and wind. Changes in the availability or price of oil and natural gas or other sources of energy, as well as business conditions, conservation, legislation, regulations, and the ability to convert to alternate fuels and other sources of energy may affect the demand for oil and natural gas.

Seasonal Nature of Business

Weather conditions affect the demand for, and prices of, natural gas and can also delay drilling activities, disrupting our overall business plans. Demand for natural gas is typically higher during the winter, resulting in higher natural gas prices for our natural gas production during our first and fourth quarters. Certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal weather conditions can limit drilling and producing activities and other oil and natural gas operations in a portion of our operating areas. Due to these seasonal fluctuations, our results of operations for individual quarterly periods may not be indicative of the results that we may realize on an annual basis.

Employees

We are managed and operated by the board of directors and executive officers of our general partner. All of our employees, including our executive officers, are employees of Black Stone Natural Resources Management Company (“Black Stone Management”). As of December 31, 2017, Black Stone Management had 113 full-time employees. None of Black Stone Management’s employees are represented by labor unions or covered by any collective bargaining agreements.

Facilities

Our principal office location is in Houston, Texas and consists of 55,862 square feet of leased space.

ITEM 1A. Risk Factors

Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. If any of the following risks were to occur, our financial condition, results of operations, cash flows, and ability to make distributions could be materially adversely affected. In that case, we might not be able to make distributions on our common units, the trading price of our common units could decline, and holders of our units could lose all or part of their investment.

Risks Related to Our Business

We may not generate sufficient cash from operations after establishment of cash reserves to pay the minimum quarterly distribution on our common and subordinated units. If we make distributions, the holders of our Series B cumulative convertible preferred units have priority with respect to rights to share in those distributions over our common and subordinated unitholders for so long as our Series B cumulative convertible preferred units are outstanding.

We may not generate sufficient cash from operations each quarter to pay the full minimum quarterly distribution to our common and subordinated unitholders. Our Series B preferred unitholders have priority with respect to rights to share in distributions over our common and subordinated unitholders for so long as our Series B cumulative convertible preferred units are outstanding. Furthermore, our partnership agreement does not require us to pay distributions to our common and subordinated unitholders on a quarterly basis or otherwise. The amount of cash to be distributed each quarter will be determined by the board of directors of our general partner.

The amount of cash we have to distribute each quarter principally depends upon the amount of revenues we generate, which are largely dependent upon the prices that our operators realize from the sale of oil and natural gas. The actual amount of cash we will have to distribute each quarter will be reduced by principal and interest payments on our outstanding debt, working-capital requirements, and other cash needs. In addition, we may restrict distributions, in whole or in part, to fund replacement capital expenditures, acquisitions, and participation in working interests. If over the long term we do not retain cash for replacement capital expenditures in amounts necessary to maintain our asset base, a portion of future distributions will represent distribution of our assets and the value of our common units could be adversely affected. Withholding cash for our capital expenditures may have an adverse impact on the cash distributions in the quarter in which amounts are withheld.

For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read Part II, Item 5. “Market for Registrant’s Common Equity, Related Unitholder Matters, and Issuer Purchases of Equity Securities — Cash Distribution Policy.”

The amount of cash we distribute to holders of our units depends primarily on our cash generated from operations and not our profitability, which may prevent us from making cash distributions during periods when we record net income.

The amount of cash we distribute depends primarily upon our cash generated from operations and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods in which we record net losses for financial accounting purposes and may be unable to make cash distributions during periods in which we record net income.

The volatility of oil and natural gas prices due to factors beyond our control greatly affects our financial condition, results of operations, and cash distributions to unitholders.

Our revenues, operating results, cash distributions to unitholders, and the carrying value of our oil and natural gas properties depend significantly upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty, and a variety of additional factors that are beyond our control, including:


•	the domestic and foreign supply of and demand for oil and natural gas;


•	market expectations about future prices of oil and natural gas;


•	the level of global oil and natural gas exploration and production;


•	the cost of exploring for, developing, producing, and delivering oil and natural gas;


•	the price and quantity of foreign imports;


•	political and economic conditions in oil producing regions, including the Middle East, Africa, South America, and Russia;


•	the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;


•	trading in oil and natural gas derivative contracts;


•	the level of consumer product demand;


•	weather conditions and natural disasters;


•	technological advances affecting energy consumption;


•	domestic and foreign governmental regulations and taxes;


•	the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East;


•	the proximity, cost, availability, and capacity of oil and natural gas pipelines and other transportation facilities;


•	the price and availability of alternative fuels; and


•	overall domestic and global economic conditions.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. The table below demonstrates such volatility for the periods presented.



	Year Ended December 31, 2017				During the Five Years Prior to 2018				As of December 31,
	High		Low		High¹		Low²		2017		2016		2015
WTI Light sweet crude oil ($/Bbl)	$	60.46	$	42.48	$	110.62	$	26.19	$	60.46	$	53.75	$	37.13
Henry Hub spot market price of natural gas ($/MMBtu)	$	3.71	$	2.44	$	8.15	$	1.49	$	3.69	$	3.71	$	2.28


¹	High prices for WTI and Henry Hub were in 2013 and 2014, respectively


²	Low prices for WTI and Henry Hub were in 2016

Any prolonged substantial decline in the price of oil and natural gas will likely have a material adverse effect on our financial condition, results of operations, and cash distributions to unitholders. We may use various derivative instruments in connection with anticipated oil and natural gas sales to minimize the impact of commodity price fluctuations. However, we cannot always hedge the entire exposure of our operations from commodity price volatility. To the extent we do not hedge against commodity price volatility, or our hedges are not effective, our results of operations and financial position may be diminished.

In addition, lower oil and natural gas prices may also reduce the amount of oil and natural gas that can be produced economically by our operators. This scenario may result in our having to make substantial downward adjustments to our estimated proved reserves, which could negatively impact our borrowing base and our ability to fund our operations. If this occurs or if production estimates change or exploration or development results deteriorate, successful efforts method of accounting principles may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. Our operators could also determine during periods of low commodity prices to shut in or curtail production from wells on our properties. In addition, they could determine during periods of low commodity prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, they may abandon any well if they reasonably believe that the well can no longer produce oil or natural gas in commercially paying quantities.

Oil prices are expected to remain depressed for the foreseeable future as compared to historical highs. Approximately 47.1% of our 2017 oil and natural gas revenues were derived from oil and condensate sales. Any additional decreases in prices of oil may adversely affect our cash generated from operations, results of operations, financial position, and our ability to pay the minimum quarterly distribution on all of our outstanding common and subordinated units, perhaps materially.

The spot WTI market price at Cushing, Oklahoma has declined from $98.17 per Bbl on December 31, 2013 to $60.46 per Bbl on December 31, 2017. The reduction in price has been caused by many factors, including substantial increases in U.S. oil production from unconventional (shale) reservoirs, with limited increases in demand. If prices for oil are depressed for an

extended period of time or there are future declines, we may be required to write down the value of our oil and natural gas properties in addition to impairments taken during 2015 and 2016, and some of our undeveloped locations may no longer be economically viable. In addition, sustained low prices for oil may negatively impact the value of our estimated proved reserves and the amount that we are allowed to borrow under our bank credit facility and reduce the amounts of cash we would otherwise have available to pay expenses, fund capital expenditures, make distributions to our unitholders, and service our indebtedness.

Natural gas prices are expected to remain depressed for the foreseeable future as compared to historical highs. Approximately 52.9% of our 2017 oil and natural gas revenues were derived from natural gas and natural gas liquids sales. Any future decreases in prices of natural gas may adversely affect our cash generated from operations, results of operations, financial position, and our ability to pay the minimum quarterly distribution on all of our outstanding common and subordinated units, perhaps materially.

During the ten years prior to 2018, natural gas prices at Henry Hub have ranged from a high of $13.31 per MMBtu in 2008 to a low of $1.49 per MMBtu in 2016. On December 31, 2017, the Henry Hub spot market price of natural gas was $3.69 per MMBtu. The reduction in prices has been caused by many factors, including increases in natural gas production from unconventional (shale) reservoirs, without an offsetting increase in demand. The expected increase in natural gas production, based on reports from the EIA, could cause the prices for natural gas to remain at current levels or fall to lower levels. If prices for natural gas are depressed for an extended period of time or there are future declines, we may be required to further write down the value of our oil and natural gas properties in addition to impairments taken during 2015 and 2016, and some of our undeveloped locations may no longer be economically viable. In addition, sustained low prices for natural gas may negatively impact the value of our estimated proved reserves and the amount that we are allowed to borrow under our bank credit facility and reduce the amounts of cash we would otherwise have available to pay expenses, make distributions to our unitholders, and service our indebtedness.

Our failure to successfully identify, complete, and integrate acquisitions could adversely affect our growth, results of operations, and cash distributions to unitholders.

We depend partly on acquisitions to grow our reserves, production, and cash generated from operations. Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic data, and other information, the results of which are often inconclusive and subject to various interpretations. The successful acquisition of properties requires an assessment of several factors, including:


•	recoverable reserves;


•	future oil and natural gas prices and their applicable differentials;


•	development plans;


•	operating costs; and


•	potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain and we may not be able to identify attractive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections may not always be performed on every well, if applicable, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.

There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain financing. In addition, compliance with regulatory requirements may impose substantial additional obligations on our operators, causing them to expend additional time and resources in compliance activities, and potentially increase our operators’ exposure to penalties or fines for non-compliance with additional legal requirements. Further, the process of integrating acquired assets may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources.

No assurance can be given that we will be able to identify suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms, or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully, or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition, results of operations, and cash distributions to unitholders. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our growth, results of operations, and cash distributions to unitholders.

Any acquisitions of additional mineral and royalty interests that we complete will be subject to substantial risks.

Even if we do make acquisitions that we believe will increase our cash generated from operations, these acquisitions may nevertheless result in a decrease in our cash distributions per unit. Any acquisition involves potential risks, including, among other things:


•	the validity of our assumptions about estimated proved reserves, future production, prices, revenues, capital expenditures, operating expenses, and costs;


•	a decrease in our liquidity by using a significant portion of our cash generated from operations or borrowing capacity to finance acquisitions;


•	a significant increase in our interest expense or financial leverage if we incur debt to finance acquisitions;


•	the assumption of unknown liabilities, losses, or costs for which we are not indemnified or for which any indemnity we receive is inadequate;


•	mistaken assumptions about the overall cost of equity or debt;


•	our ability to obtain satisfactory title to the assets we acquire;


•	an inability to hire, train, or retain qualified personnel to manage and operate our growing business and assets; and


•	the occurrence of other significant changes, such as impairment of oil and natural gas properties, goodwill or other intangible assets, asset devaluation, or restructuring charges.

We depend on various unaffiliated operators for all of the exploration, development, and production on the properties underlying our mineral and royalty interests and non-operated working interests. Substantially all of our revenue is derived from the sale of oil and natural gas production from producing wells in which we own a royalty interest or a non-operated working interest. A reduction in the expected number of wells to be drilled on our acreage by these operators or the failure of our operators to adequately and efficiently develop and operate our acreage could have an adverse effect on our results of operations.

Our assets consist of mineral and royalty interests and non-operated working interests. For the year ended December 31, 2017, we received revenue from over 1,000 operators. The failure of our operators to adequately or efficiently perform operations or an operator’s failure to act in ways that are in our best interests could reduce production and revenues. Our operators are often not obligated to undertake any development activities other than those required to maintain their leases on our acreage. In the absence of a specific contractual obligation, any development and production activities will be subject to their reasonable discretion. Our operators could determine to drill and complete fewer wells on our acreage than is currently expected. The success and timing of drilling and development activities on our properties, and whether the operators elect to drill any additional wells on our acreage, depends on a number of factors that will be largely outside of our control, including:


•	the capital costs required for drilling activities by our operators, which could be significantly more than anticipated;


•	the ability of our operators to access capital;


•	prevailing commodity prices;


•	the availability of suitable drilling equipment, production and transportation infrastructure, and qualified operating personnel;


•	the operators’ expertise, operating efficiency, and financial resources;


•	approval of other participants in drilling wells;


•	the operators’ expected return on investment in wells drilled on our acreage as compared to opportunities in other areas;


•	the selection of technology;


•	the selection of counterparties for the marketing and sale of production; and


•	the rate of production of the reserves.

The operators may elect not to undertake development activities, or may undertake these activities in an unanticipated fashion, which may result in significant fluctuations in our results of operations and cash distributions to our unitholders. Sustained reductions in production by the operators on our properties may also adversely affect our results of operations and cash distributions to unitholders.

We may experience delays in the payment of royalties and be unable to replace operators that do not make required royalty payments, and we may not be able to terminate our leases with defaulting lessees if any of the operators on those leases declare bankruptcy.

A failure on the part of the operators to make royalty payments gives us the right to terminate the lease, repossess the property, and enforce payment obligations under the lease. If we repossessed any of our properties, we would seek a replacement operator. However, we might not be able to find a replacement operator and, if we did, we might not be able to enter into a new lease on favorable terms within a reasonable period of time. In addition, the outgoing operator could be subject to a proceeding under title 11 of the United States Code (the “Bankruptcy Code”), in which case our right to enforce or terminate the lease for any defaults, including non-payment, may be substantially delayed or otherwise impaired. In general, in a proceeding under the Bankruptcy Code, the bankrupt operator would have a substantial period of time to decide whether to ultimately reject or assume the lease, which could prevent the execution of a new lease or the assignment of the existing lease to another operator. In the event that the operator rejected the lease, our ability to collect amounts owed would be substantially delayed, and our ultimate recovery may be only a fraction of the amount owed or nothing. In addition, if we are able to enter into a new lease with a new operator, the replacement operator may not achieve the same levels of production or sell oil or natural gas at the same price as the operator it replaced.

Acquisitions, funding our working-interest participation program, and our operators’ development activities of our leases will require substantial capital, and we and our operators may be unable to obtain needed capital or financing on satisfactory terms or at all.

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in connection with the acquisition of mineral and royalty interests and participation in our working-interest participation program. To date, we have financed capital expenditures primarily with funding from cash generated by operations, limited borrowings under our credit facility, executed farmout agreements, and the issuance of equity securities.

In the future, we may restrict distributions to fund acquisitions and participation in our working interests but eventually we may need capital in excess of the amounts we retain in our business or borrow under our credit facility. We cannot assure you that we will be able to access external capital on terms favorable to us or at all. If we are unable to fund our capital requirements, we may be unable to complete acquisitions, take advantage of business opportunities, or respond to competitive pressures, any of which could have a material adverse effect on our results of operation and cash distributions to unitholders.

Most of our operators are also dependent on the availability of external debt and equity financing sources to maintain their drilling programs. If those financing sources are not available to the operators on favorable terms or at all, then we expect the development of our properties to be adversely affected. If the development of our properties is adversely affected, then revenues from our mineral and royalty interests and non-operated working interests may decline.

Unless we replace the oil and natural gas produced from our properties, our cash generated from operations and our ability to make distributions to our common and subordinated unitholders could be adversely affected.

Producing oil and natural gas wells are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and our operators’ production thereof and our cash generated from operations and ability to make distributions are highly dependent on the successful development and exploitation of our current reserves. The production decline rates of our properties may be significantly higher than currently estimated if the wells on our properties do not produce as expected. We may also not be able to find, acquire, or develop additional reserves to replace the current and future production of our properties at economically acceptable terms, which would adversely affect our business, financial condition, results of operations, and cash distributions to our common and subordinated unitholders.

We either have little or no control over the timing of future drilling with respect to our mineral and royalty interests and non-operated working interests.

Our proved undeveloped reserves may not be developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations, and the decision to pursue development of a proved undeveloped drilling location will be made by the operator and not by us. The reserve data included in the reserve report of our engineer assume that substantial capital expenditures are required to develop the reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled, or that the results of the development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop our reserves, or decreases in commodity prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our undeveloped reserves as unproved reserves.

Project areas on our properties, which are in various stages of development, may not yield oil or natural gas in commercially viable quantities.

Project areas on our properties are in various stages of development, ranging from project areas with current drilling or production activity to project areas that have limited drilling or production history. If the wells in the process of being completed do not produce sufficient revenues or if dry holes are drilled, our financial condition, results of operations, and cash distributions to unitholders may be adversely affected.

Our operators’ identified potential drilling locations are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

The ability of our operators to drill and develop identified potential drilling locations depends on a number of uncertainties, including the availability of capital, construction of infrastructure, inclement weather, regulatory changes and approvals, oil and natural gas prices, costs, drilling results, and the availability of water. Further, our operators’ identified potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation. The use of technologies and the study of producing fields in the same area will not enable our operators to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, our operators may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If our operators drill additional wells that they identify as dry holes in current and future drilling locations, their drilling success rate may decline and materially harm their business as well as ours.

We cannot assure you that the analogies our operators draw from available data from the wells on our acreage, more fully explored locations, or producing fields will be applicable to their drilling locations. Further, initial production rates reported by our or other operators in the areas in which our reserves are located may not be indicative of future or long-term production rates. Because of these uncertainties, we do not know if the potential drilling locations our operators have identified will ever be drilled or if our operators will be able to produce oil or natural gas from these or any other potential drilling locations. As such, the actual drilling activities of our operators may materially differ from those presently identified, which could adversely affect our business, results of operation, and cash distributions to unitholders.

The unavailability, high cost, or shortages of rigs, equipment, raw materials, supplies, or personnel may restrict or result in increased costs for operators related to developing and operating our properties.

The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies, and personnel. When shortages occur, the costs and delivery times of rigs, equipment, and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases in demand. In accordance with customary industry practice, our operators rely on independent third-party service providers to provide many of the services and equipment necessary to drill new wells. If our operators are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer. Shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies, personnel, trucking services, tubulars, fracking and completion services, and production equipment could delay or restrict our operators’ exploration and development operations, which in turn could have a material adverse effect on our financial condition, results of operations, and cash distributions to unitholders.

The marketability of oil and natural gas production is dependent upon transportation, pipelines, and refining facilities, which neither we nor many of our operators control. Any limitation in the availability of those facilities could interfere with our or our operators’ ability to market our or our operators’ production and could harm our business.

The marketability of our or our operators’ production depends in part on the availability, proximity, and capacity of pipelines, tanker trucks, and other transportation methods, and processing and refining facilities owned by third parties. The amount of oil that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage, or lack of available capacity on these systems, tanker truck availability, and extreme weather conditions. Also, the shipment of our or our operators’ oil and natural gas on third-party pipelines may be curtailed or delayed if it does not meet the quality specifications of the pipeline owners. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we or our operators are provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or transportation, processing, or refining-facility capacity could reduce our or our operators’ ability to market oil production and have a material adverse effect on our financial condition, results of operations, and cash distributions to unitholders. Our or our operators’ access to transportation options and the prices we or our operators receive can also be affected by federal and state regulation—including regulation of oil production, transportation, and pipeline safety—as well by general economic conditions and changes in supply and demand. In addition, the third parties on whom we or our operators rely for transportation services are subject to complex federal, state, tribal, and local laws that could adversely affect the cost, manner, or feasibility of conducting our business.

Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

Oil and natural gas reserve engineering is not an exact science and requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, ultimate recoveries, and operating and development costs. As a result, estimated quantities of proved reserves, projections of future production rates, and the timing of development expenditures may be incorrect. Our estimates of proved reserves and related valuations as of December 31, 2017, 2016, and 2015 were prepared by NSAI, a third-party petroleum engineering firm, which conducted a detailed review of all of our properties for the period covered by its reserve report using information provided by us. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling, testing, and production. Also, certain assumptions regarding future oil and natural gas prices, production levels, and operating and development costs may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves and future cash generated from operations. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil and natural gas that are ultimately recovered being different from our reserve estimates.

The estimates of reserves as of December 31, 2017, 2016, and 2015 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the years ended December 31, 2017, 2016, and 2015, respectively, in accordance with the SEC guidelines applicable to reserve estimates for those periods. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for unproved undeveloped acreage.

Conservation measures, technological advances, and general concern about the environmental impact of the production and use of fossil fuels could materially reduce demand for oil and natural gas and adversely affect our results of operations and the trading market for our common units.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy, and energy-generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations, and cash distributions to unitholders. It is also possible that the concerns about the production and use of fossil fuels will reduce the number of investors willing to own our common units, adversely affecting the market price of our common units.

We rely on a few key individuals whose absence or loss could adversely affect our business.

Many key responsibilities within our business have been assigned to a small number of individuals. The loss of their services could adversely affect our business. In particular, the loss of the services of one or more members of our executive team could disrupt our business. Further, we do not maintain “key person” life insurance policies on any of our executive team or other key personnel. As a result, we are not insured against any losses resulting from the death of these key individuals.

The results of exploratory drilling in shale plays will be subject to risks associated with drilling and completion techniques and drilling results may not meet our expectations for reserves or production.

Our operators use the latest drilling and completion techniques in their operations, and these techniques come with inherent risks. When drilling horizontal wells, operators risk not landing the well bore in the desired drilling zone and straying from the desired drilling zone. When drilling horizontally through a formation, operators risk being unable to run casing through the entire length of the well bore and being unable to run tools and other equipment consistently through the horizontal well bore. Risks that our operators face while completing wells include being unable to fracture stimulate the planned number of stages, to run tools the entire length of the well bore during completion operations, and to clean out the well bore after completion of the final fracture stimulation stage. In addition, to the extent our operators engage in horizontal drilling, those activities may adversely affect their ability to successfully drill in identified vertical drilling locations. Furthermore, certain of the new techniques that our operators may adopt, such as infill drilling and multi-well pad drilling, may cause irregularities or interruptions in production due to, in the case of infill drilling, offset wells being shut in and, in the case of multi-well pad drilling, the time required to drill and complete multiple wells before these wells begin producing. The results of drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas often have limited or no production history and consequently our operators will be less able to predict future drilling results in these areas.

Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our operators’ drilling results are weaker than anticipated or they are unable to execute their drilling program on our properties, our operating and financial results in these areas may be lower than we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline, and our results of operations and cash distributions to unitholders could be adversely affected.

Oil and natural gas operations are subject to various governmental laws and regulations. Compliance with these laws and regulations can be burdensome and expensive, and failure to comply could result in significant liabilities, which could reduce cash distributions to our unitholders.

Operations on the properties in which we hold interests are subject to various federal, state, and local governmental regulations that may be changed from time to time in response to economic and political conditions. Matters subject to regulation include drilling operations, production and distribution activities, discharges or releases of pollutants or wastes, plugging and abandonment of wells, maintenance and decommissioning of other facilities, the spacing of wells, unitization and pooling of properties, and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of oil and natural gas. In addition, the production, handling, storage and transportation of oil and natural gas, as well as the remediation, emission, and disposal of oil and natural gas wastes, by-products thereof, and other substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state, and local laws and regulations primarily relating to protection of worker health and safety, natural resources, and the environment. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil, or criminal penalties, permit revocations, requirements for additional pollution controls, and injunctions limiting or prohibiting some or all of the operations on our properties. Moreover, these laws and regulations have generally imposed increasingly strict requirements related to water use and disposal, air pollution control, and waste management.

Laws and regulations governing exploration and production may also affect production levels. Our operators must comply with federal and state laws and regulations governing conservation matters, including:


•	provisions related to the unitization or pooling of the oil and natural gas properties;


•	the establishment of maximum rates of production from wells;


•	the spacing of wells;


•	the plugging and abandonment of wells; and


•	the removal of related production equipment.

Additionally, federal and state regulatory authorities may expand or alter applicable pipeline-safety laws and regulations, compliance with which may require increased capital costs for third-party oil and natural gas transporters. These transporters may attempt to pass on such costs to our operators, which in turn could affect profitability on the properties in which we own mineral and royalty interests.

Our operators must also comply with laws and regulations prohibiting fraud and market manipulations in energy markets. To the extent the operators of our properties are shippers on interstate pipelines, they must comply with the tariffs of those pipelines and with federal policies related to the use of interstate capacity.

Our operators may be required to make significant expenditures to comply with the governmental laws and regulations described above. We believe the trend of more expansive and stricter environmental legislation and regulations will continue. Please read Part I, Items 1 and 2. “Business and Properties — Environmental Matters” for a description of the laws and regulations that affect our operators and that may affect us. These and other potential regulations could increase the operating costs of our operators and delay production, which could reduce the amount of cash distributions to our unitholders.

Louisiana mineral servitudes are subject to reversion to the surface owner after ten years’ nonuse.

We own mineral servitudes covering several hundred thousand acres in Louisiana. A mineral servitude is created in Louisiana when the mineral rights are separated from the ownership of the surface, whether by sale or reservation. These mineral servitudes, once created, are subject to a ten-year prescription of nonuse. During the ten-year period, the mineral-servitude owner has to conduct good-faith operations on the servitude for the discovery and production of minerals, or the mineral servitude “prescribes,” and the mineral rights associated with that servitude revert to the surface owner. A good-faith operation for the discovery and production of minerals, even one resulting in a dry hole, conducted within the ten-year period will interrupt the prescription of nonuse and restart the running of the ten-year prescriptive period. If the operation results in production, prescription is interrupted as long as the production continues or operations are conducted in good faith to secure or restore production. If any of our mineral servitudes are prescribed by operation of Louisiana law, our operating results may be adversely affected.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs, additional operating restrictions or delays, and fewer potential drilling locations.

Our operators engage in hydraulic fracturing. Hydraulic fracturing is a common practice that is used to stimulate production of hydrocarbons from tight formations, including shales. The process involves the injection of water, sand, and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal SDWA regulates the underground injection of substances through the Underground Injection Control (“UIC”) program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic-fracturing process is typically regulated by state oil and natural gas commissions. The EPA however, has recently taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program and issued permitting guidance in February 2014 applicable to hydraulic fracturing involving the use of diesel fuel. The EPA has also issued final regulations under the federal Clean Air Act governing performance standards, including standards for the capture of air emissions released during hydraulic fracturing; finalized effluent limitation guidelines in June 2016 to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants; and issued in May 2014 an Advance Notice of Proposed Rulemaking ("ANPRM") seeking comment on its intent to develop regulations under the Toxic Substances Control Act ("TSCA") to require companies to disclose information regarding the chemicals used in hydraulic fracturing. However, no further action has been taken by the EPA with respect to the TSCA ANPRM and additional federal regulation of hydraulic fracturing is uncertain at this time.

In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals, or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. The EPA has not proposed to take any action in response to the report’s findings.

Several states, including Colorado, North Dakota, Louisiana, Oklahoma, and Texas, where we own interests in oil and natural gas producing properties, have adopted regulations that could restrict or prohibit hydraulic fracturing in certain circumstances or require the disclosure of the composition of hydraulic-fracturing fluids. For example, in Texas, the Texas RRC published a final rule in October 2014 governing permitting or re-permitting of disposal wells that require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates

such a disposal well is likely to be or determined to be contributing to seismic activity, then the RRC may deny, modify, suspend, or terminate the permit application or existing operating permit for that well. These existing or any new legal requirements establishing seismic permitting requirements or similar restrictions on the construction or operation of disposal wells for the injection of produced water likely will result in added costs to comply and affect our operators’ rate of production, which in turn could have a material adverse effect on our results of operations and financial position. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general or hydraulic fracturing in particular. In the event state, local, or municipal legal restrictions are adopted in areas where our operators conduct operations, our operators may incur substantial costs to comply with these requirements, which may be significant in nature, experience delays, or curtailment in the pursuit of exploration, development, or production activities and perhaps even be precluded from the drilling of wells.

Our credit facility has substantial restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions.

Our credit facility limits the amounts we can borrow to a borrowing base amount, as determined by the lenders at their sole discretion based on their valuation of our proved reserves and their internal criteria. The borrowing base is redetermined at least semi-annually, and the available borrowing amount could be decreased as a result of such redeterminations. Decreases in the available borrowing amount could result from declines in oil and natural gas prices, operating difficulties or increased costs, declines in reserves, lending requirements, or regulations or certain other circumstances. As of December 31, 2017, we had outstanding borrowings of $388.0 million and the aggregate maximum credit amounts of the lenders were $1.0 billion. Our borrowing base determined by the lenders under our credit facility in October 2017 is $550.0 million and the next semi-annual redetermination is scheduled for April 2018. A future decrease in our borrowing base could be substantial and could be to a level below our then-outstanding borrowings. Outstanding borrowings in excess of the borrowing base are required to be repaid in five equal monthly payments, or we are required to pledge other oil and natural gas properties as additional collateral, within 30 days following notice from the administrative agent of the new or adjusted borrowing base. If we do not have sufficient funds on hand for repayment, we may be required to seek a waiver or amendment from our lenders, refinance our credit facility, or sell assets, debt, or 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 could result in a default under our credit facility, which could materially adversely affect our business, financial condition, results of operations, and distributions to our unitholders.

The operating and financial restrictions and covenants in our credit facility restrict, and any future financing agreements likely will restrict, our ability to finance future operations or capital needs, engage, expand, or pursue our business activities, or pay distributions. Our credit facility restricts, and any future credit facility likely will restrict, our ability to:


•	incur indebtedness;


•	grant liens;


•	make certain acquisitions and investments;


•	enter into hedging arrangements;


•	enter into transactions with our affiliates;


•	make distributions to our unitholders; or


•	enter into a merger, consolidation, or sale of assets.

Our credit facility restricts our ability to make distributions to unitholders or to repurchase units unless after giving effect to such distribution or repurchase, there is no event of default under our credit facility and our outstanding borrowings are not in excess of our borrowing base. While we currently are not restricted by our credit facility from declaring a distribution, we may be restricted from paying a distribution in the future.

We also are required to comply with certain financial covenants and ratios under the credit facility. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control, such as reduced oil and natural gas prices. If we violate any of the restrictions, covenants, ratios, or tests in our credit facility, a significant portion of our indebtedness may become immediately due and payable, our ability to make distributions will be inhibited, and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our credit facility are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our credit facility, the lenders can seek to foreclose on our assets.

The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the oil and natural gas that our operators produce.

In response to findings that emissions of carbon dioxide, methane, and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, require preconstruction and operating permits for certain large stationary sources. Facilities required to obtain preconstruction permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established on a case-by-case basis. These EPA rulemakings could adversely affect operations on our properties and restrict or delay the ability of our operators to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis, which include gathering and boosting facilities as well as GHG emissions from completions and workovers of hydraulically fractured wells. Also, in June 2016, the EPA finalized rules that establish new air emission controls for methane emissions from certain new, modified, or reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission, and storage activities. However, in June 2017, the EPA proposed to stay the requirements for a period of two years and revisit implementation of the federal methane rules in their entirety. Several states, including Colorado, where we hold interests, have also adopted rules to control and minimize methane emissions from the production of oil and natural gas. Moreover, in response to public concerns regarding methane emissions, many operators have recently voluntarily agreed to implement methane controls with respect to their operations. State and federal methane rules have substantial similarities with respect to pollution control equipment and leak detection and repair (“LDAR”) requirements. These rules could result in increased compliance costs for our operators and require them to make expenditures to purchase pollution control equipment and hire additional personnel to assist with complying with LDAR requirements, such as increased frequency of inspections and repairs for certain processes and equipment. Consequently, these and other regulations related to controlling GHG emissions could have an adverse impact on production on our properties, our business and results of operations.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of federal climate legislation, a number of state and regional cap and trade programs have emerged. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our operators’ equipment and operations could require them to incur costs to reduce emissions of GHGs associated with their operations. In addition, substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas produced from our properties and lower the value of our reserves. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states, as well as state and local climate change initiatives, could adversely affect the oil and natural gas industry, and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business. Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for energy companies, which has resulted in certain financial institutions, funds, and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult for operators on our properties to secure funding for exploration and production activities. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and gas will continue to represent a substantial percentage of global energy use over that time. Exploration and production activities are capital intensive, and capital constraints of our operators could have a material adverse impact on production from our properties. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical

effects, such as increased frequency and severity of storms, floods, droughts, and other extreme climatic events; if any of these effects were to occur, they could have a material adverse effect on our properties and operations.

Operating hazards and uninsured risks may result in substantial losses to us or our operators, and any losses could adversely affect our results of operations and cash distributions to unitholders.

We may be secondarily liable for damage to the environment caused by our operators. The operations of our operators will be subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses, and environmental hazards such as oil spills, natural gas leaks and ruptures, or discharges of toxic gases. In addition, their operations will be subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage, or potential underground migration of fracturing fluids, including chemical additives. The occurrence of any of these events could result in substantial losses to our operators due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension of operations, and repairs required to resume operations.

In accordance with what we believe to be customary industry practice, we maintain insurance against some, but not all, of our business risks. Our insurance may not be adequate to cover any losses or liabilities we may suffer. Also, insurance may no longer be available to us or, if it is, its availability may be at premium levels that do not justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations, or cash distributions to unitholders. In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. We may also be liable for environmental damage caused by previous owners of properties purchased by us, which liabilities may not be covered by insurance.

We may not have coverage if we are unaware of a sudden and accidental pollution event and unable to report the “occurrence” to our insurance providers within the time frame required under our insurance policy. We do not have, and do not intend to obtain, coverage for gradual, long-term pollution events. In addition, these policies do not provide coverage for all liabilities, and we cannot assure our unitholders that the insurance coverage will be adequate to cover claims that may arise or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations, and cash distributions to unitholders.

Title to the properties in which we have an interest may be impaired by title defects.

No assurance can be given that we will not suffer a monetary loss from title defects or title failure. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.

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 have multiple layers of security to mitigate risks of cyber attack. If, however, we were to experience an attack and 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 Us

We expect to distribute a substantial majority of the cash we generate from operations each quarter, which could limit our ability to grow and make acquisitions.

We expect to distribute a substantial majority of the cash we generate from operations each quarter. As a result, we will have limited cash generated from operations to reinvest in our business or to fund acquisitions, and we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and growth capital expenditures. If we are unable to finance growth externally, our distribution policy will significantly impair our ability to grow.

If we issue additional units in connection with any acquisitions or growth capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. Other than limitations restricting our ability to issue units ranking senior or on parity with our Series B cumulative convertible preferred units, there are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units with respect to distributions. The incurrence of additional commercial borrowings or other debt to finance our growth would result in increased interest expense and required principal repayments, which, in turn, may reduce the cash that we have available to distribute to our unitholders. Please read Part II, Item 5. “Market for Registrant’s Common Equity, Related Unitholder Matters, and Issuer Purchases of Equity Securities — Cash Distribution Policy.”

The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion. Our partnership agreement does not require us to pay any distributions at all on our common and subordinated units. If we make distributions, our Series B cumulative convertible unitholders have priority with respect to rights to share in those distributions over our common and subordinated unitholders for so long as our Series B cumulative convertible preferred units are outstanding.

Our partnership agreement generally provides that, during the subordination period (as defined in our partnership agreement), we will pay any distributions each quarter as follows: (i) first, to the holders of Series B cumulative convertible preferred units equal to 7% per annum, subject to certain adjustments, (ii) second, to the holders of common units, until each common unit has received the applicable minimum quarterly distribution plus any arrearages from prior quarters, and (iii) third, to the holders of subordinated units, until each subordinated unit has received the applicable minimum quarterly distribution. If the distributions to our common and subordinated unitholders exceed the applicable minimum quarterly distribution per unit, then such excess amounts will be distributed pro rata on the common and subordinated units as if they were a single class. Our minimum quarterly distribution is $1.25 per common and subordinated unit on an annualized basis (or $0.3125 per unit on a quarterly basis) for the four quarters ending March 31, 2018. The minimum quarterly distribution will be $1.35 per common and subordinated unit on an annualized basis (or $0.3375 per unit on a quarterly basis) for the four quarters ending March 31, 2019. We expect that we will distribute a substantial majority of the cash we generate from operations each quarter. However, the board of directors of our general partner could elect not to pay distributions for one or more quarters or at all. Please read Part II, Item 5. “Market for Registrant’s Common Equity, Related Unitholder Matters, and Issuer Purchases of Equity Securities — Cash Distribution Policy.”

Our partnership agreement does not require us to pay any distributions at all on our common units. Accordingly, investors are cautioned not to place undue reliance on the permanence of any distribution policy in making an investment decision. Any modification or revocation of our cash distribution policy could substantially reduce or eliminate the amounts of distributions to our unitholders. The amount of distributions we make, if any, and the decision to make any distribution at all will be determined by the board of directors of our general partner. If we make distributions, our Series B cumulative convertible preferred unitholders have priority with respect to rights to share in those distributions over our common and subordinated unitholders for so long as our Series B cumulative convertible preferred units are outstanding. Please read Part II, Item 5. “Market for Registrant’s Common Equity, Related Unitholder Matters, and Issuer Purchases of Equity Securities — Cash Distribution Policy — Series B Cumulative Convertible Preferred Units.”

Our minimum quarterly distribution provides the common unitholders a specified priority right to distributions over the subordinated unitholders if we pay distributions. It does not provide the common unitholders the right to require payment of any distributions.

Our partnership agreement does not require us to pay any distributions on our common and subordinated units. The provision providing for a minimum quarterly distribution merely provides the common unitholders with a specified priority right to distributions before the subordinated unitholders receive distributions, if distributions are made with respect to the common and subordinated units.

Our partnership agreement eliminates the fiduciary duties that might otherwise be owed to the partnership and its partners by our general partner and its directors and executive officers under Delaware law.

Our partnership agreement contains provisions that eliminate the fiduciary duties that might otherwise be owed by our general partner and its directors and executive officers. For example, our partnership agreement provides that our general partner and its directors and executive officers have no duties to the partnership or its partners except as expressly set forth in the partnership agreement. In place of default fiduciary duties, our partnership agreement imposes a contractual standard requiring our general partner and its directors and executive officers to act in good faith, meaning they cannot cause the general partner to take an action that they subjectively believe is adverse to our interests. Such contractual standards allow our general partner and its directors and executive officers to manage and operate our business with greater flexibility and to subject the actions and determinations of our general partner and its directors and executive officers to lesser legal or judicial scrutiny than would be the case if state law fiduciary standards were applicable.

Our partnership agreement restricts the situations in which remedies may be available to our unitholders for actions taken that might constitute breaches of duty under applicable Delaware law and breaches of the contractual obligations in our partnership agreement.

Our partnership agreement restricts the potential liability of our general partner and its directors and executive officers to our unitholders. For example, our partnership agreement provides that our general partner and its directors and executive officers will not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in willful misconduct or fraud or, with respect to any criminal conduct, with the knowledge that its conduct was unlawful.

Unitholders are bound by the provisions of our partnership agreement, including the provisions described above.

Our partnership agreement restricts the voting rights of unitholders owning 15% or more of our units, subject to certain exceptions.

Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person or group that owns 15% or more of any class of units then outstanding, other than the limited partners in BSMC prior to the IPO, their transferees, persons who acquired such units with the prior approval of the board of directors of our general partner, holders of Series B cumulative convertible preferred units in connection with any vote, consent or approval of the Series B cumulative convertible preferred units as a separate class, and persons who own 15% or more of any class as a result of any redemption or purchase of any other person's units or similar action by us or any conversion of the Series B cumulative convertible preferred units at our option or in connection with a change of control may not vote on any matter.

Actions taken by our general partner may affect the amount of cash generated from operations that is available for distribution to unitholders or accelerate the right to convert subordinated units.

The amount of cash generated from operations available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:


•	amount and timing of asset purchases and sales;


•	cash expenditures;


•	borrowings;


•	entry into and repayment of current and future indebtedness;


•	issuance of additional units; and


•	the creation, reduction, or increase of reserves in any quarter.

In addition, borrowings by us do not constitute a breach of any duty owed by our general partner to our unitholders, including borrowings that have the purpose or effect of:


•	enabling holders of subordinated units to receive distributions; or


•	hastening the expiration of the subordination period.

In addition, our general partner may use an initial amount, equal to $137.6 million, which would not otherwise constitute cash generated from operations, in order to permit the payment of distributions on subordinated units. All of these actions may affect the amount of cash distributed to our unitholders and may facilitate the conversion of subordinated units into common units.

For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, our partnership agreement permits us to borrow funds, which would enable us to make such distribution on all outstanding units.

We have a call right that may require common unitholders to sell their common units at an undesirable time or price.

If at any point in time prior to the end of the subordination period we have acquired more than 80% of the total number of common units outstanding, we have the right, but not the obligation, to purchase all of the remaining common units at a price equal to the greater of (1) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (2) the highest per-unit price paid by us or any of our affiliates for common units during the 90-day period preceding the date such notice is first mailed. This limited call right is not exercisable as long as any of our Series B cumulative convertible preferred units are outstanding, or at any time after the subordination period has ended.

Unitholders may have liability to repay distributions.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

Increases in interest rates may cause the market price of our common units to decline.

An increase in interest rates may cause a corresponding decline in demand for equity investments in general, and in particular, for yield-based equity investments such as our common units. Any such increase in interest rates or reduction in demand for our common units resulting from other investment opportunities may cause the trading price of our common units to decline.

We may issue additional common units and other equity interests without common and subordinated unitholder approval, which would dilute holders of common and subordinated units. However, subject to certain exceptions, our partnership agreement does not authorize us to issue units ranking senior to or at parity with our Series B cumulative convertible preferred units without Series B cumulative convertible preferred unitholder approval.

Under our partnership agreement, we are authorized to issue an unlimited number of additional interests, including common units, without a vote of the unitholders other than, in certain instances, approval of holders of our preferred units. Our issuance of additional common units or other equity interests of equal or senior rank will have the following effects:


•	the proportionate ownership interest of common and subordinated unitholders in us immediately prior to the issuance will decrease;


•	the amount of cash distributions on each common and subordinated unit may decrease;


•	the ratio of our taxable income to distributions may increase;


•	the relative voting strength of each previously outstanding common and subordinated unit may be diminished; and


•	the market price of the common units may decline.

However, subject to certain exceptions, our partnership agreement does not authorize us to issue securities having preferences or rights with priority over or on a parity with the preferred units with respect to rights to share in distributions, redemption obligations, or redemption rights without Series B cumulative convertible preferred unitholder approval.

The market price of our common units could be adversely affected by sales of substantial amounts of our common units in the public or private markets.

As of December 31, 2017, we had 103,455,864 common units and 95,388,424 subordinated units outstanding. All of the subordinated units could convert 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 our common units in the public markets, or the perception that these sales might occur, could have a material adverse effect on the price of our common units or impair our ability to obtain capital through an offering of equity securities.

The price of our common units may fluctuate significantly, and unitholders could lose all or part of their investment.

The market price of our common units may be influenced by many factors, some of which are beyond our control, including those described elsewhere in these risk factors.

We have and will continue to incur increased costs as a result of being a publicly traded partnership.

As a publicly traded partnership, we have and will continue to incur significant legal, accounting, and other expenses that we did not incur prior to the IPO. In addition, the Sarbanes-Oxley Act, as well as rules implemented by the SEC and the NYSE, require publicly traded entities to maintain various corporate governance practices that further increase our costs. Before we are able to make distributions to our unitholders, we must first pay or reserve for our expenses, including the costs of being a publicly traded partnership. As a result, the amount of cash we have available to distribute to our unitholders will be affected by the costs associated with being a publicly traded partnership.

Following the IPO, we became subject to the public reporting requirements of the Securities Exchange Act of 1934 (the “Exchange Act”). These requirements have increased our legal and financial compliance costs.

If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud, and operate successfully as a publicly traded partnership. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future, or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act. For example, Section 404 requires us, among other things, to annually review and report on, and our independent registered public accounting firm to attest to, the effectiveness of our internal controls over financial reporting. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common units.

The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.

Because we are a publicly traded partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. In addition, because we are a publicly traded partnership, the NYSE does not require us to obtain unitholder approval prior to certain unit issuances. Accordingly, unitholders will not have the same protections afforded to stockholders of certain corporations that are subject to all of the NYSE’s corporate governance requirements.

Our partnership agreement includes exclusive forum, venue, and jurisdiction provisions. By purchasing a common unit, a limited partner is irrevocably consenting to these provisions regarding claims, suits, actions, or proceedings, and submitting to the exclusive jurisdiction of Delaware courts.

Our partnership agreement is governed by Delaware law. Our partnership agreement includes exclusive forum, venue, and jurisdiction provisions designating Delaware courts as the exclusive venue for all claims, suits, actions, or proceedings arising out of or relating in any way to the partnership agreement, brought in a derivative manner on behalf of the partnership, asserting a claim of breach of a fiduciary or other duty owed by any director, officer, or other employee of the partnership or the general partner, or owed by the general partner to the partnership or the partners, asserting a claim arising pursuant to any provision of the Delaware Act, or asserting a claim governed by the internal affairs doctrine. By purchasing a common unit, a limited partner is irrevocably consenting to these provisions regarding claims, suits, actions, or proceedings and submitting to the exclusive jurisdiction of Delaware courts. If a dispute were to arise between a limited partner and us or our officers, directors, or employees, the limited partner may be required to pursue its legal remedies in Delaware, which may be an inconvenient or distant location and which is considered to be a more corporate-friendly environment.

If a unitholder is not an Eligible Holder, the common units of such unitholder may be subject to redemption.

We have adopted certain requirements regarding those investors who may own our units. Eligible Holders are limited partners (a) whose, or whose owners’, federal income tax status does not have or is not reasonably likely to have a material adverse effect on the rates chargeable by us to customers and (b) whose ownership could not result in our loss of ownership in any material part of our assets, as determined by our general partner with the advice of counsel. If an investor is not an Eligible Holder, in certain circumstances as set forth in our partnership agreement, units by such investor may be redeemed by us at the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.

Tax Risks to Common Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes, and not being subject to a material amount of entity-level taxation. If the Internal Revenue Service (“IRS”) were to treat us as a corporation for federal income tax purposes or we 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 federal income tax purposes.

Despite the fact that we are organized as a limited partnership under Delaware law, we will be treated as a corporation for federal income tax purposes unless 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 income requirement 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 an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, or deductions would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, cash distributions to our unitholders would be substantially reduced. In addition, changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, and other forms of taxation. Imposition of any of those taxes may substantially reduce the cash distributions to our unitholders. Therefore, treatment of us as a corporation or the assessment of a material amount of entity-level taxation would result in a material reduction in the anticipated cash generated from operations and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial, or administrative changes and differing interpretations, possibly applied on a retroactive basis.

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative, or judicial changes or differing interpretations at any time. From time to time, members of Congress propose and consider similar substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Although there is no current legislative proposal, a prior legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for federal income tax purposes.

In addition, on January 24, 2017, final regulations regarding which activities give rise to qualifying income within the meaning of Section 7704 of the Code (the “Final Regulations”) were published in the Federal Register. The Final Regulations apply to taxable years beginning on or after January 19, 2017 and generally treat income from passive mineral interests (such as royalty income) as qualifying income. However, there can be no assurance that there will not be further changes to the Treasury Department's interpretation of the qualifying income rules in a manner that could impact our ability to qualify as a partnership in the future.

Any modification to the federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted or adopted. Any such changes could negatively impact the value of an investment in our common units. You are urged to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potential effect on your investment in our common units.

Future legislation may result in the elimination of certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and production. Additionally, future federal or state legislation may impose new or increased taxes or fees on oil and natural gas extraction.

In past years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including to certain key U.S. federal income tax provisions currently available to oil and gas companies. Such legislative changes have included, but not been limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; and (iii) an extension of the amortization period for certain geological and geophysical expenditures. Congress could consider, and could include, some or all of these proposals as part of tax reform legislation, to accompany lower federal income tax rates. Moreover, other more general features of tax reform legislation including changes to cost recovery rules and to the deductibility of interest expense may be developed that also would change the taxation of oil and gas companies. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development, or increase costs, and any such changes could have an adverse effect on the Company’s financial position, results of operations and cash flows.

If the IRS were to contest the federal income tax positions we take, it may adversely affect the market for our common units, and the costs of any such contest would reduce cash available for distribution to our 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 affecting us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely affect the market for our common units and the price at which they trade. Moreover, the costs of any contest between us and the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.

If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced and our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders' behalf.

Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. To the extent possible under the new rules, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised Schedule K-1 to each unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced and our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders' behalf. These rules are not applicable for tax years beginning on or prior to December 31, 2017.

Even if you, as a unitholder, do not receive any cash distributions from us, you will be required to pay taxes on your share of our taxable income.

You will be required to pay federal income taxes and, in some cases, state and local income taxes, on your share of our taxable income, whether or not you receive cash distributions from us. For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, you may be allocated taxable income and gain resulting from the sale and our cash available for distribution would not increase. Similarly, taking advantage of opportunities to reduce our existing debt, such as debt exchanges, debt repurchases, or modifications of our existing debt could result in “cancellation of indebtedness income” being allocated to our unitholders as taxable income without any increase in our cash available for distribution. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax due from you with respect to that income.

Tax gain or loss on disposition of our common units could be more or less than expected.

If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell your units at a price greater than your 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’s share of our nonrecourse liabilities, if you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale.

A substantial portion of the amount realized from the sale of your units, whether or not representing gain, may be taxed as ordinary income to you due to potential recapture items, including depreciation recapture. Thus, you may recognize both ordinary income and capital loss from the sale of your units if the amount realized on a sale of your units is less than your adjusted basis in the units. Net capital loss may only offset capital gains and, in the case of individuals, 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 our allocations 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 sale of units.

Tax-exempt entities face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs) raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Further, with respect to taxable years beginning after December 31, 2017, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours that is engaged in one or more unrelated trade or business) is required to compute the unrelated business taxable income of such tax-

exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, for years beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax-exempt entities should consult a tax advisor before investing in our common units.

Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our units.

Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business (“effectively connected income”). Income allocated to our unitholders and any gain from the sale of our units will generally be considered to be “effectively connected” with a U.S. trade or business. As a result, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a non-U.S. unitholder who sells or otherwise disposes of a unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that unit.

The Tax Cuts and Jobs Act imposes a withholding obligation of 10% of the amount realized upon a non-U.S. unitholder’s sale or exchange of an interest in a partnership that is engaged in a U.S. trade or business. However, due to challenges of administering a withholding obligation applicable to open market trading and other complications, the IRS has temporarily suspended the application of this withholding rule to open market transfers of interest in publicly traded partnerships pending promulgation of regulations or other guidance that resolves the challenges. It is not clear if or when such regulations or other guidance will be issued. Non-U.S. unitholders should consult a tax advisor before investing in our common units.

We treat each purchaser of common units as having the same tax benefits without regard to the common units actually purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of our common units and because of other reasons, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns.

We generally prorate our items of income, gain, loss, and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss, and deduction among our unitholders.

We generally prorate our items of income, gain, loss, and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month (the “Allocation Date”), instead of on the basis of the date a particular unit is transferred. Similarly, we generally allocate certain deductions for depreciation of capital additions, gain or loss realized on a sale or other disposition of our assets and, in the discretion of the general partner, any other extraordinary item of income, gain, loss, or deduction based upon ownership on the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss, and deduction among our 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 have disposed 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 and could 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 the subject 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 a partner 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 and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

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 our common units.

In addition to federal income taxes, you likely will be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance, or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if you do not live in any of those jurisdictions. We will initially own assets and conduct business in several states, many of which impose a personal income tax and also impose income taxes on corporations and other entities. You may be required to file state and local income tax returns and pay state and local income taxes in these jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. As we make acquisitions or expand our business, we may own assets or conduct business in additional states or foreign jurisdictions that impose a personal income tax. It is your responsibility to file all U.S. federal, foreign, state, and local tax returns.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 3. LEGAL PROCEEDINGS

Although we may, from time to time, be involved in various legal claims arising out of our operations in the normal course of business, we do not believe that the resolution of these matters will have a material adverse impact on our financial condition or results of operations.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common units are listed on the NYSE under the symbol “BSM.” Our common units began trading on the NYSE on May 1, 2015 at an initial public 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 the NYSE, as well as the quarterly distributions per common and subordinated unit paid for the indicated periods.



	Price Range of Common Units				Distributions¹
	High		Low		Per Common Unit		Per Subordinated Unit
2016
First Quarter	$	15.76	$	10.71	$	0.2625	$	0.18375
Second Quarter	$	17.15	$	13.61	$	0.2875	$	0.18375
Third Quarter	$	19.65	$	14.71	$	0.2875	$	0.18375
Fourth Quarter	$	19.86	$	16.94	$	0.2875	$	0.18375

2017
First Quarter	$	19.55	$	15.58	$	0.2875	$	0.18375
Second Quarter	$	17.21	$	15.12	$	0.3125	$	0.20875
Third Quarter	$	17.92	$	15.52	$	0.3125	$	0.20875
Fourth Quarter	$	18.57	$	16.71	$	0.3125	$	0.20875


¹	Represents cash distributions attributable to the quarter. Cash distributions declared in respect of a quarter are paid in the following quarter.

As of February 20, 2018, there were 104,258,290 common units outstanding held by 494 holders of record. Because many of our common units are held by brokers and other institutions on behalf of unitholders, we are unable to estimate the total number of unitholders represented by these holders of record. As of February 20, 2018, we also had outstanding 95,388,424 subordinated units, 24,803 Series A redeemable preferred units, and 14,711,219 Series B cumulative convertible preferred units. All Series A redeemable preferred units not redeemed by March 31, 2018 automatically convert to common and subordinated units effective as of January 1, 2018 or as soon as practicable thereafter. There is no established public market in which the subordinated units or the preferred units are traded.

Common Unit Performance Graph

The graph below compares our cumulative total unitholder return on our common units beginning on April 30, 2015, the date of pricing for our IPO, through December 31, 2017 with the S&P 500 index and the Alerian MLP index. The graph assumes that the value of the investment in our common units was $100.00 on April 30, 2015. Cumulative return is computed assuming reinvestment of distributions.

Comparison of Cumulative Total Return

Assumes Initial Investment of $100



	As of April 30, 2015		As of December 31,
	As of April 30, 2015		2015		2016		2017
Black Stone Minerals, L.P.	$	100.00	$	78.22	$	109.07	$	110.89
S&P 500 Index	100.00		99.47		111.37		135.69
Alerian MLP Index	100.00		66.99		79.25		74.08

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

Securities Authorized for Issuance under Equity Compensation Plans

See the information incorporated by reference under “Part III, Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters” regarding securities authorized for issuance under our equity compensation plans.

Recent Sales of Unregistered Securities

On December 14, 2017, we closed on the purchase of certain mineral interests using 7,338 common units valued at $0.1 million to fund the purchase price.

The issuance of the common units was made in reliance upon an exemption from the registration requirements of the Securities Act of 1933, as amended, pursuant to Rule 506(c) of Regulation D thereunder. The investors are "accredited investors" (as defined in Regulation D), the investors acquired the common units for investment purposes only and not for resale, and we took appropriate measures to restrict the transfer of the common units issued and verify the accredited investor status of the investors.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following tables set forth our purchases of our common and subordinated units for each month during the three months ended December 31, 2017:



Purchases of Common Units
Period	Total Number of Common Units Purchased	Average Price Paid Per Unit		Total Number of Common Units Purchased as Part of Publicly Announced Plans or Programs	Maximum Dollar Value of Common Units That May Yet Be Purchased Under the Plans or Programs
December 1 – December 31, 2017	18,999¹	$	17.93	—	$	—

Purchases of Subordinated Units
Period	Total Number of Subordinated Units Purchased	Average Price Paid Per Unit		Total Number of Common Units Purchased as Part of Publicly Announced Plans or Programs	Maximum Dollar Value of Common Units That May Yet Be Purchased Under the Plans or Programs
December 1 – December 31, 2017	—	$	—	—	$	—


¹	Includes units withheld to satisfy tax withholding obligations upon the vesting of certain restricted common units held by our executive officers and certain other employees.

Cash Distribution Policy

Our partnership agreement generally provides that we will pay any distributions each quarter during the subordination period in the following manner:


•	first, to the holders of the Series B cumulative convertible preferred units in an amount equal to 7% per annum, subject to certain adjustments;


•	second, to the holders of common units, until each common unit has received the applicable minimum quarterly distribution in the amounts specified below plus any arrearages from prior quarters; and


•	third, to the holders of subordinated units, until each subordinated unit has received the applicable minimum quarterly distribution.

If the distributions to our common and subordinated unitholders exceed the applicable minimum quarterly distribution per unit, then such excess amounts will be distributed pro rata on the common and subordinated units as if they were a single class. The applicable minimum quarterly distribution for the periods specified below is as follows:



	Minimum Quarterly Distribution (per unit)
Four Quarters Ending March 31,	Per Quarter	Annualized
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 minimum quarterly distribution does not provide the common unitholders the right to require payment of any distributions. It merely reflects the specified priority right of our common unitholders to distributions before the subordinated unitholders receive distributions, if distributions are paid.

The amount of cash to be distributed each quarter will be determined by the board of directors of our general partner following the end of that quarter after a review of our cash generated from operations for such quarter. We expect that we will distribute a substantial majority of the cash generated from our operations each quarter. The cash generated from operations for each quarter will generally equal our Adjusted EBITDA for the quarter, less cash needed for debt service, other contractual obligations, fixed charges, and reserves for future operating or capital needs that the board of directors may determine are appropriate. It is our intent, for at least the next several years, to finance most of our acquisitions and working-interest capital needs with cash generated from operations, borrowings under our credit facility, our executed farmout agreements, and, in certain circumstances, proceeds from future equity and debt issuances. We may also borrow to make distributions to our unitholders where, for example, we believe that the distribution level is sustainable over the long term, but short-term factors may cause cash generated from operations to be insufficient to pay distributions at the applicable minimum quarterly distribution level on our common and subordinated units. The board of directors of our general partner can change the amount of the quarterly distributions, if any, at any time and from time to time. Our partnership agreement does not require us to pay cash distributions on a quarterly or other basis on our common and subordinated units. Please read Part I, Item 1A. “Risk Factors — Risks Inherent in an Investment in Us — The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion. Our partnership agreement does not require us to pay any distributions at all on our common and subordinated units. If we make distributions, our Series B cumulative convertible preferred unitholders have priority with respect to rights to share in those distributions over our common and subordinated unitholders for so long as our Series B cumulative convertible preferred units are outstanding.” For a description of the relative rights and privileges of our preferred units to distributions, please read "Series A Redeemable Preferred Units" and "Series B Cumulative Convertible Preferred Units" below.

Replacement capital expenditures are expenditures necessary to replace our existing oil and natural gas reserves or otherwise maintain our asset base over the long term. Like a number of other master limited partnerships, we are required by our partnership agreement to retain cash from our operations in an amount equal to our estimated replacement capital requirements. We believe the level of our distribution rate will allow us to retain in our business sufficient cash generated from our operations to satisfy our replacement capital expenditure needs and to fund a portion of our growth capital expenditures. The board of directors of our general partner is responsible for establishing the amount of our estimated replacement capital expenditures on annual basis. On August 3, 2016 the board of directors established a replacement capital expenditure estimate of $15.0 million for the period of April 1, 2016 to March 31, 2017; there was no established estimate of replacement capital prior to this period. On June 8, 2017, the board of directors established a replacement capital expenditure estimate of $13.0 million for the period April 1, 2017 to March 31, 2018.

Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy

There is no guarantee that we will make cash distributions to our unitholders. Our cash distribution policy may be changed at any time by the board of directors of our general partner and is subject to certain restrictions, including the following:


•	Our common and subordinated unitholders have no contractual or other legal right to receive cash distributions from us on a quarterly or other basis, and if distributions are paid, common and subordinated unitholders will receive distributions only to the extent the distribution amount exceeds distributions that are required to be paid to our Series B cumulative convertible preferred unitholders.

•

Our credit facility restricts our distributions if there is a default under our credit facility or if our borrowing base is lower than the outstanding loans under our credit facility. Among other covenants, our credit facility requires we maintain a ratio of total debt to EBITDAX of 3.50:1.00 or less and a current ratio of 1.00:1.00 or greater. If we are unable to comply with these financial covenants or if we breach any other covenant under our credit facility or any future debt agreements, we could be prohibited from making distributions notwithstanding our stated distribution policy.

•

Our general partner has the authority to establish cash reserves for the prudent conduct of our business, and the establishment of, or increase in, those reserves could result in a reduction in cash distributions to our unitholders. Our partnership agreement does not limit the amount of cash reserves that our general partner may establish. Any decision to establish cash reserves made by our general partner will be binding on our unitholders.


•	Under Section 17-607 of the Delaware Act, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets.


•	We may lack sufficient cash to pay distributions to our unitholders due to shortfalls in cash generated from operations attributable to a number of operational, commercial, or other factors as well as increases in our operating or general and administrative expenses, principal and interest payments on our outstanding debt, working-capital requirements, and anticipated cash needs.

We expect to continue to distribute a substantial majority of our cash from operations to our unitholders on a quarterly basis, after, among other things, the establishment of cash reserves. To fund our growth, we may eventually need capital in excess of the amounts we may retain in our business or borrow under our credit facility. To the extent efforts to access capital externally are unsuccessful, our ability to grow could be significantly impaired.

Any distributions paid on our common and subordinated units with respect to a quarter will be paid within 60 days after the end of such quarter.

Subordinated Units

The limited partners of BSM’s Predecessor own all of our subordinated units. The principal difference between our common and subordinated units is that, for any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution until the holders of the common units have received the applicable minimum quarterly distribution for such quarter plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages. Our common unitholders are only entitled to arrearages in the payment of the minimum quarterly distribution from prior quarters during the subordination period. To the extent we have cash generated from operations available for distribution in any quarter during the subordination period in excess of the amount necessary to pay the applicable minimum quarterly distribution to holders of our common units, we will use this excess cash to pay any distribution arrearages on the common units related to prior quarters before any cash distribution is made on our subordinated units. Please read “Cash Distribution Policy.”

The subordination period will end on the first business day after we have earned and paid an aggregate amount of at least $1.35 (the annualized minimum quarterly distribution applicable for quarterly periods ending March 31, 2019 and thereafter) multiplied by the total number of outstanding common and subordinated units for a period of four consecutive, non-overlapping quarters ending on or after March 31, 2019, and there are no outstanding arrearages on our common units. When the subordination period ends as a result of our having met the test described above, all subordinated units will convert into common units on a one-to-one basis, and common units will thereafter no longer be entitled to arrearages.

In addition, at any time on or after March 31, 2019, provided there are no arrearages in the payment of the minimum quarterly distribution on the common units, our general partner may decide in its sole discretion to convert each subordinated unit into a number of common units at a ratio that will be less than one to one. If our general partner makes such election, all outstanding subordinated units will be converted into common units, and the conversion ratio will be equal to the distributions paid out with respect to the subordinated units over the previous four-quarter period in relation to the total amount of distributions required to pay the applicable minimum quarterly distribution in full with respect to the subordinated units over the previous four quarters. If at the time our general partner elects to convert the subordinated units under this provision our forecasted distributions on our subordinated units (as determined by the conflicts committee of our general partner’s board of directors) for the next four quarters are lower than our actual distributions for the previous four-quarter period referred to above, then the conversion ratio will be based on the forecasted distributions instead of the actual distributions.

Series A Redeemable Preferred Units

Until March 31, 2018, the holders of our outstanding Series A redeemable preferred units have the option to elect to have us redeem, effective as of December 31, 2017, their Series A redeemable preferred units at face value, plus any accrued and unpaid distributions. All Series A redeemable preferred units not redeemed by March 31, 2018 shall automatically convert to common and subordinated units effective as of January 1, 2018 or as soon as practicable thereafter. Therefore, as of the date of this report, the holders of our outstanding Series A redeemable preferred units do not have the right to receive any future distributions on their units.

Series B Cumulative Convertible Preferred Units

The holders of our Series B cumulative convertible preferred units will receive cumulative quarterly distributions in an amount equal to 7.0% of the face amount of the preferred units per annum (the “Distribution Rate”), provided that the Distribution Rate will be adjusted as follows: commencing on the sixth anniversary of November 28, 2017 and readjusting every two years thereafter (each, a “Readjustment Date”), the rate will equal the greater of (i) the Distribution Rate in effect immediately prior to the relevant Readjustment Date and (ii) the 10-year Treasury Rate as of such Readjustment Date plus 5.5% per annum; provided, however, that for any quarter commencing after the second anniversary of November 28, 2017 in which quarterly distributions are accrued but unpaid, the then-Distribution Rate shall be increased by 2.0% per annum for such quarter. We cannot pay any distributions on any junior securities, including any of our common units and subordinated units, prior to paying the quarterly distribution payable to the Series B cumulative convertible preferred units, including any previously accrued and unpaid distributions.

ITEM 6. SELECTED FINANCIAL DATA

The financial information below should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data” of this Annual Report.



	At December 31,
	2017		2016			2015			2014		2013
	(in thousands, except per unit amounts)
Total revenue	$	429,659	$	260,833		$	392,924		$	548,321	$	463,559
Net income (loss)	157,153		20,188			(101,305		)	169,187		168,963
Net income (loss) attributable to the general partner and common units and subordinated units subsequent to initial public offering	152,145		14,437			(108,017		)	*		*
Net income (loss) attributable to limited partners per common and subordinated unit (basic)¹
Per common unit (basic)	1.01		0.26			(0.56		)	*		*
Per subordinated unit (basic)	0.56		(0.11		)	(0.56		)	*		*
Net income (loss) attributable to limited partners per common and subordinated unit (diluted)¹
Per common unit (diluted)	1.01		0.26			(0.56		)	*		*
Per subordinated unit (diluted)	0.56		(0.11		)	(0.56		)	*		*
Cash distributions declared per common and subordinated unit
Per common unit	1.20		1.10			0.42			*		*
Per subordinated unit	0.79		0.74			0.42			*		*
Total assets²	1,576,451		1,128,827			1,061,436			1,326,782		1,444,413
Long-term debt	388,000		316,000			66,000			394,000		451,000
Total mezzanine equity	322,422		54,015			79,162			161,165		161,392


*	Information is not applicable for the periods prior to our IPO.


¹	See Note 13 – Earnings Per Unit in the consolidated financial statements included elsewhere in this Annual Report.


²	We recorded noncash impairments of oil and natural gas properties in the amounts of $6.8 million, $249.6 million, $117.9 million, and $57.1 million, for the years ended December 31, 2016, 2015, 2014, and 2013, respectively. We did not have impairments of oil and natural gas properties for the year ended December 31, 2017.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and notes thereto presented elsewhere in this Annual Report. This discussion and analysis contains forward-looking statements that involve risks, uncertainties, and assumptions. Actual results may differ materially from those anticipated in these forward-looking statements as a result of a number of factors, including those set forth under “Cautionary Note Regarding Forward-Looking Statements” and “Part I, Item 1A. Risk Factors.”

Overview

We are one of the largest owners of oil and natural gas mineral interests in the United States. Our principal business is maximizing the value of our existing portfolio of mineral and royalty assets through active management and expanding our asset base through acquisitions of additional mineral and royalty interests. We maximize value through the marketing of our mineral assets for lease, creative structuring of those leases to encourage and accelerate drilling activity, and selectively participating alongside our lessees on a working-interest basis. Our primary business objective is to grow our reserves, production, and cash generated from operations over the long term, while paying, to the extent practicable, a quarterly distribution to our unitholders.

On May 6, 2015, we completed our initial public offering of 22,500,000 common units representing limited partner interests. Our common units trade on the New York Stock Exchange under the symbol "BSM."

Our mineral and royalty interests consist of mineral interests in approximately 16.8 million acres, with an average 43.4% ownership interest in that acreage, NPRIs in 1.9 million acres, and ORRIs in 2.1 million acres. These non-cost-bearing interests include ownership in over 55,728 producing wells. We also own non-operated working interests, a significant portion of which are on positions where we also have a mineral and royalty interest. We recognize oil and natural gas revenue from our mineral and royalty and non-operated working interests in producing wells when the oil and natural gas production from the associated acreage is sold. Our other sources of revenue include mineral lease bonus and delay rentals, which are recognized as revenue according to the terms of the lease agreements.

Recent Developments

2017 Acquisitions

On November 28, 2017, we closed on the acquisition of (i) certain mineral interests and other non-cost bearing royalty interests from Noble Energy Inc., Noble Energy Wyco, LLC, and Rosetta Resources Operating LP, and (ii) one hundred percent (100%) of the issued and outstanding securities of Samedan Royalty, LLC ("Samedan") from Noble Energy US Holdings, LLC, collectively, the "Noble Acquisition." The mineral interests and other non-cost bearing royalty interests acquired in the Noble Acquisition, including interests owned by Samedan, include approximately 1.1 million gross (140,000 net) mineral acres, 380,000 gross acres of non-participating royalty interests, and 600,000 gross acres of overriding royalty interests collectively spread over 20 states with significant concentrations in Texas, Oklahoma, and North Dakota. We funded the cash purchase price of the Noble Acquisition of $335 million, before customary post-closing adjustments, with the proceeds from the issuance of $300 million of Series B cumulative convertible preferred units and $35 million of cash from borrowings on our credit facility. See "Recent Developments — Series B Cumulative Convertible Preferred Units" below for additional information about our Series B cumulative convertible preferred units.

Throughout 2017, we also closed numerous acquisitions consisting of various mineral and royalty interests in several Texas counties. We acquired mineral and royalty interests in East Texas prospective for the Haynesville and Bossier shales for a total of $4.8 million in cash and $45.7 million in our common units through acquisitions of assets previously owned by Angelina County Lumber Company. We also acquired mineral and royalty interests in the Delaware Basin for $30.8 million in cash and $12.0 million in common units, as well as additional mineral and royalty interests in East Texas for $55.3 million in cash and $14.0 million in our common units, and mineral and royalty interests in the Anadarko Basin for $0.4 million in cash.

Put Option Related to Noble Acquisition

By acquiring 100% of the issued and outstanding securities of Samedan, now NAMP Holdings, LLC, we acquired a 100% interest in Comin-Termin, LLC, now NAMP GP, LLC ("Holdings"), Comin 1989 Partnership LLLP, now NAMP 1, LP ("Comin"), and Temin 1987 Partnership LLLP, now NAMP 2, LP ("Temin"). Pursuant to certain co-ownership agreements, various co-owners hold undivided beneficial ownership interests in 47.34% and 44.39% of the minerals interests held of record by Holdings and Temin, respectively. Based on the terms of the co-ownership agreements, the co-owners each have an unconditional option to require Comin or Temin, as applicable, to purchase their beneficial ownership interest in the mineral interests held of record by Holdings or Temin, as applicable, at any time within 30 days of receiving such repurchase notice. The purchase price of the beneficial ownership interest shall be based on an evaluation performed by Comin or Temin, as applicable, in good faith. As of December 31, 2017, we had not received notice from any co-owner to exercise their repurchase option, and as such, no liability was recorded.

Farmout Agreements

On February 21, 2017, we announced that we entered into a farmout agreement with Canaan, which covers certain Haynesville and Bossier shale acreage in San Augustine County, Texas operated by XTO Energy Inc., a subsidiary of Exxon Mobil Corporation. We have an approximate 50% working interest in the acreage. A total of 18 wells are anticipated to be drilled over an initial phase, beginning with wells spud after January 1, 2017. As of December 31, 2017, 10 wells have been drilled during the initial phase. At its option, Canaan may participate in two additional phases with each phase continuing for the lesser of 2 years or until 20 wells have been drilled. During the first three phases of the agreement, Canaan will commit on a phase-by-phase basis and fund 80% of our drilling and completion costs and will be assigned 80% of our working interests in such wells (40% working interest on an 8/8ths basis). After the third phase, Canaan can earn 40% of our working interest (20% working interest on an 8/8ths basis) in additional wells drilled in the area by continuing to fund 40% of our costs for those wells on a well-by-well basis. We will receive a base ORRI before payout and an additional ORRI after payout on all wells drilled under the agreement. The Canaan Farmout is anticipated to reduce our future capital expenditures by approximately $40 to $50 million annually during the term of the agreement.

On November 21, 2017, we entered into a farmout agreement with Pivotal that covers substantially all of our remaining working interests under active development in the Shelby Trough area of East Texas targeting the Haynesville and Bossier shale acreage after giving effect to the Canaan Farmout (discussed above) over the next eight years. In wells operated by XTO Energy Inc. in San Augustine County, Texas, Pivotal will earn our remaining approximate 20% working interest (10% working interest on an 8/8ths basis) not covered by the Canaan Farmout, as well as 100% of our working interests (ranging from approximately 12.5% to 25% on an 8/8th basis) in wells operated by our other major operator in the area. Initially, Pivotal will be obligated to fund the development of up to 80 wells across several development areas and then will have options to continue funding our working interest across those areas for the duration of the eight year term. After the funding of a designated group of wells by Pivotal and once Pivotal achieves a specified payout for such well group, the Partnership will obtain a majority of the original working interest in the designated group of wells.

As a result of the farmout agreements with Canaan and Pivotal, we expect capital requirements associated with non-operated working interests to be minimal beyond the first quarter of 2018.

At-the-Market Offering Program

In the second quarter of 2017, we commenced an at-the-market offering (the “ATM Program”) program and in connection therewith entered into an Equity Distribution Agreement. The ATM Program permits us from time to time through our Sales Agents to sell our common units having an aggregate offering price of up to $100,000,000. We intend to use the net proceeds from any sales pursuant to the ATM Program, after deducting commissions and offering expenses, for general partnership purposes, which may include, among other things, repayment of indebtedness outstanding under our credit facility. Common units to be sold pursuant to the Equity Distribution Agreement will be offered and sold pursuant to our existing effective shelf-registration statement on Form S-3 (File No. 333-215857), which was declared effective by the Securities and Exchange Commission on February 8, 2017. Proceeds, net of commissions and expenses, of these sales through December 31, 2017 amounted to $32.5 million. See Note 15 – At-the-Market Offering Program to our consolidated financial statements included herein for further discussion.

Series B Cumulative Convertible Preferred Units

On November 22, 2017, we entered into a purchase agreement with Mineral Royalties One, L.L.C., a Delaware limited liability company and affiliate of The Carlyle Group ("Carlyle"), pursuant to which, on November 28, 2017, we issued and sold in a private placement 14,711,219 Series B cumulative convertible preferred units representing limited partner interests in us to Carlyle for a cash purchase price of $20.3926 per Series B cumulative convertible preferred unit (the “Issue Price”), resulting in proceeds to us of approximately $300 million. Proceeds from the private placement were used to partially fund the Noble Acquisition.

The holders of the Series B cumulative convertible preferred units will receive cumulative quarterly distributions in an amount equal to 7% per annum, subject to certain adjustments. Each holder may elect to convert all or any portion of its Series B cumulative convertible preferred units into common units on a one-for-one basis, subject to customary anti-dilution adjustments and an adjustment for any distributions that have accrued but not been paid when due, at any time after the second anniversary of November 28, 2017. Under certain conditions, we may elect to convert all or any portion of the Series B cumulative convertible preferred units into common units at any time after the second anniversary of November 28, 2017. We may also may elect to redeem the Series B cumulative convertible preferred units at any time during the 90-day period beginning on the sixth anniversary of November 28, 2017 at a redemption price equal to 105% of the Issue Price plus any accrued and unpaid distributions on the applicable Series B cumulative convertible preferred units, and at any time during the 90-day period beginning on each Readjustment Date at a redemption price payable wholly in cash equal to the Issue Price plus any accrued and unpaid distributions on the applicable Series B cumulative convertible preferred units.

Business Environment

The information below is designed to give a broad overview of the oil and natural gas business environment as it affects us.

Commodity Prices and Demand

Oil and natural gas prices have been historically volatile based upon the dynamics of supply and demand. The EIA forecasts that WTI oil prices will average approximately $58.00 per Bbl in both 2018 and 2019. During the year ended December 31, 2017, the WTI oil spot price reached a low of $42.48 per Bbl on June 21, 2017 but rebounded to a high of $60.46 per Bbl on December 29, 2017.

The EIA forecasts that the Henry Hub spot natural gas price will average $3.20 per MMBtu for 2018 and $3.08 per MMBtu for 2019. During the year ended December 31, 2017, Henry Hub spot natural gas prices ranged from a high of $3.71 per MMBtu on January 2, 2017 to a low of $2.44 per MMBtu on February 27, 2017.

To manage the variability in cash flows associated with the projected sale of our oil and natural gas production, we use various derivative instruments, which have recently consisted of fixed-price swap contracts.

The following table reflects commodity prices at the end of each quarter presented:



	2017
Benchmark Prices	Fourth Quarter		Third Quarter		Second Quarter		First Quarter
WTI spot oil ($/Bbl)¹	$	60.46	$	48.18	$	46.02	$	50.54
Henry Hub spot natural gas ($/MMBtu)¹	$	3.69	$	2.95	$	2.98	$	3.13


¹	Source: EIA

Rig Count

As we are the operator of record on only three properties, drilling on our acreage is dependent upon the exploration and production companies that lease our acreage. In addition to drilling plans that we seek from our operators, we also monitor rig counts in an effort to identify existing and future leasing and drilling activity on our acreage.

The following table shows the rig count at the close of each quarter presented:



	2017
U.S. Rotary Rig Count¹	Fourth Quarter	Third Quarter	Second Quarter	First Quarter
Oil	747	750	756	662
Natural gas	182	189	184	160
Other	—	1	—	2
Total	929	940	940	824


¹	Source: Baker Hughes Incorporated

Natural Gas Storage

A substantial portion of our revenue is derived from sales of oil production attributable to our interests; however, the majority of our production is natural gas. Natural gas prices are significantly influenced by storage levels throughout the year. Accordingly, we monitor the natural gas storage reports regularly in the evaluation of our business and its outlook.

Historically, natural gas supply and demand fluctuates on a seasonal basis. From April to October, when the weather is warmer and natural gas demand is lower, natural gas storage levels generally increase. From November to March, storage levels typically decline as utility companies draw natural gas from storage to meet increased heating demand due to colder weather. In order to maintain sufficient storage levels for increased seasonal demand, a portion of natural gas production during the summer months must be used for storage injection. The portion of production used for storage varies from year to year depending on the demand from the previous winter and the demand for electricity used for cooling during the summer months. Despite anticipated rising production, the EIA forecasts that inventories will conclude the withdrawal season, which is the end of March 2018, at 1,429 Bcf, or 17% below the five-year average. The EIA expects inventories to build slightly over the five-year average to a projected 3,861 Bcf at the end of October 2018; in 2019, inventories are expected to be about 6% lower on average than 2018 levels.

The following table shows natural gas storage volumes by region at the close of each quarter presented:



	2017
Region¹	Fourth Quarter	Third Quarter	Second Quarter	First Quarter
	(Bcf)
East	740	861	564	268
Midwest	875	989	699	479
Mountain	183	220	187	142
Pacific	268	311	287	216
South Central	1,060	1,127	1,151	946
Total	3,126	3,508	2,888	2,051


¹	Source: EIA

How We Evaluate Our Operations

We use a variety of operational and financial measures to assess our performance. Among the measures considered by management are the following:


•	volumes of oil and natural gas produced;


•	commodity prices including the effect of hedges; and


•	Adjusted EBITDA, distributable cash flow, and distributable cash flow after net working interest capital expenditures.

Volumes of Oil and Natural Gas Produced

In order to track and assess the performance of our assets, we monitor and analyze our production volumes from the various basins and plays that comprise our extensive asset base. We also regularly compare projected volumes to actual reported volumes and investigate unexpected variances.

Commodity Prices

Factors Affecting the Sales Price of Oil and Natural Gas

The prices we receive for oil, natural gas, and NGLs vary by geographical area. The relative prices of these products are determined by the factors affecting global and regional supply and demand dynamics, such as economic conditions, production levels, availability of transportation, weather cycles, and other factors. In addition, realized prices are influenced by product quality and proximity to consuming and refining markets. Any differences between realized prices and NYMEX prices are referred to as differentials. All of our production is derived from properties located in the United States.

•

Oil. The substantial majority of our oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of our control. NYMEX light sweet crude oil, commonly referred to as WTI, is the prevailing domestic oil pricing index. The majority of our oil production is priced at the prevailing market price with the final realized price affected by both quality and location differentials.

The chemical composition of crude oil plays an important role in its refining and subsequent sale as petroleum products. As a result, variations in chemical composition relative to the benchmark crude oil, usually WTI, will result in price adjustments, which are often referred to as quality differentials. The characteristics that most significantly affect quality differentials include the density of the oil, as characterized by its API gravity, and the presence and concentration of impurities, such as sulfur.

Location differentials generally result from transportation costs based on the produced oil’s proximity to consuming and refining markets and major trading points.


•	Natural Gas. The NYMEX price quoted at Henry Hub is a widely used benchmark for the pricing of natural gas in the United States. The actual volumetric prices realized from the sale of natural gas differ from the quoted NYMEX price as a result of quality and location differentials.

Quality differentials result from the heating value of natural gas measured in Btus and the presence of impurities, such as hydrogen sulfide, carbon dioxide, and nitrogen. Natural gas containing ethane and heavier hydrocarbons has a higher Btu value and will realize a higher volumetric price than natural gas which is predominantly methane, which has a lower Btu value. Natural gas with a higher concentration of impurities will realize a lower volumetric price due to the presence of the impurities in the natural gas when sold or the cost of treating the natural gas to meet pipeline quality specifications.

Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply and demand conditions and the cost to transport natural gas to end user markets.

Hedging

We enter into derivative instruments to partially mitigate the impact of commodity price volatility on our cash generated from operations. From time to time, such instruments may include variable-to-fixed-price swaps, fixed-price contracts, costless collars, and other contractual arrangements. The impact of these derivative instruments could affect the amount of revenue we ultimately realize. Since 2015, we have only entered into fixed-price swap contracts. Under fixed-price swap contracts, a counterparty is required to make a payment to us if the settlement price is less than the swap strike price. Conversely, we are required to make a payment to the counterparty if the settlement price is greater than the swap strike price. We may employ contractual arrangements other than 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 partially mitigate the effect of lower prices on our future revenue.

Our open oil and natural gas derivative contracts as of December 31, 2017, and as of the date of this filing, are detailed in Note 5 – Commodity Derivative Financial Instruments to our consolidated financial statements included elsewhere in this Annual Report. Prior to amending and restating our credit agreement on November 1, 2017, we were allowed to hedge all of our estimated production from our proved developed producing reserves based on the most recent reserve information provided to our lenders.

Pursuant to our Fourth Amended and Restated Credit Agreement, we are allowed to hedge certain percentages of expected future monthly production volumes equal to the lesser of (i) internally forecasted production and (ii) the average of reported production for the most recent three months. We are allowed to hedge up to 90% of such volumes for the first 24 months, 70% for months 25 through 36, and 50% for months 37 through 48. Pursuant to our updated hedge provisions, we have hedged 85.5% and 19.9% of our available oil and condensate hedge volumes for 2018 and 2019, respectively. Also, we have hedged 98.8% and 27.7% of our available natural gas hedge volumes for 2018 and 2019, respectively.

We intend to continuously monitor the production from our assets and the commodity price environment, and will, from time to time, add additional hedges within the percentages described above to remain significantly hedged for the following 12 to 24 months. We do not enter into derivative instruments for speculative purposes.

Non-GAAP Financial Measures

Adjusted EBITDA, distributable cash flow, and distributable cash flow after net working interest capital expenditures are supplemental non-GAAP financial measures used by our management and external users of our financial statements such as investors, research analysts, and others, to assess the financial performance of our assets and our ability to sustain distributions over the long term without regard to financing methods, capital structure, or historical cost basis.

We define Adjusted EBITDA as net income (loss) before interest expense, income taxes, and depreciation, depletion, and amortization adjusted for impairment of oil and natural gas properties, accretion of asset retirement obligations, unrealized gains and losses on commodity derivative instruments, and non-cash equity-based compensation. We define distributable cash flow as Adjusted EBITDA plus or minus amounts for certain non-cash operating activities, estimated replacement capital expenditures, cash interest expense, and distributions to noncontrolling interests and preferred unitholders. We define distributable cash flow after net working interest capital expenditures as distributable cash flow less net working interest capital expenditures. Net working interest capital expenditures consists of all capital expenditures related to working interest wells less the recoupment of working interest expenditures under our farmout agreements.

Adjusted EBITDA, distributable cash flow, and distributable cash flow after net working interest capital expenditures 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 generally accepted accounting principles (“GAAP”) in the United States as measures of our financial performance.

Adjusted EBITDA, distributable cash flow, and distributable cash flow after net working interest capital expenditures have important limitations as analytical tools because they exclude some but not all items that affect net income (loss), the most directly comparable GAAP financial measure. Our computation of Adjusted EBITDA, distributable cash flow, and distributable cash flow after net working interest capital expenditures may differ from computations of similarly titled measures of other companies.

The following table presents a reconciliation of Adjusted EBITDA, distributable cash flow, and distributable cash flow after net working interest capital expenditures to net income (loss), the most directly comparable GAAP financial measure, for the periods indicated.



	Year Ended December 31,
	2017			2016			2015
	(in thousands)
Net income (loss)	$	157,153		$	20,188		$	(101,305	)
Adjustments to reconcile to Adjusted EBITDA:
Depreciation, depletion and amortization	114,534			102,487			104,298
Interest expense	15,694			7,547			6,418
Impairment of oil and natural gas properties	—			6,775			249,569
Accretion of asset retirement obligations	1,026			892			1,075
Equity-based compensation¹	33,045			43,138			18,000
Unrealized (gain) loss on commodity derivative instruments	(11,691		)	81,253			(27,063		)
Adjusted EBITDA	309,761			262,280			250,992
Adjustments to distributable cash flow:
Restructuring charges	—			—			4,208
Incremental general and administrative related to initial public offering	—			—			1,303
Deferred revenue	(2,086		)	(870		)	(660		)
Cash interest expense	(14,817		)	(6,676		)	(5,483		)
(Gain) loss on sales of assets, net	(931		)	(4,793		)	(4,873		)
Estimated replacement capital expenditures²	(13,500		)	(11,250		)	—
Cash paid to noncontrolling interests	(120		)	(111		)	(208		)
Preferred unit distributions	(5,042		)	(5,763		)	(11,562		)
Distributable cash flow	273,265			232,817			233,717
Net working interest capital expenditures	$	(39,477	)	(80,179		)	(54,244		)
Distributable cash flow after net working interest capital expenditures	$	233,788		$	152,638		$	179,473


¹	On April 25, 2016, the Compensation Committee of the board of directors of our general partner approved a resolution to change the settlement feature of certain employee long-term incentive compensation plans from cash to equity. As a result of the modification, $10.1 million of cash-settled liabilities were reclassified to equity-settled liabilities during the second quarter of 2016.

On August 3, 2016, the board of directors of our general partner established a replacement capital expenditures estimate of $15.0 million for the period of April 1, 2016 to March 31, 2017; there was no established estimate of replacement capital expenditures prior to this period. On June 8, 2017, the board of directors of our general partner established a replacement capital expenditure estimate of $13.0 million for the period of April 1, 2017 to March 31, 2018.

Factors Affecting the Comparability of Our Financial Results

Our historical 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. These incremental expenses include costs associated with SEC reporting requirements, including annual and quarterly reports to unitholders; tax return and Schedule K-1 preparation and distribution fees; Sarbanes-Oxley Act compliance; New York Stock Exchange listing fees; independent registered public accounting 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.

Results of Operations

Year Ended December 31, 2017 Compared to Year Ended December 31, 2016

The following table shows our production, revenue, and operating expenses for the periods presented:



	Year Ended December 31,
	2017		2016			Variance
	(dollars in thousands, except for realized prices and per BOE data)
Production:
Oil and condensate (MBbls)	3,552		3,680			(128		)	(3.5	)%
Natural gas (MMcf)¹	59,779		47,498			12,281			25.9	%
Equivalents (MBoe)	13,515		11,596			$	1,919		16.5	%
Revenue:
Oil and condensate sales	$	169,728	$	142,382		$	27,346		19.2	%
Natural gas and natural gas liquids sales¹	190,967		122,836			68,131			55.5	%
Gain (loss) on commodity derivative instruments	26,902		(36,464		)	63,366			(173.8	)%
Lease bonus and other income	42,062		32,079			9,983			31.1	%
Total revenue	$	429,659	$	260,833		$	168,826		64.7	%
Realized prices, without derivatives:
Oil and condensate ($/Bbl)	$	47.78	$	38.69		$	9.09		23.5	%
Natural gas ($/Mcf)¹	$	3.19	$	2.59		$	0.60		23.2	%
Equivalents ($/Boe)	$	26.69	$	22.87		$	3.82		16.7	%
Operating expenses:
Lease operating expense	$	17,280	$	18,755		$	(1,475	)	(7.9	)%
Production costs and ad valorem taxes	47,474		35,464			12,010			33.9	%
Exploration expense	618		645			(27		)	(4.2	)%
Depreciation, depletion, and amortization	114,534		102,487			12,047			11.8	%
Impairment of oil and natural gas properties	—		6,775			(6,775		)	(100.0	)%
General and administrative	77,574		73,139			4,435			6.1	%

¹As a mineral-and-royalty-interest owner, we are often provided insufficient and inconsistent data on NGL volumes by our operators. As a result, we are unable to reliably determine the total volumes of NGLs associated with the production of natural gas on our acreage. Accordingly, no NGL volumes are included in our reported production; however, revenue attributable to NGLs is included in our natural gas revenue and our calculation of realized prices for natural gas.

Revenue

Total revenue for the year ended December 31, 2017 increased compared to the year ended December 31, 2016. Production for 2017 averaged 37.0 MBoe per day, an increase of 5.3 MBoe per day, compared to the corresponding period in 2016. The increase in total revenue from the corresponding period is primarily due to higher realized commodity prices and production volumes, an increase in revenue from our commodity derivative instruments, and higher lease bonus and other income.

Oil and condensate sales. Oil and condensate sales during 2017 were higher than the corresponding period in 2016 due to a significant increase in realized prices. Our mineral-and-royalty-interest oil and condensate volumes accounted for 83.1% and 77.3% of total oil and condensate volumes for the years ended December 31, 2017 and 2016, respectively. Our oil and condensate volumes decreased slightly in 2017.

Natural gas and natural gas liquids sales. Natural gas and NGL sales increased for the year ended December 31, 2017 as compared to 2016. During 2017, production from new wells in Haynesville/Bossier and Wilcox plays combined with higher natural gas and NGL prices drove the increase in natural gas and NGL sales. Mineral-and-royalty-interest production

accounted for 51.3% and 59.3% of our natural gas and NGL volumes for the years ended December 31, 2017 and 2016, respectively.

Gain (loss) on commodity derivative instruments. In 2017, we recognized $5.1 million of net losses from oil commodity contracts, which included cash received of $10.9 million, compared to $16.0 million of recognized net losses in 2016. In 2017, we recognized $32.0 million of net gains from natural gas commodity contracts, which included cash received of $4.3 million, compared to $20.5 million of net losses in 2016.

Lease bonus and other income. When we lease our mineral interests, we generally receive an upfront cash payment, or a lease bonus. Lease bonus and delay rental revenue increased for the year ended December 31, 2017, as compared to 2016. In 2017, we successfully closed several significant lease transactions in the Austin Chalk, Bakken/Three Forks, Haynesville/Bossier and Canyon Lime plays as well as the Anadarko and Permian Basins, compared to the majority of 2016 activity which came from the Wolfcamp, Austin Chalk, and Marcellus plays.

Operating Expenses

Lease operating expenses. Lease operating expense includes normally recurring expenses associated with our non-operated working interests necessary to produce hydrocarbons from our oil and natural gas wells, as well as certain nonrecurring expenses, such as well repairs. Lease operating expense decreased for the year ended December 31, 2017 as compared to 2016, primarily due to fewer remedial projects initiated by our operators.

Production costs and ad valorem taxes. Production taxes include statutory amounts deducted from our production revenues by various state taxing entities. 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 fixed amount per production unit. This category also includes the costs to process and transport our production to applicable sales points. Ad valorem taxes are jurisdictional taxes levied on the value of oil and natural gas minerals and reserves. Rates, methods of calculating property values, and timing of payments vary between taxing authorities. For the year ended December 31, 2017, production and ad valorem taxes increased over the year ended December 31, 2016, generally as a result of higher production volumes and commodity prices.

Exploration expense. Exploration expense typically consists of dry-hole expenses, delay rentals, and geological and geophysical costs, including seismic costs, and is expensed as incurred under the successful efforts method of accounting. Exploration expense for 2017 represents costs incurred to acquire 3-D seismic information, related to our mineral and royalty interests, from a third-party service provider.

Depreciation, depletion, and amortization. Depletion is the amount of cost basis of oil and natural gas properties attributable to the volume of hydrocarbons extracted during such period, calculated on a units-of-production basis. Estimates of proved developed producing reserves are a major component of the calculation of depletion. We adjust our depletion rates semi-annually based upon the mid-year and year-end reserve reports, except when circumstances indicate that there has been a significant change in reserves or costs. Depreciation, depletion, and amortization expense increased for the year ended December 31, 2017 as compared to 2016, primarily due to higher production volumes partially offset by lower depletion rates.

Impairment of oil and natural gas properties. Individual categories of oil and natural gas properties are assessed periodically to determine if the net book value for these properties has been impaired. Management periodically conducts an in-depth evaluation of the cost of property acquisitions, successful exploratory wells, development activities, unproved leasehold, and mineral interests to identify impairments. We did not incur any impairment in 2017, while impairments for 2016 were $6.8 million.

General and administrative. General and administrative expenses are costs not directly associated with the production of oil and natural gas and include the cost of employee salaries and related benefits, office expenses, and fees for professional services. For the year ended December 31, 2017, general and administrative expenses increased compared to 2016. In 2017, costs attributable to our long-term incentive plans were higher due to the achievement of certain performance targets; we also incurred higher broker fees associated with increased acquisition activities.

Interest expense. Interest expense increased due to higher average outstanding borrowings and higher interest rates under our credit facility, which were predominantly driven by increased acquisition of oil and natural gas properties in 2017 as compared to 2016.

Year Ended December 31, 2016 Compared to Year Ended December 31, 2015

The following table shows our production, revenue, and operating expenses for the periods presented:



	Year Ended December 31,
	2016			2015		Variance
	(dollars in thousands, except for realized prices and per BOE data)
Production:
Oil and condensate (MBbls)	3,680			3,565		115			3.2	%
Natural gas (MMcf)¹	47,498			41,389		6,109			14.8	%
Equivalents (MBoe)	11,596			10,463		$	1,133		10.8	%
Revenue:
Oil and condensate sales	$	142,382		$	163,538	$	(21,156	)	(12.9	)%
Natural gas and natural gas liquids sales¹	122,836			116,018		6,818			5.9	%
Gain (loss) on commodity derivative instruments	(36,464		)	90,288		(126,752		)	(140.4	)%
Lease bonus and other income	32,079			23,080		8,999			39.0	%
Total revenue	$	260,833		$	392,924	$	(132,091	)	(33.6	)%
Realized prices:
Oil and condensate ($/Bbl)	$	38.69		$	45.87	$	(7.18	)	(15.7	)%
Natural gas ($/Mcf)¹	$	2.59		$	2.80	$	(0.21	)	(7.5	)%
Equivalents ($/Boe)	$	22.87		$	26.72	$	(3.85	)	(14.4	)%
Operating expenses:
Lease operating expense	$	18,755		$	21,583	$	(2,828	)	(13.1	)%
Production costs and ad valorem taxes	35,464			35,767		(303		)	(0.8	)%
Exploration expense	645			2,592		(1,947		)	(75.1	)%
Depreciation, depletion, and amortization	102,487			104,298		(1,811		)	(1.7	)%
Impairment of oil and natural gas properties	6,775			249,569		(242,794		)	(97.3	)%
General and administrative	73,139			77,175		(4,036		)	(5.2	)%

As a mineral-and-royalty-interest owner, we are often provided insufficient and inconsistent data on NGL volumes by our operators. As a result, we are unable to reliably determine the total volumes of NGLs associated with the production of natural gas on our acreage. Accordingly, no NGL volumes are included in our reported production; however, revenue attributable to NGLs is included in our natural gas revenue and our calculation of realized prices for natural gas.

Revenue

The $132.1 million decrease in total revenue for the year ended December 31, 2016 compared to the year ended December 31, 2015 was due to $126.8 million of losses attributable to commodity derivative instruments and $36.7 million lower realized commodity prices, partially offset by $22.4 million related to higher oil and condensate and natural gas and NGL volumes and $9.0 million in additional lease bonus and other income.

Oil and condensate sales. Oil and condensate sales during 2016 were lower than the corresponding period in 2015 primarily due to a steep decline in realized prices. Our mineral-and-royalty-interest oil volumes accounted for 77.3% and 76.8% of total oil and condensate volumes for the years ended December 31, 2016 and 2015, respectively. Our oil and condensate volumes increased in 2016 relative to 2015 primarily driven by production increases from new wells in the Bakken/Three Forks, Wilcox, and Wolfcamp plays.

Natural gas and natural gas liquids sales. Natural gas and NGL sales increased for the year ended December 31, 2016 as compared to 2015. During 2016, increases in production from our Haynesville and Wilcox properties served to more than mitigate the impact of further depressed realized natural gas and NGL prices. Mineral-and-royalty-interest production made up 59.3% and 67.3% of our natural gas and NGL volumes for the years ended December 31, 2016 and 2015, respectively.

Gain (loss) on commodity derivative instruments. In 2016, we recognized $16.0 million of net losses from oil commodity contracts, which included $27.5 million of realized gains, compared to $57.7 million of combined gains in 2015, of which $41.8 million were realized. In 2016, we recognized $20.5 million of net losses from natural gas commodity contracts, which included $17.3 million of realized gains, compared to $32.6 million of combined gains in 2015, of which $21.4 million were realized gains.

Lease bonus and other income. Lease bonus and delay rental revenue increased for the year ended December 31, 2016, as compared to 2015. In 2016, we successfully closed several significant lease transactions in Jasper, Tyler, Pecos, and Newton Counties of Texas, in the Red River parish of Louisiana, and in Potter County of Pennsylvania. Closings in 2015 included large lease transactions in the Wolfcamp, the Eagle Ford Shale, and various plays in East Texas and in Southern Mississippi.

Operating Expenses

Lease operating expenses. Lease operating expense decreased for the year ended December 31, 2016 as compared to 2015, primarily due to lower workover expense, realized cost efficiencies resulting from a currently depressed industry market, the plugging of certain uneconomical working interest wells, and fewer remedial projects initiated by our operators.

Production costs and ad valorem taxes. For the year ended December 31, 2016, production and ad valorem taxes increased over the year ended December 31, 2015, generally as a result of higher production volumes.

Exploration expense. Exploration expense for the years ended December 31, 2016 and 2015 primarily resulted from costs incurred to acquire 3-D seismic information related to our mineral and royalty interests from a third-party service provider.

Depreciation, depletion, and amortization. Depreciation, depletion, and amortization expense increased for the year ended December 31, 2016 as compared to 2015, primarily due to higher production rates offset by the impact of a reduced cost basis resulting from impairment charges related to prior periods.

Impairment of oil and natural gas properties. Impairments of $249.6 million for the year ended December 31, 2015 primarily resulted from changes in reserve values due to declines in future expected realized net cash flows as a result of lower commodity prices. Impairments of $6.8 million for 2016 were insignificant.

General and administrative. For the year ended December 31, 2016, general and administrative expenses decreased compared to 2015. In 2016, personnel costs and costs attributable to our long-term incentive plans were lower primarily due to one-time incentive compensation awards granted in 2015 as a result of our IPO and certain restructuring costs incurred in 2015. In addition, we also incurred $2.5 million for our Sarbanes-Oxley Act compliance project and other consulting work during 2015.

Interest expense. Interest expense increased due to higher average outstanding borrowings under our credit facility. Outstanding borrowings during 2016 were higher than 2015, primarily due to additional borrowings for multiple acquisitions, preferred unit redemptions, and common unit repurchases.

Liquidity and Capital Resources

Overview

Our primary sources of liquidity are cash generated from operations, borrowings under our credit facility, and proceeds from the issuance of equity and debt. Our primary uses of cash are for distributions to our unitholders and for investing in our business, specifically the acquisition of mineral and royalty interests and our selective participation on a non-operated working-interest basis in the development of our oil and natural gas properties.

The board of directors of our general partner has adopted a policy pursuant to which distributions equal in amount to the applicable minimum quarterly distribution will be paid on each common and subordinated unit for each quarter to the extent we have sufficient cash generated from our operations 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 on our common and subordinated units quarterly or on any other basis, at the applicable minimum quarterly distribution rate or at any other rate, and there is no guarantee that we will pay distributions to our common and subordinated unitholders in any quarter. Our minimum quarterly distribution provides the common unitholders a specified priority right to distributions over the subordinated unitholders. The board of directors of our general partner may change the foregoing distribution policy at any time and from time to time.

We intend to finance our future acquisitions with cash generated from operations, borrowings from our credit facility, and proceeds from any future issuances of equity and debt. Over the long-term, we intend to finance our working-interest capital needs with our executed farmout agreements and internally-generated cash flows, although at times we may fund a portion of these expenditures through other financing sources such as borrowings under our credit facility. Replacement capital expenditures are expenditures necessary to replace our existing oil and natural gas reserves or otherwise maintain our asset base over the long-term. Like a number of other master limited partnerships, we are required by our partnership agreement to retain cash from our operations in an amount equal to our estimated replacement capital requirements. The board of directors of our general partner established a replacement capital expenditure estimate of $15.0 million for the period of April 1, 2016 to March 31, 2017. On June 8, 2017, the board of directors of our general partner established a replacement capital expenditure estimate of $13.0 million for the period of April 1, 2017 to March 31, 2018.

Cash Flows

The following table shows our cash flows for the periods presented:



	Year Ended December 31,
	2017			2016			2015
	(in thousands)
Cash flows provided by operating activities	$	281,852		$	196,656		$	284,735
Cash flows used in investing activities	(454,249		)	(221,542		)	(90,998		)
Cash flows provided by (used in) financing activities	168,267			21,425			(195,307		)

Year Ended December 31, 2017 Compared to Year Ended December 31, 2016

Operating Activities. Our operating cash flow is dependent, in large part, on our production, realized commodity prices, leasing revenues, and operating expenses. For the year ended December 31, 2017, cash flows from operating activities increased by $85.2 million. This increase was primarily due to increased oil and natural gas revenue driven by higher oil and natural gas sales, an increase in lease bonus and other income, as well as changes in working capital, which was partially offset by increased production costs and ad valorem taxes and general and administrative expenses, as well as a decrease in net cash received on the settlement of commodity derivative financial instruments.

Investing Activities. The net cash used in investing activities increased by $232.7 million in 2017 as compared to 2016 primarily due to the cash portion of oil and natural gas properties acquisitions in 2017 being higher than the cash portion of oil and natural gas properties acquisitions in 2016, which was partially offset by increased proceeds from the sale of oil and natural gas properties and proceeds from farmouts of oil and natural gas properties.

Financing Activities. For the year ended December 31, 2017, financing activities increased by $146.8 million. The increase was primarily due to proceeds from the issuance of common units under our ATM Program and proceeds from the issuance of the Series B cumulative convertible preferred units. Decreased distributions to holders of the Series A redeemable preferred units and decreased repurchases of common and subordinated units also contributed to increased financing cash flows. These increases were partially offset by increased distributions to common and subordinated unitholders and a decrease in net borrowings under our credit facility compared to 2016.

Year Ended December 31, 2016 Compared to Year Ended December 31, 2015

Operating Activities. Our operating cash flow is dependent, in large part, on our production, realized commodity prices, leasing revenues, and operating expenses. For the year ended December 31, 2016, cash flows from operating activities decreased by $88.1 million. This decrease was primarily due to lower cash collections of $68.9 million related to oil and natural gas sales as compared to 2015 and the impact of $18.4 million in lower cash collections related to the settlement of commodity derivative instruments.

Investing Activities. The net cash used in investing activities increased by $130.5 million in 2016 as compared to 2015 primarily due to four mineral and property acquisitions that closed during 2016 and higher capital expenditures for our working interests.

Financing Activities. For the year ended December 31, 2016, we generated cash from financing activities as we increased borrowings under our credit facility and lowered distributions on our subordinated units as compared to the corresponding period in 2015. Financing activities were further impacted by the repurchase of common units.

Capital Expenditures

In the first quarter of each calendar year, we establish a capital budget and then monitor it throughout the year. Our capital budget is created based upon our estimate of internally-generated cash flows and the ability to borrow and raise additional capital. Actual capital expenditure levels will vary, in part, based on actual cash generated, the economics of wells proposed by our operators for our participation, and the successful closing of acquisitions. The timing, size, and nature of acquisitions are unpredictable. After the completion and approval of the capital budget, we establish an estimate of replacement capital expenditures.

Our 2018 capital expenditure budget associated with our working-interest participation program is expected to be between $15.0 million and $25.0 million, approximately 99% of which will be spent in the Haynesville/Bossier play with the remainder to be spent in various plays including the Bakken/Three Forks and Wolfcamp plays. We also expect to spend approximately $10 million to $12 million to drill two 100% working interest exploratory wells to evaluate a Lower Wilcox prospect in East Texas.

During 2017, we spent approximately $58.6 million related to drilling and completion costs. We also spent approximately $425.7 million related to acquisitions of oil and natural gas properties. Additionally, our capital expenditures were offset by proceeds from farmout agreements of approximately $19.2 million.

During 2016, we spent approximately $73.3 million related to drilling and completion costs. We also spent approximately$141.1 million related to four mineral acquisitions in 2016 as well as a final holdback payment from an acquisition in 2015.

During 2015, we spent approximately $54.2 million related to drilling and completion costs, the majority of which was in the Haynesville/Bossier, Bakken/Three Forks, and Wilcox plays. We also spent approximately $62.3 million on eight acquisitions. See Note 4 – Oil and Natural Gas Properties Acquisitions in the consolidated financial statements included elsewhere in this Annual Report for further discussion.

Credit Facility

Pursuant to our $1.0 billion secured revolving credit agreement, the commitment of the lenders equals the lesser of the aggregate maximum credit amounts of the lenders and the borrowing base, which is determined based on the lenders’ estimated value of our oil and natural gas properties. Borrowings under the credit facility may be used for the acquisition of properties, cash distributions, and other general corporate purposes. On November 1, 2017, we entered into the fourth amended and restated credit agreement to extend the maturity date thereof for a term of five years, create a swingline facility that permits short-term borrowings on same-day notice, and make other changes to the hedging and restrictive covenants. The borrowing base was reconfirmed at $550.0 million with our fall 2017 redetermination. Our credit facility now terminates on November 1, 2022. As of December 31, 2017, we had outstanding borrowings of $388.0 million at a weighted-average interest rate of 4.06%.

The borrowing base is redetermined semi-annually, typically in April and October of each year, by the administrative agent, taking into consideration the estimated loan value of our oil and natural gas properties consistent with the administrative agent’s normal lending criteria. The administrative agent’s proposed redetermined borrowing base must be approved by all lenders to increase our existing 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 election of two-thirds of the lenders) each have discretion to have the borrowing base redetermined once between scheduled redeterminations. Under the fourth amended and restated credit agreement, we additionally have the right to request a redetermination following acquisition of oil and natural gas properties in excess of 10% of the value of the borrowing base immediately prior to such acquisition.

Outstanding borrowings under the credit agreement bear interest at a floating rate elected by us equal to an alternative base rate (which is equal to the greatest of the Prime Rate, the Federal Funds effective rate plus 0.50%, or 1-month LIBOR plus 1.00%) or LIBOR, in each case, plus the applicable margin. Through October 2016, the applicable margin ranged from 0.50% to 1.50% in the case of the alternative base rate and from 1.50% to 2.50% in the case of LIBOR, in each case depending on the amount of borrowings outstanding in relation to the borrowing base. Subsequent to the closing of our fall redetermination on October 31, 2016, the applicable margin ranges from 1.00% to 2.00% in the case of the alternative base rate and from 2.00% to 3.00% in the case of LIBOR, depending on the borrowings outstanding in relation to the borrowing base.

We are obligated to pay a quarterly commitment fee ranging from a 0.375% to 0.500% annualized rate on the unused portion of the borrowing base, depending on the amount of the borrowings outstanding in relation to the borrowing base. Principal may be optionally repaid from time to time without premium or penalty, other than customary LIBOR breakage, and is required to 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 a cure period, or (b) at the maturity date. Our credit facility is secured by liens on substantially all of our producing properties.

Our 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 with affiliates, and entering into certain swap agreements, as well as require the maintenance of certain financial ratios. The credit agreement contains two financial covenants: total debt to EBITDAX of 3.5:1.0 or less and a modified current ratio of 1.0:1.0 or greater as defined in the credit agreement. Distributions are not permitted if there is a default under the credit agreement (including due to a failure to satisfy one of the financial covenants) or during any time that our borrowing base is lower than the loans outstanding under the credit agreement. The lenders have the right to accelerate all of the indebtedness under the credit agreement upon the occurrence and during the continuance of any event of default, and the credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy, and change of control. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods. As of December 31, 2017, we were in compliance with all debt covenants.

Contractual Obligations

The following table summarizes our minimum payments as of December 31, 2017 (in thousands):



			Payments due by period
	Total		Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years
Credit facility	$	388,000	$	—	$	—	$	388,000	$	—
Operating lease obligations	1,708		1,654		54		—		—
Purchase commitments	1,017		856		161		—		—
Total	$	390,725	$	2,510	$	215	$	388,000	$	—

Off-Balance Sheet Arrangements

At December 31, 2017, we did not have any material off-balance sheet arrangements.

Critical Accounting Policies and Related Estimates

The discussion and analysis of our financial condition and results of operations are based upon the consolidated financial statements, which have been prepared in accordance with GAAP. Certain of our accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts would have been reported under different conditions, or if different assumptions had been used. The following discussions of critical accounting estimates, including any related discussion of contingencies, address all important accounting areas where the nature of accounting estimates or assumptions could be material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility 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 our accounting policies.

Successful Efforts Method of Accounting

We follow the successful efforts method of accounting for oil and natural gas operations. Under this method, costs to acquire mineral and royalty interests and working interests in oil and natural gas properties, property acquisitions, successful exploratory wells, development costs, and support equipment and facilities are capitalized when incurred. Acquisitions of proved oil and natural gas properties and working interests are considered business combinations and are recorded at their estimated fair value as of the acquisition date. Acquisitions of unproved oil and natural gas properties are considered asset acquisitions and are recorded at cost.

The costs of unproved leaseholds and non-producing mineral interests are capitalized as unproved properties pending the results of exploration and leasing efforts. As unproved properties are determined to be productive, the related costs are transferred to proved oil and natural gas properties. The costs related to exploratory wells are capitalized pending determination of whether proved commercial reserves exist. If proved commercial reserves are not discovered, such drilling costs are expensed. In some circumstances, it may be uncertain whether proved commercial reserves have been discovered when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is ongoing. Other exploratory costs, including annual delay rentals and geological and geophysical costs, are expensed when incurred.

Oil and natural gas properties are grouped in accordance with the Extractive Industries – Oil and Gas Topic of the Financial Accounting Standards Board Accounting Standards Codification. The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field, which we may also refer to as a depletable unit.

As exploration and development work progresses and the reserves associated with our oil and natural gas properties become proved, capitalized costs attributed to the properties are charged as an operating expense through depreciation, depletion, and amortization ("DD&A"). DD&A of producing oil and natural gas properties is recorded based on the units-of-production method. Capitalized development costs are amortized on the basis of proved developed reserves while leasehold acquisition costs and the costs to acquire proved properties are amortized on the basis of all proved reserves, both developed and undeveloped. Proved reserves are quantities of oil and natural gas that can be estimated 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 our producing oil and natural gas properties was $114.3 million, $102.4 million and $102.7 million for the years ended December 31, 2017, 2016, and 2015, respectively.

We evaluate impairment of producing properties whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. This evaluation is performed on a depletable unit basis. We compare the undiscounted projected future cash flows expected in connection with a depletable unit to its unamortized carrying amount to determine recoverability. When the carrying amount of a depletable unit exceeds its estimated undiscounted 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 flows of such properties. The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, future capital expenditures, and a risk-adjusted discount rate.

There was no impairment of proved oil and natural gas properties for the year ended December 31, 2017. Impairment of proved oil and natural gas properties was $4.9 million and $127.8 million for the years ended December 31, 2016 and 2015, respectively. The impairments primarily resulted from declines in future expected realizable net cash flows. The charges are included in impairment of oil and natural gas properties on the consolidated statements of operations and reflected in the net book value of oil and natural gas properties.

Unproved properties are also assessed for impairment periodically on a depletable unit basis when facts and circumstances indicate that the carrying value may not be recoverable, at which point an impairment loss is recognized to the extent the carrying value exceeds the estimated recoverable value. The carrying value of unproved properties, including unleased mineral rights, is determined based on management’s assessment of fair value using factors similar to those previously noted for proved properties, as well as geographic and geologic data. There was no impairment of unproved properties for the year ended December 31, 2017. Impairment of unproved properties was $1.9 million and $121.8 million for the years ended December 31, 2016 and 2015, respectively.

Upon the sale of a complete depletable unit, the book value thereof, less proceeds or salvage value, is charged to income. Upon the sale or retirement of an individual well, or an aggregation of interests which make up less than a complete depletable unit, the proceeds are credited to accumulated DD&A, unless doing so would significantly alter the DD&A rate of the depletable unit, in which case a gain or loss is recorded.

We are unable to predict future commodity prices with any greater precision than the futures market. To estimate the effect lower prices would have on our reserves, we applied a 10% discount to the commodity prices used in our December 31, 2017 reserve report. Applying this discount results in an approximate 2.2% reduction of estimated proved reserve volumes as compared to the undiscounted pricing scenario used in our December 31, 2017 reserve report prepared by NSAI.

Asset Retirement Obligations

Under various contracts, permits, and regulations, we have legal obligations to restore the land at the end of operations at certain properties where we own non-operated working interests. Estimating the future restoration costs necessary for this accounting calculation is difficult. Most of these restoration obligations are many years, or decades, in the future and the contracts and regulations often have vague descriptions of what practices and criteria must be met when the event actually occurs. Asset-restoration technologies and costs, regulatory and other compliance considerations, expenditure timing, and other inputs into the valuation of the obligation, including discount and inflation rates, are also subject to change.

Fair values of legal obligations to retire and remove long-lived assets are recorded when the obligation is incurred and becomes determinable. When the liability is initially recorded, we capitalize this cost by increasing the carrying amount of the related property. Over time, the liability is accreted 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 with the related asset.

Revenue Recognition

We recognize revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller’s price to the buyer is fixed or determinable, and (iv) collectability is reasonably assured.

We recognize oil and natural gas revenue from our interests in producing wells when the associated production is sold. The volumes of natural gas sold may differ from the volumes to which we are entitled based on our interests in the properties. These differences create imbalances that are recognized as a liability only when the properties’ estimated remaining reserves, net to us, will not be sufficient to enable the under-produced owner to recoup its entitled share through production; however, such amounts are de minimis at December 31, 2017 and 2016.

To the extent actual volumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volume and prices for these properties are estimated and recorded within accounts receivable in the accompanying consolidated balance sheets. Crude oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. Natural gas contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality and heat content of natural gas, and prevailing supply and demand conditions, so that the price of natural gas fluctuates to remain competitive with other available natural gas supplies. These market indices are determined on a monthly basis.

Other sources of revenue we receive include mineral lease bonuses and delay rentals. We generate lease bonus revenue by leasing our mineral interests to exploration and production companies. The lease agreements generally transfer the rights to any oil or natural gas discovered, grant us a right to a specified royalty interest, and require that drilling and completion operations commence within a specified time period. We recognize such lease bonus revenue at which time the lease agreement has been executed, payment is determined to be collectable, and we have no further obligation to refund the payment. We also recognize revenue from delay rentals to the extent drilling has not started within the specified period, payment has been collected, and we have no further obligation to refund the payment.

Commodity Derivative Financial Instruments

Our ongoing operations expose us to changes in the market price for oil and natural gas. To mitigate the given price risk associated with its operations, we use commodity derivative financial instruments. From time to time, such instruments may include variable-to-fixed price swaps, costless collars, fixed price contracts, and other contractual arrangements. We do not enter into derivative instruments for speculative purposes. The impact of these derivative instruments 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 fair value of derivatives are recognized on a net basis in the accompanying consolidated statements of operations within gain (loss) on commodity derivative instruments. Although these derivative instruments may expose us to credit risk, we monitor the creditworthiness of our counterparties.

Equity-Based Compensation

We 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 expected to vest multiplied by the grant-date fair value per unit. Compensation expense for time-based restricted unit awards with graded vesting requirements are recognized using straight-line attribution over the requisite service period. Compensation expense related to the restricted performance unit awards is determined by multiplying the number of common units underlying such awards that, based on our estimates, are likely to vest, by the grant-date fair value and recognized using the accelerated attribution method. Equity-based compensation expense related to unit-based awards is included in general and administrative expense within the consolidated statements of operations. Distribution equivalent rights for the restricted performance unit awards that are expected to vest are charged to partners’ capital. Please read Note 9 – Incentive Compensation within the consolidated financial statements included elsewhere in this Annual Report for additional information.

Prior to our IPO, the board of directors of our Predecessor determined the fair value of unit-based awards by considering various objective and subjective factors, along with input from management, and using the same methodology as required under our Predecessor’s partnership agreement 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 and relied on generally accepted valuation techniques, which included the net asset value method under the asset approach, the guideline public company method under the market approach, and the dividend discount method of the income approach. Estimates of value using the net asset value method were derived using assumptions including commodity prices, estimated development timing of our acreage, and market-based discount rates. The value conclusion using the guideline public company method was estimated by considering peer company performance metrics, comparability of the peer company 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. The dividend discount method was developed based on assumptions including our projected distributions, anticipated long-term distribution growth rates, and near- and long-term cost of capital estimates. In determining the fair value of the awards, the board of directors of our Predecessor also considered our historical transactions and performance in making these estimates.

New and Revised Financial Accounting Standards

The effects of new accounting pronouncements are discussed in Note 2 – Summary of Significant Accounting Policies within the consolidated financial statements included elsewhere in this Annual Report.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

Our major market risk exposure is the pricing of oil, natural gas, and NGLs produced by our operators. Realized prices are primarily driven by the prevailing global prices for oil and prices for natural gas and NGLs in the United States. Prices for oil, natural gas, and NGLs have been volatile for several years, and we expect this unpredictability to continue in the future. The prices that our operators 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 financial instruments to reduce our exposure to price volatility of oil and natural gas. The counterparties to the contracts are unrelated third parties. The contracts settle monthly in cash based on a designated floating price. The designated floating price is based on the NYMEX benchmark for oil and natural gas. We have not designated any of our contracts as fair value or cash flow hedges. Accordingly, the changes in fair value of the contracts are included in net income in the period of the change. See Note 5 – Commodity Derivative Financial Instruments and Note 6 – Fair Value Measurements to the consolidated financial statements included elsewhere in this Annual Report for additional information.

Commodity prices have declined in recent years. To estimate the effect lower prices would have on our reserves, we applied a 10% discount to the SEC commodity pricing for the twelve months ended December 31, 2017. Applying this discount results in an approximate 2.2% reduction of proved reserve volumes as compared to the undiscounted December 31, 2017 SEC pricing scenario.

Counterparty and Customer Credit Risk

Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require our counterparties to our derivative contracts to post collateral, we do evaluate the credit standing of such counterparties as we deem appropriate. This evaluation includes reviewing a counterparty’s credit rating and latest financial information. As of December 31, 2017, we had nine counterparties, all of which are rated Baa1 or better by Moody’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 our significant operators to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. However, we believe the credit risk associated with our operators and customers is acceptable.

Interest Rate Risk

We have exposure to changes in interest rates on our indebtedness. As of December 31, 2017, we had $388.0 million of outstanding borrowings under our credit facility, bearing interest at a weighted-average interest rate of 4.06%. The impact of a 1% increase in the interest rate on this amount of debt would have resulted in an increase in interest expense, and a corresponding decrease in our results of operations, of $3.9 million for the year ended December 31, 2017, assuming that our indebtedness remained constant throughout the period. We may use certain derivative instruments to hedge our exposure to variable interest rates in the future, but we do not currently have any interest rate hedges in place.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The 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 DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of management of our general partner, including our general partner’s principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Annual Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to management, including our general partner’s principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our general partner’s principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2017 to provide such reasonable assurance.

Management’s Annual Report on Internal Control over Financial Reporting

Our general partner’s management, including our general partner’s principal executive officer and principal financial officer, is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Exchange Act. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external purposes in accordance with GAAP.

There are inherent limitations in the effectiveness of internal control over financial reporting, including the possibility that misstatements may not be prevented or detected. Accordingly, even effective internal controls over financial reporting can provide only reasonable assurance with respect to financial statement preparation.

Under the supervision and with the participation of our general partner's principal executive officer and principal financial officer, our general partner’s management assessed the effectiveness of our internal control over financial reporting as of December 31, 2017, using the criteria in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, our general partner’s management believes that our internal control over financial reporting was effective as of December 31, 2017.

This Annual Report includes an attestation report of Ernst & Young LLP, our independent registered public accounting firm, on our internal control over financial reporting as of December 31, 2017, which is included in the Annual Report on page F-3.

Changes in Internal Control over Financial Reporting

There were no changes in our system of internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act) during the quarter ended December 31, 2017, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE

Information required by this item is incorporated by reference to the material appearing in our Proxy Statement for the 2018 Annual Meeting of Limited Partners (“2018 Proxy Statement”), which will be filed with the SEC not later than 120 days after December 31, 2017.

We have a Code of Business Conduct and Ethics that applies to our directors, officers, and employees as well as a Financial Code of Ethics that applies to our Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer and the other senior financial officers, each as required by SEC and NYSE rules. Each of the foregoing is available on our website at www.blackstoneminerals.com in the “Corporate Governance” section. We will provide copies, 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, Texas 77002, Attn: Investor Relations. We intend to disclose amendments to and waivers from our Financial Code of Ethics, if any, on our website, www.blackstoneminerals.com, promptly following the date of any such amendment or waiver.

ITEM 11. EXECUTIVE COMPENSATION

Information required by this item is incorporated by reference to the 2018 Proxy Statement, which will be filed with the SEC not later than 120 days after December 31, 2017.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

Information required by this item is incorporated by reference to the 2018 Proxy Statement, which will be filed with the SEC not later than 120 days after December 31, 2017.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

Information required by this item is incorporated by reference to the 2018 Proxy Statement, which will be filed with the SEC not later than 120 days after December 31, 2017.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Information required by this item is incorporated by reference to the 2018 Proxy Statement, which will be filed with the SEC not later than 120 days after December 31, 2017.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)(1) Financial Statements

Our Consolidated Financial Statements are included under Part II, Item 8 of this Annual Report. For a listing of these statements and accompanying notes, please read “Index to Financial Statements” on page F-1 of this Annual Report.

(a)(2) Financial Statement Schedules

All schedules have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidated financial statements or notes thereto.

(a)(3) Exhibits

The following documents are filed as a part of this Annual Report or incorporated by reference:



Exhibit Number		Description

2.1**		Purchase and Sale Agreement, dated as of November 22, 2017, by and among Noble Energy Inc., Noble Energy Wyco, LLC, Noble Energy US Holdings, LLC, Rosetta Resources Operating LP, and Black Stone Minerals Company, L.P. (incorporated herein by reference to Exhibit 2.1 of Black Stone Minerals, L.P.'s Current Report of Form 8-K filed on November 29, 2017 (SEC File No. 001-37362))

3.1		Certificate of Limited Partnership of Black Stone Minerals, L.P. (incorporated herein by reference to Exhibit 3.1 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)).

3.2		Certificate of Amendment to Certificate of Limited Partnership of Black Stone Minerals, L.P. (incorporated herein by reference to Exhibit 3.2 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)).

3.3		First Amended and Restated Agreement of Limited Partnership of Black Stone Minerals, L.P., dated May 6, 2015, by and among Black Stone Minerals GP, L.L.C. and Black Stone Minerals Company, L.P., (incorporated herein by reference to Exhibit 3.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on May 6, 2015 (SEC File No. 001-37362)).

3.4		Amendment No. 1 to First Amended and Restated Agreement of Limited Partnership of Black Stone Minerals, L.P., dated as of April 15, 2016 (incorporated herein by reference to Exhibit 3.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on April 19, 2016 (SEC File No. 001-37362)).

3.5		Amendment No. 2 to First Amended and Restated Agreement of Limited Partnership of Black Stone Minerals, L.P., dated as of November 28, 2017 (incorporated herein by reference to Exhibit 3.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on November 29, 2017 (SEC File No. 001-37362)).

3.6		Amendment No. 3 to First Amended and Restated Agreement of Limited Partnership of Black Stone Minerals, L.P., dated as of December 11, 2017 (incorporated herein by reference to Exhibit 3.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on December 12, 2017 (SEC File No. 001-37362)).

4.1		Registration Rights Agreement, dated as of November 28, 2017, by and between Black Stone Minerals, L.P. and Minerals Royalties One, L.L.C. (incorporated herein by reference to Exhibit 4.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on December 12, 2017 (SEC File No. 001-37362)).

10.1^		Black Stone Minerals, L.P. Long-Term Incentive Plan, dated May 6, 2015, by Black Stone Minerals GP, L.L.C. (incorporated herein 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		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, Wells Fargo Bank, N.A. and Amegy Bank National Association, as Co-Documentation Agents, and a syndicate of lenders dated as of January 23, 2015 (incorporated herein by reference to Exhibit 10.2 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)).

10.3		Fourth Amended and Restated Credit Agreement, among Black Stone Minerals Company, L.P., as Borrower, Black Stone Minerals, L.P., as Parent MLP, Wells Fargo Bank, National Association, as Administrative Agent, Bank of America, N.A. and Compass Bank, as Co-Syndication Agents, ZB Bank, N.A. DBA and Amegy Bank National Association, as Documentation Agent, and the lenders signatory thereto, dated as of November 1, 2017 (incorporated herein by reference to Exhibit 10.1 to Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on November 7, 2017 (SEC File No. 001-37362)).

10.4*#		First Amendment to Fourth Amended and Restated Credit Agreement among Black Stone Minerals Company, L.P., as Borrower, Wells Fargo Bank, National Association, as Administrative Agent and Swingline Lender, Bank of America, N.A. and Compass Bank, as Co-Syndication Agents, ZB Bank, N.A., DBA Amegy Bank, National Association, as Documentation Agent, and a syndicate of lenders dated as of February 7, 2018.

10.5^		Employment Agreement by and between Black Stone Minerals Company, L.P. and Thomas L. Carter, Jr. effective as of April 1, 2009 (incorporated herein by reference to Exhibit 10.3 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)).

10.6^		First Amendment to Employment Agreement by and between Black Stone Minerals Company, L.P. and Thomas L. Carter, Jr. effective as of June 25, 2014 (incorporated herein by reference to Exhibit 10.4 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)).

10.7^		Black Stone Minerals Company, L.P. 2012 Executive Incentive Plan (incorporated herein by reference to Exhibit 10.5 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)).

10.8^		Restricted Unit Award Agreement by and between Black Stone Minerals Company, L.P. and Thomas L. Carter, Jr. effective as of January 1, 2012 (incorporated herein by reference to Exhibit 10.6 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed 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 Marc Carroll effective as of January 1, 2012 (incorporated herein by reference to Exhibit 10.7 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)).

10.10^		Restricted Unit Award Agreement by and between Black Stone Minerals Company, L.P. and Holbrook F. Dorn effective as of January 1, 2012 (incorporated herein by reference to Exhibit 10.8 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)).

10.11^		Form of IPO Award Grant Notice and Award Agreement for Senior Management (Restricted Units) (incorporated herein by reference to Exhibit 10.9 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on April 13, 2015 (SEC File No. 333-202875)).

10.12^		Form of IPO Award Grant Notice and Award Agreement for Senior Management (Performance Units) (incorporated herein by reference to Exhibit 10.10 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on April 13, 2015 (SEC File No. 333-202875)).

10.13^		Form of Non-Employee Director Unit Grant Notice and Award Agreement (incorporated herein by reference to Exhibit 10.11 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on April 13, 2015 (SEC File No. 333-202875)).

10.14^		Form of Severance Agreement for Thomas L. Carter, Jr. (incorporated herein by reference to Exhibit 10.12 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on April 13, 2015 (SEC File No. 333-202875)).

10.15^		Form of Severance Agreement for Senior Vice Presidents (incorporated herein by reference to Exhibit 10.13 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on April 13, 2015 (SEC File No. 333-202875)).

10.16^		Form of LTI Award Grant Notice and LTI Award Agreement (Leadership) under the Black Stone Minerals, L.P. Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.2 to Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on February 19, 2016 (SEC File No. 001-37362).

10.17*		Form of STI Award Letter (Leadership) under the Black Stone Minerals, L.P. Long-Term Incentive Plan.



10.18^		Separation and Consulting Agreement and General Release of Claims, dated as of November 21, 2016, by and among Marc Carroll, Black Stone Natural Resources Management Company, and Black Stone Minerals GP, L.L.C. (incorporated herein by reference to Exhibit 10.1 Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on November 28, 2016 (SEC File No. 001-37362)).

10.19		Series B Preferred Unit Purchase Agreement, dated as of November 22, 2017, by and between Black Stone Minerals, L.P. and Mineral Royalties One, L.L.C. (incorporated herein by reference to Exhibit 10.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on December 12, 2017 (SEC File No. 001-37362)).

21.1*		List of Subsidiaries of Black Stone Minerals, L.P.

23.1*		Consent of Ernst & Young LLP

23.2*		Consent of BDO USA, LLP

23.3*		Consent of Netherland, Sewell & Associates, Inc.

31.1*		Certification of Chief Executive Officer of Black Stone Minerals, L.P. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2*		Certification of Chief Financial Officer of Black Stone Minerals, L.P. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1*		Certification of Chief Executive Officer and Chief Financial Officer of Black Stone Minerals, L.P. pursuant to 18 U.S.C. Section 1350, 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.
**	Schedules and exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The Partnership agrees to furnish supplementally a copy of the omitted schedules and exhibits to the SEC upon request.
^	Management contract or compensatory plan or arrangement.
#	The agreement filed herewith is a corrected version of the agreement previously filed as Exhibit 10.1 to the Current Report on Form 8-K filed on February 12, 2018.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



		BLACK STONE MINERALS, L.P.

	By:	Black Stone Minerals GP, L.L.C., its general partner

February 28, 2018	By:	/s/ Thomas L. Carter, Jr.
		Thomas L. Carter, Jr.
		President, Chief Executive Officer, and Chairman

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 the registrant and in the capacities and on the dates indicated.



Signature	Title	Date


/s/ Thomas L. Carter, Jr.	President, Chief Executive Officer, and Chairman	February 28, 2018
Thomas L. Carter, Jr.	(Principal Executive Officer)

/s/ Jeffrey P. Wood	Senior Vice President and Chief Financial Officer	February 28, 2018
Jeffrey P. Wood	(Principal Financial Officer)

/s/ Dawn K. Smajstrla	Vice President and Chief Accounting Officer	February 28, 2018
Dawn K. Smajstrla	(Principal Accounting Officer)

/s/ William G. Bardel	Director	February 28, 2018
William G. Bardel

/s/ Carin M. Barth	Director	February 28, 2018
Carin M. Barth

/s/ D. Mark DeWalch	Director	February 28, 2018
D. Mark DeWalch

/s/ Ricky J. Haeflinger	Director	February 28, 2018
Ricky J. Haeflinger

/s/ Jerry V. Kyle, Jr.	Director	February 28, 2018
Jerry V. Kyle, Jr.

/s/ Michael C. Linn	Director	February 28, 2018
Michael C. Linn

/s/ John H. Longmaid	Director	February 28, 2018
John H. Longmaid

/s/ William N. Mathis	Director	February 28, 2018
William N. Mathis

/s/ William E. Randall	Director	February 28, 2018
William E. Randall

/s/ Alexander D. Stuart	Director	February 28, 2018
Alexander D. Stuart

/s/ Allison K. Thacker	Director	February 28, 2018
Allison K. Thacker

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

BLACK STONE MINERALS, L.P.



Reports of Independent Registered Public Accounting Firms		F-2

Consolidated Balance Sheets as of December 31, 2017 and December 31, 2016		F-5

Consolidated Statements of Operations for the Years Ended December 31, 2017, 2016 and 2015		F-6

Consolidated Statements of Equity for the Years Ended December 31, 2017, 2016 and 2015		F-7

Consolidated Statements of Cash Flows for the Years Ended December 31, 2017, 2016 and 2015		F-8

Notes to Consolidated Financial Statements		F-9

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Audit Committee of the Board of Directors and Unitholders of

Black Stone Minerals, L.P. and subsidiaries

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Black Stone Minerals, L.P. and subsidiaries (the "Partnership") as of December 31, 2017 and 2016, the related consolidated statements of operations, equity and cash flows for each of the two years in the period ended December 31, 2017, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the consolidated financial position of the Partnership at December 31, 2017 and 2016, and the consolidated results of its operations and its cash flows for each of the two years in the period ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Partnership’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 28, 2018 expressed an unqualified opinion thereon.

Basis for Opinion

These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Ernst & Young LLP

We have served as the Partnership’s auditor since 2016.

Houston, Texas

February 28, 2018

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Audit Committee of the Board of Directors and Unitholders of

Black Stone Minerals, L.P. and subsidiaries

Opinion on Internal Control over Financial Reporting

We have audited Black Stone Minerals, L.P. and subsidiaries’ internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the "COSO criteria"). In our opinion, Black Stone Minerals, L.P. and subsidiaries (the "Partnership") maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Partnership as of December 31, 2017 and 2016, the related consolidated statements of operations, equity and cash flows for each of the two years in the period ended December 31, 2017, and the related notes and our report dated February 28, 2018 expressed an unqualified opinion thereon.

Basis for Opinion

The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying “Management’s Annual Report on Internal Control over Financial Reporting.” Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulation of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A partnership’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A partnership’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the partnership; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the partnership are being made only in accordance with authorizations of management and directors of the partnership; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the partnership’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young LLP

Houston, Texas

February 28, 2018

F-3

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Partners of

Black Stone Minerals, L.P.

Houston, Texas

We have audited the accompanying consolidated statements of operations, equity, and cash flows of Black Stone Minerals, L.P. and subsidiaries (the “Partnership”) for the year ended December 31, 2015. These consolidated financial statements are the responsibility of the Partnership’s management. 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 that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the results of operations and cash flows of Black Stone Minerals, L.P. and subsidiaries for the year ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America.

/s/ BDO USA, LLP

Houston, Texas

March 8, 2016

F-4

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)



	As of December 31,
	2017			2016
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	5,642		$	9,772
Accounts receivable	80,695			68,181
Commodity derivative assets	94			—
Prepaid expenses and other current assets	1,212			1,036
TOTAL CURRENT ASSETS	87,643			78,989
PROPERTY AND EQUIPMENT
Oil and natural gas properties, at cost, using the successful efforts method of accounting, includes unproved properties of $988,720 and $605,736 at December 31, 2017 and 2016, respectively	3,247,613			2,697,073
Accumulated depreciation, depletion, amortization, and impairment	(1,766,842		)	(1,652,930		)
Oil and natural gas properties, net	1,480,771			1,044,143
Other property and equipment, net of accumulated depreciation of $14,433 and $14,327 at December 31, 2017 and 2016, respectively	559			528
NET PROPERTY AND EQUIPMENT	1,481,330			1,044,671
DEFERRED CHARGES AND OTHER LONG-TERM ASSETS	7,478			5,167
TOTAL ASSETS	$	1,576,451		$	1,128,827
LIABILITIES, MEZZANINE EQUITY, AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	2,464		$	4,142
Accrued liabilities	52,631			50,952
Commodity derivative liabilities	4,222			16,237
Other current liabilities	417			—
TOTAL CURRENT LIABILITIES	59,734			71,331
LONG-TERM LIABILITIES
Credit facility	388,000			316,000
Accrued incentive compensation	3,648			1,485
Commodity derivative liabilities	1,263			482
Deferred revenue	—			518
Asset retirement obligations	14,092			13,350
Other long-term liabilities	19,171			—
TOTAL LIABILITIES	485,908			403,166
COMMITMENTS AND CONTINGENCIES (Note 11)
MEZZANINE EQUITY
Partners' equity — Series A redeemable preferred units, 26 and 53 units outstanding at December 31, 2017 and 2016, respectively	27,028			54,015
Partners' equity — Series B cumulative convertible preferred units, 14,711 and 0 units outstanding at December 31, 2017 and 2016, respectively	295,394			—
EQUITY
Partners' equity — general partner interest	—			—
Partners' equity — common units, 103,456 and 95,721 units outstanding at December 31, 2017 and 2016, respectively	603,116			489,023
Partners' equity — subordinated units, 95,388 and 95,164 units outstanding at December 31, 2017 and 2016, respectively	164,138			181,602
Noncontrolling interests	867			1,021
TOTAL EQUITY	768,121			671,646
TOTAL LIABILITIES, MEZZANINE EQUITY, AND EQUITY	$	1,576,451		$	1,128,827

The accompanying notes to consolidated financial statements are an integral part of these financial statements.

F-5

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit amounts)



	Year Ended December 31,
	2017			2016			2015
REVENUE
Oil and condensate sales	$	169,728		$	142,382		$	163,538
Natural gas and natural gas liquids sales	190,967			122,836			116,018
Gain (loss) on commodity derivative instruments	26,902			(36,464		)	90,288
Lease bonus and other income	42,062			32,079			23,080
TOTAL REVENUE	429,659			260,833			392,924
OPERATING (INCOME) EXPENSE
Lease operating expense	17,280			18,755			21,583
Production costs and ad valorem taxes	47,474			35,464			35,767
Exploration expense	618			645			2,592
Depreciation, depletion and amortization	114,534			102,487			104,298
Impairment of oil and natural gas properties	—			6,775			249,569
General and administrative	77,574			73,139			77,175
Accretion of asset retirement obligations	1,026			892			1,075
(Gain) loss on sale of assets, net	(931		)	(4,793		)	(4,873		)
Other expense	—			—			1,593
TOTAL OPERATING EXPENSE	257,575			233,364			488,779
INCOME (LOSS) FROM OPERATIONS	172,084			27,469			(95,855		)
OTHER INCOME (EXPENSE)
Interest and investment income	49			656			58
Interest expense	(15,694		)	(7,547		)	(6,418		)
Other income (expense)	714			(390		)	910
TOTAL OTHER EXPENSE	(14,931		)	(7,281		)	(5,450		)
NET INCOME (LOSS)	157,153			20,188			(101,305		)
Net loss attributable to Predecessor	—			—			(450		)
Net income attributable to noncontrolling interests subsequent to initial public offering	34			12			1,260
Distributions on Series A redeemable preferred units subsequent to initial public offering	(3,117		)	(5,763		)	(7,522		)
Distributions on Series B cumulative convertible preferred units	(1,925		)	—			—
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS SUBSEQUENT TO INITIAL PUBLIC OFFERING	$	152,145		$	14,437		$	(108,017	)
ALLOCATION OF NET INCOME (LOSS) SUBSEQUENT TO INITIAL PUBLIC OFFERING ATTRIBUTABLE TO:
General partner interest	$	—		$	—		$	—
Common units	98,389			24,669			(54,326		)
Subordinated units	53,756			(10,232		)	(53,691		)
	$	152,145		$	14,437		$	(108,017	)
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:
Per common unit (basic)	$	1.01		$	0.26		$	(0.56	)
Weighted average common units outstanding (basic)	97,400			96,073			96,182
Per subordinated unit (basic)	$	0.56		$	(0.11	)	$	(0.56	)
Weighted average subordinated units outstanding (basic)	95,149			95,138			95,057
Per common unit (diluted)	$	1.01		$	0.26		$	(0.56	)
Weighted average common units outstanding (diluted)	97,400			96,243			96,182
Per subordinated unit (diluted)	$	0.56		$	(0.11	)	$	(0.56	)
Weighted average subordinated units outstanding (diluted)	95,149			95,138			95,057
DISTRIBUTIONS DECLARED AND PAID SUBSEQUENT TO INITIAL PUBLIC OFFERING:
Per common unit	$	1.20		$	1.10		$	0.42
Per subordinated unit	$	0.79		$	0.74		$	0.42

The accompanying notes to consolidated financial statements are an integral part of these financial statements.

F-6

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

(in thousands)



	Predecessor				Black Stone Minerals, L.P.
	Predecessor units		Partners' equity		Common units		Subordinated units		Partners' equity— common units			Partners' equity— subordinated units			Noncontrolling interests			Total equity
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 noncontrolling interests	—		(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 of offering 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 distribution equivalent rights	—		—		—		—		(159		)	—			—			(159		)
Net loss subsequent to initial public offering	—		—		—		—		(50,543		)	(49,952		)	(1,260		)	(101,755		)
Distributions on Series A 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
Conversion of Series A redeemable preferred units	—		—		184		241		2,625			3,439			—			6,064
Repurchases of common and subordinated units	—		—		(1,618	)	(78	)	(27,436		)	—			—			(27,436		)
Restricted common and subordinated units granted, net of forfeitures	—		—		993		(56	)	—			—			—			—
Equity-based compensation	—		—		—		—		21,022			2,823			—			23,845
Distributions	—		—		—		—		(105,817		)	(70,127		)	(111		)	(176,055		)
Charges to partners' equity for accrued distribution equivalent rights	—		—		—		—		(688		)	—			—			(688		)
Net income (loss)	—		—		—		—		27,565			(7,365		)	(12		)	20,188
Distributions on Series A redeemable preferred units	—		—		—		—		(2,896		)	(2,867		)	—			(5,763		)
BALANCE AT DECEMBER 31, 2016	—		—		95,721		95,164		489,023			181,602			1,021			671,646
Conversion of Series A redeemable preferred units	—		—		201		263		2,868			3,756			—			6,624
Repurchases of common and subordinated units	—		—		(446	)	(39	)	(7,893		)	(292		)	—			(8,185		)
Issuance of common units, net of offering costs	—		—		2,002		—		32,458			—			—			32,458
Issuance of units for property acquisitions	—		—		4,348		—		71,723			—			—			71,723
Restricted units granted, net of forfeitures	—		—		1,630		—		—			—			—			—
Equity-based compensation	—		—		—		—		39,205			152			—			39,357
Distributions	—		—		—		—		(119,963		)	(74,836		)	(120		)	(194,919		)
Charges to partners' equity for accrued distribution equivalent rights	—		—		—		—		(2,694		)	—			—			(2,694		)
Net income (loss)	—		—		—		—		101,891			55,296			(34		)	157,153
Distributions on Series A redeemable preferred units	—		—		—		—		(1,577		)	(1,540		)	—			(3,117		)
Distributions on Series B cumulative convertible preferred units	—		—		—		—		(1,925		)	—			—			(1,925		)
BALANCE AT DECEMBER 31, 2017	—		—		103,456		95,388		$	603,116		$	164,138		$	867		$	768,121

The accompanying notes to consolidated financial statements are an integral part of these financial statements.

F-7

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)



	Year Ended December 31,
	2017			2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	157,153		$	20,188		$	(101,305	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization	114,534			102,487			104,298
Impairment of oil and natural gas properties	—			6,775			249,569
Accretion of asset retirement obligations	1,026			892			1,075
Amortization of deferred charges	877			871			935
(Gain) loss on commodity derivative instruments	(26,902		)	36,464			(90,288		)
Net cash received (paid) on settlement of commodity derivative instruments	15,211			44,789			63,225
Equity-based compensation	33,044			43,138			18,000
(Gain) loss on sale of assets, net	(931		)	(4,793		)	(4,873		)
Changes in operating assets and liabilities:
Accounts receivable	(6,084		)	(29,759		)	33,586
Prepaid expenses and other current assets	(177		)	(180		)	95
Accounts payable and accrued liabilities	(3,585		)	(23,029		)	11,221
Deferred revenue	(2,086		)	(870		)	(660		)
Settlement of asset retirement obligations	(228		)	(317		)	(143		)
NET CASH PROVIDED BY OPERATING ACTIVITIES	281,852			196,656			284,735
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisitions of oil and natural gas properties	(425,667		)	(141,136		)	(62,278		)
Additions to oil and natural gas properties	(58,648		)	(80,179		)	(54,244		)
Purchases of other property and equipment	(207		)	(425		)	(181		)
Proceeds from the sale of oil and natural gas properties	11,102			198			25,705
Proceeds from farmouts of oil and natural gas properties	19,171			—			—
NET CASH USED IN INVESTING ACTIVITIES	(454,249		)	(221,542		)	(90,998		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of common units of Black Stone Minerals, L.P., net of offering costs	32,458			—			399,087
Proceeds from issuance of Series B cumulative convertible preferred units of Black Stone Minerals, L.P., net of offering costs	293,469			—			—
Distributions to Predecessor unitholders	—			—			(126,383		)
Distributions to common and subordinated unitholders	(194,799		)	(175,943		)	(81,087		)
Distributions to Series A redeemable preferred unitholders	(3,777		)	(6,385		)	(13,578		)
Distributions to noncontrolling interests	(120		)	(111		)	(208		)
Redemption of Series A redeemable preferred units	(19,704		)	(18,461		)	(40,747		)
Repurchases of Predecessor units	—			—			(3,015		)
Repurchases of common and subordinated units	(8,185		)	(27,436		)	—
Borrowings under credit facility	292,500			349,000			245,600
Repayments under credit facility	(220,500		)	(99,000		)	(573,600		)
Debt issuance costs	(3,075		)	(239		)	(1,376		)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	168,267			21,425			(195,307		)
NET CHANGE IN CASH AND CASH EQUIVALENTS	(4,130		)	(3,461		)	(1,570		)
Cash and cash equivalents — beginning of the year	9,772			13,233			14,803
Cash and cash equivalents — end of the year	$	5,642		$	9,772		$	13,233
SUPPLEMENTAL DISCLOSURE
Interest paid	$	14,761		$	6,535		$	5,478
NON-CASH ACTIVITIES
Accrued distributions payable to Predecessor unitholders	$	—		$	—		$	(53,248	)
Conversion of Series A redeemable preferred units	(6,624		)	(6,064		)	(39,240		)
Accrued distributions payable to Series A redeemable preferred unitholders	(660		)	(1,324		)	(2,016		)
Accrued distributions payable to Series B cumulative convertible preferred unitholders	(1,925		)	—			—
Additions to oil and natural gas properties financed through accounts payable and accrued liabilities	34,247			26,553			21,496
Public offering costs capitalized and offset against proceeds from initial public offering	—			—			7,587
Asset retirement obligations incurred and revisions in estimated costs	391			2,009			272
Accrued distribution equivalent rights	2,694			847			159

The accompanying notes to consolidated financial statements are an integral part of these financial statements.

F-8

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 — BUSINESS AND BASIS OF PRESENTATION

Description of the Business

Black Stone Minerals, L.P. (“BSM” or the “Partnership”) is a publicly traded Delaware limited partnership formed on September 16, 2014. On May 6, 2015, BSM completed its initial public offering (the “IPO”) of 22,500,000 common units representing limited partner interests at a price to the public of $19.00 per common unit. BSM received proceeds of $391.5 million from the sale of its common units, net of underwriting discount, structuring fee, and offering expenses (including costs previously incurred and capitalized). BSM used the net proceeds from the IPO to repay substantially all indebtedness outstanding under its Credit Facility, as defined in Note 8 – Credit Facility. On May 1, 2015, BSM’s common units began trading on the New York Stock Exchange under the symbol “BSM.”

Black Stone Minerals Company, L.P., a Delaware limited partnership, and its subsidiaries (collectively referred to as “BSMC” or the “Predecessor”) own oil and natural gas mineral and royalty interests in the United States ("U.S.") . In connection with the IPO, BSMC was merged into a wholly owned subsidiary of BSM, with BSMC as the surviving entity. Pursuant to the merger, the Class A and Class B common units representing limited partner interests of the Predecessor were converted into an aggregate of 72,574,715 common units and 95,057,312 subordinated units of BSM at a conversion ratio of 12.9465:1 for 0.4329 common units and 0.5671 subordinated units, and the preferred units of BSMC were converted into an aggregate of 117,963 Series A redeemable preferred units of BSM at a conversion ratio of one to one. The merger was accounted for as a combination of entities under common control with assets and liabilities transferred at their carrying amounts in a manner similar to a pooling of interests. Unless otherwise stated or the context otherwise indicates, all references to the “Partnership” or similar expressions for time periods prior to the IPO refer to Black Stone Minerals Company, L.P. and its subsidiaries, the Predecessor, for accounting purposes. For time periods subsequent to the IPO, these terms refer to Black Stone Minerals, L.P. and its subsidiaries.

In addition to mineral interests, which make up the vast majority of the asset base, the Partnership's assets also include nonparticipating royalty interests and overriding royalty interests. These interests, which are substantially non-cost-bearing, are collectively referred to as “mineral and royalty interests.” The Partnership’s mineral and royalty interests are located in 41 states and 64 onshore oil and natural gas producing basins of the continental U.S., including all of the major onshore producing basins. The Partnership also owns non-operated working interests in certain oil and natural gas properties.

Basis of Presentation

The accompanying audited consolidated financial statements of the Partnership have been prepared in accordance with generally accepted accounting principles (“GAAP”) in the U.S. and pursuant to the rules and regulations of the U.S. Securities and Exchange Commission ("SEC").

The consolidated financial statements include the consolidated results of the Partnership, which also includes the results of the Noble Acquisition (as defined below) for the period from November 28, 2017 through December 31, 2017, as discussed in Note 4 – Oil and Natural Gas Properties Acquisitions.

In the opinion of management, all material adjustments, which are of a normal and recurring nature, necessary for the fair presentation of the financial results for all periods presented have been reflected. All intercompany balances and transactions have been eliminated.

The Partnership evaluates the significant terms of its investments to determine the method of accounting to be applied to each respective investment. Investments in which the Partnership has less than a 20% ownership interest and does not have control or exercise significant influence are accounted for under the cost method. The Partnership’s cost method investment is included in deferred charges and other long-term assets in the consolidated balance sheets. Investments in which the Partnership exercises control are consolidated, and the noncontrolling interests of such investments, which are not attributable directly or indirectly to the Partnership, are presented as a separate component of net income and equity in the accompanying consolidated financial statements.

The consolidated financial statements include undivided interests in oil and natural gas property rights. The Partnership accounts for its share of oil and natural gas property rights by reporting its proportionate share of assets, liabilities, revenues, costs, and cash flows within the relevant lines on the accompanying consolidated balance sheets, statements of operations, and statements of cash flows.

F-9

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Segment Reporting

The Partnership operates in a single operating and reportable segment. Operating segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assess performance. The Partnership’s chief executive officer has been determined to be the chief operating decision maker and allocates resources and assesses performance based upon financial information at the consolidated level.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, as well as reported amounts of revenues and expenses for the periods herein. Actual results could differ from those estimates.

The Partnership’s consolidated financial statements are based on a number of significant estimates including oil and natural gas reserve quantities that are the basis for the calculations of depreciation, depletion, and amortization (“DD&A”) and impairment of oil and natural gas properties. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. The accuracy of any reserve estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may differ from the quantities of oil and natural gas that are ultimately recovered. The Partnership’s reserve estimates are determined by an independent petroleum engineering firm. Other items subject to significant estimates and assumptions include the carrying amount of oil and natural gas properties, valuation of commodity derivative financial instruments, valuation of future asset retirement obligations (“ARO”), determination of revenue accruals, and the determination of the fair value of equity-based awards.

The Partnership evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. The volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions. A significant decline in oil or natural gas prices could result in a reduction in the Partnership’s fair value estimates and cause the Partnership to perform analyses to determine if its oil and natural gas properties are impaired. As future commodity prices cannot be predicted accurately, actual results could differ 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 be cash equivalents.

Accounts Receivable

The Partnership’s accounts receivable balance results primarily from operators’ sales of oil and natural gas to their customers. Accounts receivable are recorded at the contractual amounts and do not bear interest. Any concentration of customers may impact the Partnership’s overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions impacting the oil and natural gas industry.

Commodity Derivative Financial Instruments

The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To mitigate the given price risk associated with its operations, the Partnership uses commodity derivative financial instruments. From time to time, such instruments may include variable–to-fixed-price swaps, costless collars, fixed-price contracts, and other contractual arrangements. The Partnership does not enter into derivative instruments for speculative purposes.

F-10

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 sheets. The Partnership does not specifically designate derivative instruments as cash flow hedges, even though they reduce its exposure to changes in oil and natural gas prices; therefore, gains and losses arising from changes in the fair value of derivative instruments are recognized on a net basis in the accompanying consolidated statements of operations within gain (loss) on commodity derivative instruments.

Concentration of Credit Risk

Financial instruments that potentially subject the Partnership to credit risk consist principally of cash and cash equivalents, accounts receivable, and commodity derivative financial instruments.

The Partnership maintains cash and cash equivalent balances with major financial institutions. At times, those balances exceed federally insured limits; however, no losses have been incurred.

The Partnership’s customer base is made up of its lessees, which consist of integrated oil and gas companies to independent producers and operators. The Partnership’s credit risk may also include the purchasers of oil and natural gas produced from the Partnership’s properties. The Partnership attempts to limit the amount of credit exposure to any one company through procedures that include credit approvals, credit limits and terms, and prepayments. The Partnership believes the credit quality of its customer base is high and has not experienced significant write-offs in its accounts receivable balances. See Note 7 – Significant Customers for further discussion.

Commodity derivative financial instruments may expose the Partnership to credit risk; however, the Partnership monitors the creditworthiness of its counterparties. See Note 5 – Commodity Derivative Financial Instruments for further discussion.

Oil and Natural Gas Properties

The Partnership follows the successful efforts method of accounting for oil and natural gas operations. Under this method, costs to acquire mineral and royalty interests and working interests in oil and natural gas properties, property acquisitions, successful exploratory wells, development costs, and support equipment and facilities are capitalized when incurred. Acquisitions of proved oil and natural gas properties and working interests are considered business combinations and are recorded at their estimated fair value as of the acquisition date. Acquisitions of unproved oil and natural gas properties are considered asset acquisitions and are recorded at cost.

Oil and natural gas properties are grouped in accordance with the Extractive Industries – Oil and Gas Topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC). The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field, which we may also refer to as a depletable unit.

As exploration and development work progresses and the reserves associated with the Partnership’s oil and natural gas properties become proved, capitalized costs attributed to the properties are charged as an operating expense through DD&A. DD&A of producing oil and natural gas properties is recorded based on the units-of-production method. Capitalized development costs are amortized on the basis of proved developed reserves while leasehold acquisition costs and the costs to acquire proved properties are amortized on the basis of all proved reserves, both developed and undeveloped. Proved reserves are quantities of oil and natural gas that can be estimated 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 $114.3 million, $102.4 million and $102.7 million for the years ended December 31, 2017, 2016, and 2015, respectively.

F-11

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Partnership evaluates impairment of producing properties whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. This evaluation is performed on a depletable unit basis. The Partnership compares the undiscounted projected future cash flows expected in connection with a depletable unit to its unamortized carrying amount to determine recoverability. When the carrying amount of a depletable unit exceeds its estimated undiscounted 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 flows of such properties. The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, future capital expenditures, and a risk-adjusted discount rate.

Other Property and Equipment

Other property and equipment includes furniture, fixtures, office equipment, leasehold improvements, and computer software and is stated at historical cost. Depreciation and amortization are calculated using the straight-line method over expected useful lives ranging from three to seven years. Depreciation and amortization expense totaled $0.2 million, $0.1 million, and $1.6 million for the years ended December 31, 2017, 2016, and 2015, respectively.

Repairs and Maintenance

The cost of normal maintenance and repairs is charged to expense as incurred. Material expenditures that increase the life of an asset are capitalized and depreciated over the shorter of the estimated remaining useful life of the asset or the term of the lease, if applicable.

Accrued Liabilities

Accrued liabilities consisted of the following as of December 31, 2017 and 2016:



	As of December 31,
	2017		2016
Accrued liabilities:	(in thousands)
Accrued capital expenditures	$	28,711	$	17,775
Accrued incentive compensation	16,503		20,898
Accrued property taxes	4,090		3,175
Accrued other	3,327		9,104
Total accrued liabilities	$	52,631	$	50,952

F-12

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Debt Issuance Costs

Debt issuance costs consist of costs directly associated with obtaining credit with financial institutions. These costs are capitalized and are amortized on a straight-line basis over the life of the credit agreement, which approximates the effective-interest method. Any unamortized debt issuance costs are expensed in the year when the associated debt instrument is terminated. Amortization expense for debt issuance costs was $0.9 million, $0.9 million, and $0.9 million for the years ended December 31, 2017, 2016, and 2015, respectively, and is included in interest expense in the consolidated statements of operations.

Asset Retirement Obligations

Fair values of legal obligations to retire and remove long-lived assets are recorded when the obligation is incurred and becomes determinable. When the liability is initially recorded, the Partnership capitalizes this cost by increasing the carrying amount of the related property. Over time, the liability is accreted 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 with the related asset.

Revenue Recognition

The Partnership recognizes revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller’s price to the buyer is fixed 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 of natural gas sold may differ from the volumes to which the Partnership is entitled based on its interests in the properties. These differences create imbalances that are recognized as a liability only when the properties’ estimated remaining reserves, net to the Partnership, will not be sufficient to enable the under-produced owner to recoup its entitled share through production; however, such amounts are de minimis at December 31, 2017 and 2016.

Other sources of revenue received by the Partnership include mineral lease bonuses and delay rentals. The Partnership generates lease bonus revenue by leasing its mineral interests to exploration and production companies. The lease agreements generally transfer the rights to any oil or natural gas discovered, grant the Partnership a right to a specified royalty interest, and require that drilling and completion operations commence within a specified time period. 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 not started 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 responsible for 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.

F-13

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Limited partnerships that receive at least 90% of their gross income from designated passive sources, including royalties from mineral properties and other non-operated mineral interest income, and do not receive more than 10% of their income from operating an active trade or business, are classified as “passive entities” and are generally exempt from the Texas margin tax. The Partnership believes that it meets the requirements for being considered a “passive entity” for Texas margin tax purposes. As a result, each unitholder that is considered a taxable entity under the Texas margin tax would generally 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 of Texas.

Fair Value of Financial Instruments

The carrying values of the Partnership’s current financial instruments, which include cash and cash equivalents, accounts receivable, commodity derivative financial instruments, and accounts payable, approximate their fair value at December 31, 2017 and 2016 due to the short-term maturity of these instruments. See Note 6 – Fair Value Measurements for further discussion.

Incentive Compensation

Incentive compensation includes both liability awards and equity-based awards. The Partnership recognizes compensation expense associated with its incentive compensation awards using either straight-line or accelerated 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 date fair values. Liability awards are awards that are expected to be settled in cash or an unknown number of common or subordinated units on their vesting dates. Liability awards are recorded as accrued liabilities based on the vested portion of the estimated fair value of the awards as of the grant date, which is subject to revision based on the impact of certain performance conditions associated with the incentive plans.

Incentive compensation expense is charged to general and administrative expense on the consolidated statements of operations. See Note 9 – Incentive Compensation for additional discussion.

Recent Accounting Pronouncements

In May 2014, the FASB issued Accounting Standards Update ("ASU") 2014-09, Revenue from Contracts with Customers (Topic 606) that will supersede ASC 605, Revenue Recognition. Under the new standard, entities will be required to use judgment and make estimates, including identifying performance obligations in a contract, estimating the amount of variable consideration to include in the transaction price, allocating the transaction price to each separate performance obligation, and determining when an entity satisfies its performance obligations. The new standard also requires more detailed disclosures related to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The new guidance is effective for fiscal years and interim periods beginning after December 15, 2017. The standard allows for either “full retrospective” adoption, meaning that the standard is applied to all of the periods presented with a cumulative catch-up adjustment as of the earliest period presented, or “modified retrospective” adoption, meaning the standard is applied only to the most current period presented in the financial statements with a cumulative catch-up as of the current period.

The Partnership has completed its review of a representative sample of revenue contracts covering its material revenue streams that was designed to evaluate any potential changes in revenue recognition upon adoption of the new standard, and based on evaluations to-date, the implementation of the new standard will not have a material impact on the consolidated financial statements and disclosures. The Partnership has also completed its review of the information technology and internal control changes that will be required to implement the new standard based on the results of its contract review process. The Partnership intends to use the modified retrospective approach upon adoption of the new guidance on the effective date of January 1, 2018, and does not anticipate recording or disclosing any material transition adjustments upon adoption.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires lessees to recognize the lease assets and lease liabilities classified as operating leases on the balance sheet. The new standard will be effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, and early adoption is permitted. The Partnership will use the modified retrospective adoption approach and does not plan to early adopt. Based on current evaluations to-date, the new guidance will not have a material impact on the Partnership's consolidated financial statements and related disclosures as this guidance does not apply to leases to explore for or use minerals, oil, natural gas, and similar resources.

F-14

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments (Topic 230), to address diversity in practice of how certain cash receipts and cash payments are currently presented and classified in the statement of cash flows. The ASU addresses the topic of separately identifiable cash flows and application of the predominance principle. Classification of cash receipts and payments that have aspects of more than one class of cash flows should be determined first by applying specific guidance, and then by the nature of each separately identifiable cash flow. In situations where there is an absence of specific guidance and the cash flow has aspects of more than one type of classification, the predominance principle should be applied whereby the cash flow classification should depend on the activity that is likely to be the predominant source or use of cash flows. The new guidance is effective for public business entities for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. The Partnership intends to use the retrospective transition method upon adoption of the new guidance on the effective date of January 1, 2018 and based on current evaluations to-date, adoption will not have a material impact to the consolidated financial statements and related disclosures.

In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805), which clarifies the definition of a business in order to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The FASB issued this ASU in response to stakeholder feedback that the current definition of a business in ASC 805 is being applied too broadly and the application of the guidance was not resulting in consistent application in a cost-effective manner. This ASU provides a screen whereby a transaction will be accounted for as an asset purchase (or disposal) if substantially all of the fair value of the gross assets acquired (disposed) is concentrated in a single identifiable asset or a group of similar identifiable assets. If the screen is not met, the entity will evaluate whether it is a business acquisition under revised criteria. The ASU is effective for public business entities for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. The Partnership will adopt the new guidance prospectively as of the effective date of January 1, 2018, and based on current evaluations to-date, adoption will not have a material impact to the consolidated financial statements and related disclosures.

In May 2017, the FASB issued ASU 2017-09, Compensation-Stock Compensation: Scope of Modification Accounting (Topic 718). The update provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting under Topic 718. The amendments require an entity to account for the effects of a modification unless all of the following conditions are met:


•	The fair value (or intrinsic or calculated value if elected) of the modified award is the same as the value of the original award immediately before the original award was modified.


•	The vesting conditions of the modified award are the same as the vesting conditions of the original award immediately before the original award is modified.


•	The classification of the modified award as an equity instrument or a liability instrument is the same as the classification of the original award immediately before the original award is modified.

This ASU is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. The Partnership will adopt the new guidance prospectively to all awards modified on or after the effective date of January 1, 2018, and based on current evaluations to-date, adoption will not have a material impact to the consolidated financial statements and related disclosures.

NOTE 3 — ASSET RETIREMENT OBLIGATIONS

The ARO liability reflects the present value of estimated costs of dismantlement, removal, site reclamation, and similar activities associated with the Partnership’s working-interest 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 credit-adjusted risk-free rate, and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and natural gas property balance.

F-15

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table describes changes to the Partnership’s ARO liability for the periods presented:



	For the year ended December 31,
	2017			2016
	(in thousands)
Beginning asset retirement obligations	$	13,350		$	10,585
Liabilities incurred	308			2,009
Liabilities settled	(228		)	(317		)
Accretion expense	1,026			892
Revisions in estimated costs	83			181
Dispositions	(30		)	—
Ending asset retirement obligations	$	14,509		$	13,350
Current asset retirement obligations	$	417		$	—
Non-current asset retirement obligations	$	14,092		$	13,350

NOTE 4 — OIL AND NATURAL GAS PROPERTIES ACQUISITIONS

Noble Acquisition

On November 28, 2017, BSMC closed on the acquisition of (i) certain mineral interests and other non-cost bearing royalty interests from Noble Energy Inc., Noble Energy Wyco, LLC, and Rosetta Resources Operating LP and (ii) one hundred percent (100%) of the issued and outstanding securities of Samedan Royalty, LLC ("Samedan") from Noble Energy US Holdings, LLC, collectively, the "Noble Acquisition."

The mineral interests and other non-cost bearing royalty interests acquired in the Noble Acquisition, including interests owned by Samedan (the "Noble Assets") include approximately 1.1 million gross (140,000 net) mineral acres, 380,000 gross acres of non-participating royalty interests, and 600,000 gross acres of overriding royalty interests collectively spread over 20 states with significant concentrations in Texas, Oklahoma, and North Dakota.

The Partnership funded the $335 million purchase price (before customary post-closing adjustments) using (i) approximately $300 million in proceeds from its issuance of 14,711,219 Series B cumulative convertible preferred units to Mineral Royalties One, L.L.C., an affiliate of The Carlyle Group ("the Purchaser"), in a private placement which also closed on November 28, 2017, and (ii) approximately $35 million from borrowings under its Credit Facility. See additional discussion of the Series B cumulative convertible preferred units in Note 12 – Preferred Units.

The transaction was accounted for as a business combination using the acquisition method of accounting which requires, among other things, that the assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date. The final determination of fair value remains preliminary and will be completed after post-closing purchase price adjustments are finalized, but in no case later than one year from the acquisition date.

The following table summarizes the preliminary estimate and allocation of the fair value of the assets acquired and the acquisition-related costs.



	Assets Acquired								Cash Consideration Paid		Acquisition-Related Costs¹
	Proved		Unproved		Net Working Capital		Total Fair Value		Cash Consideration Paid		Acquisition-Related Costs¹
	(in thousands)
Noble Assets	$	68,877	$	259,749	$	5,917	$	334,543	$	334,543	$	247


¹	Acquisition-related costs were expensed and included in the general and administrative expense line item of the consolidated statement of operations for the year ended December 31, 2017.

F-16

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The fair value of the Noble Assets was measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of: (i) oil and natural gas reserves; (ii) future commodity prices; (iii) estimated future cash flows; and (iv) market-based weighted average cost of capital. These inputs require significant judgments and estimates by the Partnership's management at the time of the valuation and are the most sensitive and subject to change.

Actual and Pro Forma Impact of Noble Acquisition (Unaudited)

Revenue attributable to the Noble Acquisition included in the Partnership's consolidated statement of operations for the year ended December 31, 2017 was $2.8 million. The following table presents unaudited pro forma information for the Partnership as if the Noble Acquisition occurred on January 1, 2016.



	For the Year Ended December 31,
	2017			2016
	(in thousands, except per unit amounts)
Revenue and other income	$	468,103		$	288,772
Net income (loss)	$	178,970		$	33,264
Net income (loss) attributable to noncontrolling interests	34			12
Distributions on Series A redeemable preferred units	(3,117		)	(5,763		)
Distributions on Series B cumulative convertible preferred units	(21,000		)	(21,000		)
Net income (loss) attributable to the general partner and common and subordinated units	$	154,887		$	6,513
Allocation of net income (loss):
General partner interest	—			—
Common units	99,776			20,696
Subordinated units	55,111			(14,183		)
	$	154,887		$	6,513
Net income (loss) attributable to limited partners per common and subordinated unit:
Per common unit (basic)	$	1.02		$	0.22
Per subordinated unit (basic)	$	0.58		$	(0.15	)
Per common unit (diluted)	$	1.02		$	0.22
Per subordinated unit (diluted)	$	0.58		$	(0.15	)

The historical financial information was adjusted to give effect to the pro forma events that were directly attributable to the Noble Acquisition and are factually supportable. The unaudited pro forma consolidated results are not necessarily indicative of what the Partnership's consolidated results of operations would have been had the acquisition been completed on January 1, 2016. In addition, the unaudited pro forma consolidated results do not purport to project the future results of operations for the combined company. The unaudited pro forma consolidated results reflect the following pro forma adjustments:


•	Adjustments to recognize incremental revenue, production costs and ad valorem taxes, and DD&A expense attributable to the Noble Assets.


•	Adjustment to recognize additional interest expense associated with the incremental borrowings under the Partnership's Credit Facility.


•	Adjustment to recognize the quarterly distribution associated with the issuance of 14,711,219 Series B cumulative convertible preferred units.


•	The Series B cumulative convertible preferred units were excluded from the calculation of pro forma diluted earnings per common unit for the periods presented above due to their antidilutive effect under the if-converted method; the Series B cumulative convertible preferred units do not have any impact to earnings per subordinated unit.

F-17

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2017 Acquisitions

In addition to the Noble Acquisition, the Partnership closed on multiple acquisitions of mineral and royalty interests, which also included producing properties, during the year ended December 31, 2017, as reflected in the table below. These acquisitions were primarily focused in the Delaware Basin and East Texas. The cash portion of all acquisitions below was funded via borrowings under the Partnership's Credit Facility.



	Assets Acquired								Consideration Paid
	Proved		Unproved		Net Working Capital		Total Fair Value		Cash		Fair Value of Common Units Issued		Acquisition-Related Costs¹
	(in thousands)
January	$	5,135	$	34,008	$	263	$	39,406	$	27,380	$	12,026	$	1,162
June	5,006		45,477		—		50,483		4,802		45,681		1,481
August	3,277		9,984		—		13,261		4,289		8,972		107
September	3,120		—		—		3,120		3,120		—		—
Total fair value	$	16,538	$	89,469	$	263	$	106,270	$	39,591	$	66,679	$	2,750


¹	Acquisition-related costs were expensed and included in the general and administrative expense line item of the 2017 consolidated statement of operations.

In addition, the Partnership acquired mineral and royalty interests from various sellers in East Texas as reflected in the table below. The cash portion of all acquisitions below was funded via borrowings under the Partnership's Credit Facility.



	Assets Acquired		Consideration Paid
	Unproved		Cash		Fair Value of Common Units Issued
	(in thousands)
Q1 2017	$	21,189	$	21,017	$	172
Q2 2017	13,329		13,329		—
Q3 2017	19,946		15,205		4,741
Q4 2017	2,267		2,137		130
Total acquired	$	56,731	$	51,688	$	5,043

Farmout Agreements

On February 21, 2017, the Partnership announced that it had entered into a farmout agreement with Canaan Resource Partners ("Canaan") which covers certain Haynesville and Bossier shale acreage in San Augustine County, Texas operated by XTO Energy Inc. The Partnership has an approximate 50% working interest in the acreage and is the largest mineral owner. A total of 18 wells are anticipated to be drilled over an initial phase, beginning with wells spud after January 1, 2017. As of December 31, 2017, 10 wells had been drilled during the initial phase. At its option, Canaan may participate in two additional phases with each phase continuing for the lesser of 2 years or until 20 wells have been drilled. During the first three phases of the agreement, Canaan will commit on a phase-by-phase basis and fund 80% of the Partnership's drilling and completion costs and will be assigned 80% of the Partnership's working interests in such wells (40% working interest on an 8/8ths basis). After the third phase, Canaan can earn 40% of the Partnership’s working interest (20% working interest on an 8/8ths basis) in additional wells drilled in the area by continuing to fund 40% of the Partnership's costs for those wells on a well-by-well basis. The Partnership will receive an overriding royalty interest (“ORRI”) before payout and an increased ORRI after payout on all wells drilled under the agreement. For the year ended December 31, 2017, the Partnership received $13.6 million from Canaan under the agreement. All amounts received in 2017 are included in the Other long-term liabilities line of our December 31, 2017 consolidated balance sheet, as none of the drilled wells had been completed nor had any working interest been assigned to Canaan as of the balance sheet date.

F-18

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On November 21, 2017, we entered into a farmout agreement with a portfolio company of Tailwater Capital, LLC, Pivotal Petroleum Partners (“Pivotal”), that covers substantially all of the Partnership's remaining working interests under active development in the Shelby Trough area of East Texas targeting the Haynesville and Bossier shale acreage after giving effect to the Canaan Farmout (discussed above) over the next eight years. In wells operated by XTO Energy Inc. in San Augustine County, Texas, Pivotal will earn the Partnership's remaining approximate 20% working interest (10% working interest on an 8/8th basis) not covered by the Canaan Farmout, as well as 100% of the Partnership's working interests (ranging from approximately 12.5% to 25% on an 8/8ths basis) in wells operated by its other major operator in the area. Initially, Pivotal will be obligated to fund the development of up to 80 wells across several development areas and then will have options to continue funding the Partnership's working interest across those areas for the duration of the eight year term. After the funding of a designated group of wells by Pivotal and once Pivotal achieves a specified payout for such well group, the Partnership will obtain a majority of the original working interest in the designated group of wells. For the year ended December 31, 2017, the Partnership received $5.6 million from Pivotal under the agreement. All amounts received in 2017 are included in the Other long-term liabilities line of our December 31, 2017 consolidated balance sheet, as none of the drilled wells had been completed nor had any working interest been assigned to Pivotal as of the balance sheet date.

2016 Acquisitions

During the year ended December 31, 2016, the Partnership acquired producing oil and natural gas properties and unproved acreage in a diverse oil and natural gas mineral asset package, and also completed an acquisition in June 2016 in the DJ Basin. The following table summarizes the fair value assigned to the properties acquired:



	Assets Acquired											Cash Consideration Paid
	Proved		Unproved		Net Working Capital		ARO			Total Fair Value		Cash Consideration Paid
	(in thousands)
June 2016	$	39,735	$	79,827	$	2,064	$	(50	)	$	121,576	$	121,576

The Partnership also acquired unproved mineral and royalty interests in the Permian Basin and Midland Basin for $10 million and $8.3 million in cash, respectively. Additionally, throughout 2016, the Partnership funded certain other oil and natural gas asset acquisitions for an aggregate amount of $1.2 million in cash. All 2016 acquisition transactions were funded via borrowings under the Partnership's Credit Facility.

2015 Acquisitions

During the year ended December 31, 2015, the Partnership acquired mineral and royalty interests in the Permian Basin for $51.7 million, mineral and royalty interests and non-operated working interests in the Eagle Ford Shale resource play for $9.7 million, and overriding royalty interests in the Utica Shale and Marcellus Shale resource plays for $1.8 million. All 2015 acquisition transactions were funded via borrowings under the Partnership's Credit Facility.

NOTE 5 — COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS

The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To mitigate the inherent commodity price risk associated with its operations, the Partnership uses oil and natural gas commodity derivative financial instruments. From time to time, such instruments may include variable–to-fixed-price swaps, costless collars, fixed-price contracts, and other contractual arrangements. The Partnership enters into oil and natural gas derivative contracts that contain netting arrangements with each counterparty. The Partnership does not enter into derivative instruments for speculative purposes.

As of December 31, 2017, the Partnership's open derivatives contracts consisted of only fixed-price-swap contracts. A fixed-price-swap contract between the Partnership and the counterparty specifies a fixed commodity price and a future settlement date. The Partnership has not designated any of its contracts as fair value or cash flow hedges. Accordingly, the changes in fair value of the contracts are included in the consolidated statement of operations in the period of the change. All derivative gains and losses from the Partnership's derivative contracts have been recognized in revenue in the Partnership's accompanying consolidated statements of operations. Derivative instruments that have not yet been settled in cash are reflected as either derivative assets or liabilities in the Partnership’s accompanying consolidated balance sheets as of December 31, 2017 and 2016. See Note 6 – Fair Value Measurements for further discussion.

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BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Partnership's derivative contracts expose it to credit risk in the event of nonperformance by counterparties. While the Partnership does not require its derivative contract counterparties to post collateral, the Partnership does evaluate the credit standing of such counterparties as deemed appropriate. This evaluation includes reviewing a counterparty’s credit rating and latest financial information. As of December 31, 2017, the Partnership had nine counterparties, all of which are rated Baa1 or better by Moody’s. Seven of the Partnership's counterparties are lenders under the Partnership's Credit Facility. The Partnership would have been at risk of losing a fair value amount of $12.1 million had the Partnership's counterparties as a group been unable to fulfill their obligations as of December 31, 2017.

The tables below summarize the fair value and classification of the Partnership’s derivative instruments, as well as the gross recognized derivative assets, liabilities and amounts offset in the consolidated balance sheets at December 31, 2017 and 2016:



		As of December 31, 2017
Classification	Balance Sheet Location	Gross Fair Value		Effect of Counterparty Netting			Net Carrying Value on Balance Sheet
		(in thousands)
Assets:
Current asset	Commodity derivative assets	$	10,713	$	(10,619	)	$	94
Long-term asset	Deferred charges and other long-term assets	1,392		(1,029		)	363
Total assets		$	12,105	$	(11,648	)	$	457
Liabilities:
Current liability	Commodity derivative liabilities	$	14,841	$	(10,619	)	$	4,222
Long-term liability	Commodity derivative liabilities	2,292		(1,029		)	1,263
Total liabilities		$	17,133	$	(11,648	)	$	5,485



		As of December 31, 2016
Classification	Balance Sheet Location	Gross Fair Value		Effect of Counterparty Netting			Net Carrying Value on Balance Sheet
		(in thousands)
Assets:
Current asset	Commodity derivative assets	$	3,879	$	(3,879	)	$	—
Long-term asset	Deferred charges and other long-term assets	—		—			—
Total assets		$	3,879	$	(3,879	)	$	—
Liabilities:
Current liability	Commodity derivative liabilities	$	20,116	$	(3,879	)	$	16,237
Long-term liability	Commodity derivative liabilities	482		—			482
Total liabilities		$	20,598	$	(3,879	)	$	16,719

Changes in the fair values of the Partnership’s derivative instruments (both assets and liabilities) are presented on a net basis in the accompanying consolidated statements of operations and consisted of the following for the periods presented:



	For the year ended December 31,
Derivatives not designated as hedging instruments	2017			2016			2015
	(in thousands)
Beginning fair value of commodity derivative instruments	$	(16,719	)	$	64,534		$	37,471
Gain (loss) on oil derivative instruments	(5,091		)	(15,998		)	57,681
Gain (loss) on natural gas derivative instruments	31,993			(20,466		)	32,607
Net cash received on settlements of oil derivative instruments	(10,901		)	(27,450		)	(41,786		)
Net cash received on settlements of natural gas derivative instruments	(4,310		)	(17,339		)	(21,439		)
Net change in fair value of commodity derivative instruments	11,691			(81,253		)	27,063
Ending fair value of commodity derivative instruments	$	(5,028	)	$	(16,719	)	$	64,534

F-20

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Partnership had the following open derivative contracts for oil as of December 31, 2017:



	Volume (Bbl)	Weighted Average Price (per Bbl)		Range (per Bbl)
Period and Type of Contract	Volume (Bbl)	Weighted Average Price (per Bbl)		Low		High
Oil Swap Contracts:
2018
First quarter	729,000	$	54.36	$	52.09	$	57.15
Second quarter	736,000	54.33		52.09		56.75
Third quarter	744,000	54.35		51.85		55.87
Fourth quarter	749,000	54.24		51.85		55.87
2019
First quarter	165,000	$	53.58	$	52.82	$	54.02
Second quarter	165,000	53.58		52.82		54.02
Third quarter	165,000	53.58		52.82		54.02
Fourth quarter	165,000	53.58		52.82		54.02

The Partnership had the following open derivative contracts for natural gas as of December 31, 2017:



	Volume (MMBtu)	Weighted Average Price (per MMBtu)		Range (per MMBtu)
Period and Type of Contract	Volume (MMBtu)	Weighted Average Price (per MMBtu)		Low		High
Natural Gas Swap Contracts:
2018
First quarter	13,590,000	$	3.06	$	2.96	$	3.45
Second quarter	13,660,000	3.02		2.86		3.23
Third quarter	13,600,000	3.01		2.90		3.23
Fourth quarter	13,630,000	3.01		2.90		3.23
2019
First quarter	3,600,000	2.91		2.90		2.93
Second quarter	3,600,000	2.91		2.90		2.93
Third quarter	3,600,000	2.91		2.90		2.93
Fourth quarter	3,600,000	2.91		2.90		2.93

Subsequent to December 31, 2017, the Partnership entered into oil derivative contracts for 35,000 barrels per month beginning February 2018 through December 2018 and 60,000 barrels per month in 2019 at weighted average prices of $61.85 and $57.58, respectively.

NOTE 6 — FAIR VALUE MEASUREMENTS

Fair 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 between market participants at the measurement date. Further, ASC 820, Fair Value Measurement, establishes a framework for measuring fair value, establishes a fair value hierarchy based on the 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 and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are 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 or indirectly, for substantially the full term of the financial instrument.

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BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Level 3 — Inputs that are unobservable and significant to the fair value measurement (including the Partnership’s own assumptions in determining fair value).

A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers 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 ended December 31, 2017 and 2016.

The carrying value of our cash and cash equivalents, receivables and payables approximate fair value due to the short-term nature of the instruments. The estimated carrying value of all debt as of December 31, 2017 and 2016 approximated the fair value due to variable market rates of interest. These debt fair values, which are Level 3 measurements, were estimated based on the Partnership’s incremental borrowing rates for similar types of borrowing arrangements, when quoted market prices were not available. The estimated fair values of the Partnership’s financial instruments are not necessarily indicative of the amounts that would be realized in a current market exchange.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The Partnership estimated the fair value of commodity derivative financial instruments using the market approach via a model that uses inputs that are observable in the market or can be derived from, or corroborated by, observable data. See Note 5 – Commodity Derivative 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 of Counterparty
	Level 1		Level 2		Level 3		Netting			Total
	(In thousands)
As of December 31, 2017
Financial Assets
Commodity derivative instruments	$	—	$	12,105	$	—	$	(11,648	)	$	457
Financial Liabilities
Commodity derivative instruments	—		17,133		—		(11,648		)	5,485
As of December 31, 2016
Financial Assets
Commodity derivative instruments	$	—	$	3,879	$	—	$	(3,879	)	$	—
Financial Liabilities
Commodity derivative instruments	—		20,598		—		(3,879		)	16,719

Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis

Nonfinancial assets and liabilities measured at fair value on a non-recurring basis include certain nonfinancial assets and liabilities as may be acquired in a business combination and measurements of oil and natural gas property values for assessment of impairment.

The determination of the fair values of proved and unproved properties acquired in business combinations are prepared by estimating discounted cash flow projections. The factors used to determine fair value include estimates of economic reserves, future operating and development costs, future commodity prices, and a risk-adjusted discount rate. The Partnership has designated these measurements as Level 3. The Partnership's fair value assessments for recent acquisitions are included in Note 4 — Oil and Natural Gas Properties Acquisitions.

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BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Oil and natural gas properties are measured at fair value on a nonrecurring basis using the income approach when assessing for impairment. Proved and unproved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of those properties. When assessing producing properties for impairment, the Partnership compares the expected undiscounted projected future cash flows of the producing properties to the carrying amount of the producing properties to determine recoverability. When the carrying amount exceeds its estimated undiscounted 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 flows of such properties. The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, future capital expenditures, and a risk-adjusted discount rate.

The Partnership’s estimates of fair value have been determined at discrete points in time based on relevant market data. These estimates involve uncertainty and cannot be determined with precision. There were no significant changes in valuation techniques or related inputs for the years ended December 31, 2017 and 2016.

The following table presents information about the Partnership’s assets measured at fair value on a non-recurring basis:



	Fair Value Measurements Using						Net Book
	Level 1		Level 2		Level 3¹		Value¹		Impairment
	(In thousands)
Year Ended December 31, 2017
Impaired oil and natural gas properties	$	—	$	—	$	—	$	—	$	—
Year Ended December 31, 2016
Impaired oil and natural gas properties	$	—	$	—	$	3,042	$	9,817	$	6,775
Year Ended December 31, 2015
Impaired oil and natural gas properties	$	—	$	—	$	156,689	$	406,258	$	249,569

¹Amounts represent fair value and net book value at the date of assessment.

NOTE 7 — SIGNIFICANT CUSTOMERS

The Partnership leases mineral interests to exploration and production companies and participates in non-operated working interests when economic conditions are favorable. XTO Energy Inc., a subsidiary of Exxon Mobil Corporation ("Exxon"), represented approximately 21% of total revenue for the year ended December 31, 2017. Exxon represented approximately 11% of total revenue for the year ended December 31, 2016. No customer represented 10% or more of total revenue for the year ended December 31, 2015.

If the Partnership lost a significant customer, such loss could impact revenue derived from its mineral and royalty interests and working interests. The loss of any single customer is mitigated by the Partnership’s diversified customer base.

NOTE 8 — CREDIT FACILITY

The Partnership maintains a secured revolving credit agreement, as amended, (the “Credit Facility”). The Credit Facility has a maximum credit amount of $1.0 billion. The amount of the borrowing base is derived from the value of the Partnership’s oil and natural gas properties determined by the lender syndicate using pricing assumptions that often differ from the current market for future prices.

Drawings on the Credit Facility are used for the acquisition of oil and natural gas properties and for other general business purposes. Effective April 15, 2016, the borrowing base was $450.0 million. The Partnership's fall 2016 borrowing base redetermination process resulted in an increase in the borrowing base to $500.0 million, which became effective October 31, 2016. Effective April 25, 2017, the borrowing base redetermination resulted in an increase to $550.0 million. On November 1, 2017, the Partnership amended and restated the credit agreement to extend the maturity thereof for a term of five years, create a swingline facility that permits short-term borrowings on same-day notice, and make other changes to the hedging and restrictive covenants. There was no change to the borrowing base. The Credit Facility now terminates on November 1, 2022.

Prior to October 31, 2016, borrowings under the Credit Facility bore interest at LIBOR plus a margin between 1.50% and 2.50%, or Prime Rate plus a margin between 0.50% and 1.50%, with the margin depending on the borrowing base utilization percentage of the loan. The Prime Rate was determined to be the higher of the financial institution’s prime rate or the federal funds effective rate plus 0.50% per annum.

F-23

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Effective October 31, 2016, borrowings under the Credit Facility bore interest at LIBOR plus a margin between 2.00% and 3.00%, or the Prime Rate plus a margin between 1.00% and 2.00%, with the margin depending on the borrowing base utilization of the loan.

The weighted-average interest rate of the Credit Facility was 4.06% and 3.26% as of December 31, 2017 and 2016, respectively. Accrued interest 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 case interest 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 of 0.375% 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 greater than 50%. The Credit Facility is secured by substantially all of the Partnership’s oil and natural gas production and assets.

The Credit Facility contains various limitations on future borrowings, leases, hedging, and sales of assets. Additionally, the Credit Facility requires 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, 2017, the Partnership was in compliance with all financial covenants in the Credit Facility.

The aggregate principal balance outstanding was $388.0 million and $316.0 million at December 31, 2017 and 2016, respectively. The unused portion of the available borrowings under the Credit Facility were $162.0 million and $184.0 million at December 31, 2017 and 2016, respectively.

NOTE 9 — INCENTIVE COMPENSATION

Overview

The Board of the Partnership’s general partner established a long-term incentive plan (the “2015 LTIP”), pursuant to which non-employee directors of the Partnership’s general partner and certain employees and consultants of the Partnership and its affiliates are eligible to receive awards with respect to the Partnership’s common and subordinated units. The 2015 LTIP permits the grant of unit options, unit appreciation rights, restricted units, unit awards, phantom units, distribution equivalent rights either in tandem with an award or as a separate award, cash awards, and other unit-based awards. Any vesting terms associated with incentive awards are based on a predetermined schedule as approved by the Board or a committee thereof.

Incentive compensation expense is included in general and administrative expense on the consolidated statements of operations. The total compensation expense related to the common and subordinated unit grants is measured as the number of units granted that are expected to vest multiplied by the grant-date fair value per unit. Incentive compensation expense is recognized using straight-line or accelerated attribution depending on the specific terms of the award agreements over the requisite service periods (generally equivalent to the vesting period).

Cash Awards

The Partnership may also provide from time to time short-term and long-term cash incentive and retention awards annually for its directors, executive officers and certain other employees. Certain employees are entitled to receive cash bonuses based on service criteria over a four-year requisite service period ending in 2019. Payments are disbursed as vesting is attained on a graded annual basis. The last grant of such cash awards with graded vesting requirements was made in 2016 and extends through December 31, 2019.

Restricted Unit Awards

Restricted common units in the Predecessor outstanding as of the date of the IPO were converted into restricted common and subordinated units of the Partnership in connection with the IPO. The converted restricted units awarded are subject to restrictions on transferability, customary forfeiture provisions, and time vesting provisions. Award recipients have all the rights of a unitholder in the Partnership with respect to the converted restricted units, including the right to receive distributions thereon, if and when made by the Partnership. Non-employee directors of the Partnership’s general partner receive compensation under the 2015 LTIP in the form of fully vested common units granted after each year of service.

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BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In conjunction with the adoption of the 2015 LTIP, the Board approved a grant of awards to each of the executive officers of the Partnership's general partner, certain other employees, and each of the non-employee directors of the Partnership’s general partner. The grants included restricted common units subject to limitations on transferability, customary forfeiture provisions, and service based graded vesting requirements through March 15, 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 their restricted common units. The grant-date fair value of these awards, net of estimated forfeitures, is recognized ratably using the straight-line attribution method.

The Compensation Committee of the Board (the "Compensation Committee") approved a grant of awards to each of the executive officers of the Partnership's general partner and certain other employees. The grant includes restricted common units subject to limitations on transferability, customary forfeiture provisions, and service-based graded vesting requirements through January 7, 2020. Holders of restricted common unit awards have all of the rights of a common unitholder, including non-forfeitable distribution rights with respect to their restricted common units. The grant-date fair value of these awards, net of estimated forfeitures, is recognized ratably using the straight-line attribution method.

In April 2016, the Compensation Committee approved a resolution to change the form of settlement of certain employee long-term incentive compensation plans from cash to equity. As a result of the modification, $10.1 million of cash-settled liabilities were reclassified to equity-settled liabilities during the second quarter of 2016 and the remaining unamortized expense of the awards will be amortized as equity-settled liabilities.

Additionally, in January of each year, non-employee directors on the Board receive fully vested common units for their service in the previous year.

The following table summarizes information about restricted units for the year ended December 31, 2017.



	Units				Weighted-Average Grant-Date Fair Value per Unit
	Common		Subordinated		Common		Subordinated
Unvested at December 31, 2016	1,271,215		163,041		$	15.29	$	18.97
Granted	901,910		—		18.48		—
Vested	(602,764	)	(103,912	)	15.13		19.35
Converted	—		—		—		—
Forfeited	(28,303	)	—		17.64		—
Unvested at December 31, 2017	1,542,058		59,129		16.72		18.30

The weighted-average grant-date fair value per unit for unit-based awards was $18.48, $10.09, and $18.79 for the years ended December 31, 2017, 2016, and 2015, respectively. Unrecognized compensation cost associated with restricted common and subordinated unit awards was $15.7 million and $0.2 million, respectively, as of December 31, 2017, which the Partnership expects to recognize over a weighted-average period of 1.65 years and 0.2 years for common units and subordinated units, respectively. The fair value of units vested for the years ended December 31, 2017, 2016, and 2015 was $25.1 million, $11.9 million, and $9.4 million, respectively. There were no cash payments made for vested units during the years ended December 31, 2017, 2016 and 2015.

Performance Unit Awards

The Compensation Committee also approved grants of restricted performance units that are subject to both performance-based and service-based vesting provisions. The number of common units issued to a recipient upon vesting of a restricted performance unit will be calculated based on performance against certain metrics that relate to the Partnership’s performance over each of the three calendar year performance periods commencing January 1 of the first calendar period. The target number of common units subject to each restricted performance unit is one; however, based on the achievement of performance criteria, the number of common units that may be received in settlement of each restricted performance unit can range from zero to two times the target number. The restricted performance units are eligible to become earned at the end of the required service period assuming the minimum performance metrics are achieved. Compensation expense related to the restricted performance unit awards is determined by multiplying the number of common units underlying such awards that, based on the Partnership’s estimate, are probable to vest, by the measurement-date (i.e., the last day of each reporting period date) fair value and recognized using the accelerated or straight line attribution methods, depending on the terms of the award. Distribution equivalent rights for the restricted performance unit awards that are expected to vest are charged to partners’ capital.

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BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Compensation Committee also approved dollar-value targets for performance-based short-term incentive compensation for executive officers and certain other employees of the Partnership. The Partnership expects to ultimately settle the authorized awards, at the end of the annual performance period, in common units.

The following table summarizes information about performance units for the year ended December 31, 2017.



Performance units	Number of Units		Weighted-Average Grant-Date Fair Value per Unit
Unvested at December 31, 2016	1,156,419		$	14.94
Granted	438,288		17.99
Vested	—		—
Forfeited	(137,351	)	18.60
Unvested at December 31, 2017	1,457,356		15.51

Unrecognized compensation cost associated with performance unit awards was $10.1 million as of December 31, 2017, which the Partnership expects to recognize over a weighted-average period of 1.54 years.

Incentive Compensation Summary

The table below summarizes incentive compensation expense recorded in general and administrative expenses in the consolidated statements of operations for the years ended December 31, 2017, 2016, and 2015.



	Year Ended December 31,
Incentive compensation expense	2017		2016		2015
	(In thousands)
Cash — long-term incentive plan	$	1,412	$	2,725	$	15,064
Equity-based compensation — restricted common and subordinated units	13,476		13,408		10,137
Equity-based compensation — restricted performance units	17,367		18,518		4,743
Board of Directors incentive plan	2,202		2,012		3,120
Total incentive compensation expense	$	34,457	$	36,663	$	33,064

NOTE 10 — EMPLOYEE BENEFIT PLANS

Black Stone Natural Resources Management Company, a subsidiary of the Partnership, sponsors a defined contribution 401(k) Profit Sharing Plan (the “401(k) Plan”) for the benefit of substantially all employees of the Partnership. The 401(k) Plan became effective on January 1, 2001 and allows eligible employees to make tax-deferred contributions up to 100% of their annual compensation, not to exceed annual limits established by the Internal Revenue Service. The Partnership makes matching contributions of 100% of employee 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 Partnership matching contributions vest immediately. The Partnership’s contributions were $0.6 million, $0.5 million, and $0.6 million for the years ended December 31, 2017, 2016, and 2015, respectively.

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BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 11 — COMMITMENTS AND CONTINGENCIES

Leases

The Partnership leases certain office space and equipment under cancelable and non-cancelable operating leases that end at various dates through 2021. The Partnership recognizes rent expense on a straight-line basis over the lease term. Rent expense under such arrangements was $2.5 million, $1.9 million, and $1.8 million for the years ended December 31, 2017, 2016, and 2015, respectively. Such amounts are included in general and administrative expense on the consolidated statements of operations.

Future minimum lease commitments under non-cancelable leases are as follows as of December 31, 2017:



Year Ending December 31,	(in thousands)
2018	$	1,654
2019	38
2020	16
2021	—
Total	$	1,708

Environmental Matters

The Partnership’s business includes activities that are subject to U.S. federal, state and local environmental regulations with regard to air, land, and water 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 be significant to the consolidated financial statements and no provision for potential remediation costs has been made.

Put Option Related to Noble Acquisition

By acquiring 100% of the issued and outstanding securities of Samedan, now NAMP Holdings, LLC, the Partnership acquired a 100% interest in Comin-Termin, LLC, now NAMP GP, LLC ("Holdings"), Comin 1989 Partnership LLLP, now NAMP 1, LP ("Comin"), and Temin 1987 Partnership LLLP, now NAMP 2, LP ("Temin"). Pursuant to certain co-ownership agreements, various co-owners hold undivided beneficial ownership interests in 47.34% and 44.39% of the minerals interests held of record by Holdings and Temin, respectively. Based on the terms of the co-ownership agreements, the co-owners each have an unconditional option to require Comin or Temin, as applicable, to purchase their beneficial ownership interest in the mineral interests held of record by Holdings or Temin, as applicable, at any time within 30 days of receiving such repurchase notice. The purchase price of the beneficial ownership interest shall be based on an evaluation performed by Comin or Temin, as applicable, in good faith. As of December 31, 2017, the Partnership had not received notice from any co-owner to exercise their repurchase option, and as such, no liability was recorded.

Litigation

From time to time, the Partnership is involved in legal actions and claims arising in the ordinary course of business. The Partnership believes existing claims as of December 31, 2017 will be resolved without material adverse effect on the Partnership’s financial condition or results of operations.

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BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 12 — PREFERRED UNITS

Series A Redeemable Preferred Units

The Partnership had 26,363 and 52,691 Series A redeemable preferred units outstanding with a carrying value of $27.0 million and $54.0 million as of December 31, 2017 and 2016, respectively. The aforementioned amounts include accrued distributions of $0.7 million and $1.3 million as of December 31, 2017 and 2016, respectively. The Series A redeemable preferred units are classified as mezzanine equity on the consolidated balance sheets since redemption is outside the control of the Partnership. The Series A redeemable preferred units are entitled to an annual distribution of 10%, payable on a quarterly basis in arrears.

Prior to liquidation of the Partnership, and while any of the Series A redeemable preferred units remain outstanding, cash or other property of the Partnership will be distributed 100% to the Series A redeemable preferred unitholders until the aggregate Unpaid Preferred Yield (as defined below) of each Series A redeemable preferred unit accrued through the last day of the immediately preceding calendar quarter has been reduced to zero. Distributions in excess of the aggregate Unpaid Preferred Yield will be distributed 100% to common and subordinated unitholders, until there has been distributed an aggregate amount in respect of such calendar year equal to 10% of the aggregate Interest Fair Market Value of the outstanding common and subordinated units as of the first day of such calendar year. Any additional distributions shall be distributed to the common and subordinated unitholders, on the one hand, and the Series A redeemable preferred unitholders, on the other hand, pro rata on an as-is-converted basis.

The terms “Interest Fair Market Value,” “Preferred Yield,” and “Unpaid Preferred Yield” have the following meanings:

“Interest Fair Market Value” means, as of any date, the amount which would be received by the holder of a common unit or subordinated unit, as applicable, if (a) all of the Series A redeemable preferred units were converted into or exchanged or exercised for common units and, during the subordination period, subordinated units, (b) the fair market value of the assets of the Partnership in excess of its liabilities as of the date of determination of Interest Fair Market Value equaled the Value (as defined in the partnership agreement) as of such date, adjusted to reflect any increases in equity value resulting from the deemed conversion, exchange or exercise of convertible securities, and (c) an amount equal to such Value (as defined in the partnership agreement), as so adjusted, were distributed to the unitholders in accordance with the liquidation distribution provisions of the partnership agreement.

“Preferred Yield” means a yield on the outstanding Series A redeemable preferred units equivalent to a 10% per annum interest rate (subject to adjustment following certain 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 Series A redeemable 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 the IPO through the date established, over (b) the cumulative amount of distributions made as of the date established in respect of the Series A redeemable preferred unit.

The Series A redeemable preferred units are convertible into common and subordinated units at the option of the Series A redeemable preferred unitholders. The Series A redeemable preferred units have an adjusted conversion price of $14.2683 and an adjusted conversion rate of 30.3431 common units and 39.7427 subordinated units per redeemable preferred unit, which reflects the reverse split described in Note 1 – Business and Basis of Presentation and the capital restructuring related to the IPO. The Series A redeemable preferred unitholders can elect to have the Partnership redeem, at face value, up to 26,363 redeemable preferred units as of December 31, 2017.

The Partnership shall have the right, at its sole option, to redeem an amount of Series A redeemable preferred units equal to the units being redeemed by an owner of Series A redeemable preferred units on each December 31. Any amount of a given year’s Series A redeemable preferred units eligible for redemption not redeemed on December 31 shall automatically convert to common and subordinated units on January 1 in the following year. All Series A redeemable preferred units not redeemed by March 31, 2018 automatically convert to common and subordinated units effective as of January 1, 2018 or as soon as practicable thereafter.

F-28

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the year ended December 31, 2017, 19,704 Series A redeemable preferred units were redeemed for $20.2 million, including accrued unpaid yield. For the year ended December 31, 2017, 6,624 Series A redeemable preferred units totaling $6.6 million were converted into 200,996 common units and 263,247 subordinated units as a result of the mandatory conversion subsequent to December 31, 2016. For the year ended December 31, 2016, 18,461 Series A redeemable preferred units were redeemed for $19.0 million, including accrued unpaid yield. For the year ended December 31, 2016, 6,064 Series A redeemable preferred units totaling $6.1 million were converted into the equivalent of 184,006 common units and 240,986 subordinated units on an adjusted basis. For the year ended December 31, 2015, 39,240 Series A redeemable preferred units totaling $39.2 million were converted into the equivalent of 1,190,664 common units and 1,559,502 subordinated units on an adjusted basis.

On November 6, 2015, the Partnership commenced a tender offer to purchase up to 100% of the then outstanding Series A redeemable preferred units at par value plus unpaid accrued yield. The tender offer expired on December 10, 2015. The Partnership purchased and canceled 40,747 Series A redeemable preferred units for $1,019.45 per unit for a total cost of $41.5 million, excluding fees and expenses related to the tender offer.

Series B Cumulative Convertible Preferred Units

On November 28, 2017, the Partnership issued and sold in a private placement 14,711,219 Series B cumulative convertible preferred units representing limited partner interests in the Partnership to the "Purchaser" for a cash purchase price of $20.3926 per Series B cumulative convertible preferred unit, resulting in total proceeds of approximately $300 million.

The Series B cumulative convertible preferred units are entitled to an annual distribution of 7%, payable on a quarterly basis in arrears. For the eight quarters consisting of the quarter in respect of which the initial distribution is paid and the seven full quarters thereafter, the quarterly distribution may be paid, at the sole option of the Partnership, (i) in-kind in the form of additional Series B cumulative convertible preferred units (the "Series B PIK Units"), (ii) in cash, or (iii) in a combination of Series B PIK Units and cash. Beginning with the ninth quarter, all Series B cumulative convertible preferred unit distributions shall be paid in cash. The number of Series B PIK Units to be issued, if any, shall equal the quotient of the Series B cumulative convertible preferred unit distribution amount (or portion thereof) divided by the Series B cumulative convertible preferred unit purchase price of $20.3926.

The Series B cumulative convertible preferred units are convertible into common units of the Partnership on November 29, 2019 and once per quarter thereafter. At such time, the Series B cumulative convertible preferred units may be converted by each holder at its option, in whole or in part, into common units on a one-for-one basis at the purchase price of $20.3926, adjusted to give effect to any accrued but unpaid accumulated distributions on the applicable Series B cumulative convertible preferred units through the most recent declaration date. However, the Partnership shall not be obligated to honor any request for such conversion if such request does not involve an underlying value of common units of at least $10 million based on the closing trading price of common units on the trading day immediately preceding the conversion notice date, or such lesser amount to the extent such exercise covers all of a holder's Series B cumulative convertible preferred units.

The Series B cumulative convertible preferred units had a carrying value of $295.4 million, including accrued distributions of $1.9 million, as of December 31, 2017. The Series B cumulative convertible preferred units are classified as mezzanine equity on the consolidated balance sheet since redemption is outside the control of the Partnership.

NOTE 13 — EARNINGS PER UNIT

The Partnership applies the two-class method for purposes of calculating earnings per unit (“EPU”). The holders of the Partnership’s restricted common and subordinated units have all the rights of a unitholder, including non-forfeitable distribution rights. As participating securities, the restricted common and subordinated units are included in the calculation of basic earnings per unit. For the periods presented, the amount of earnings allocated to these participating units was not material.

Net income (loss) attributable to the Partnership is allocated to our general partner and the common and subordinated unitholders in proportion to their pro rata ownership after giving effect to distributions, if any, declared during the period. The Series A redeemable preferred units could be converted into 0.8 million common units and 1.1 million subordinated units as of December 31, 2017. The Series B cumulative convertible preferred units could be converted into 1.6 million weighted average common units as of December 31, 2017.

At December 31, 2017, if the outstanding Series A redeemable preferred units were converted to common and subordinated units, and the outstanding Series B cumulative convertible preferred units were converted to common units, the effect would be anti-dilutive. Therefore, the Series A redeemable preferred units and the Series B cumulative convertible preferred units are not included in the diluted EPU calculations.

F-29

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Partnership’s restricted performance unit awards are contingently issuable units that are considered in the calculation 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 the reporting period were the end of the contingency period. As of December 31, 2017, there were no units related to the Partnership’s restricted performance unit awards included in the calculation of diluted EPU as the inclusion of these units would be anti-dilutive.

The following table sets forth the computation of basic and diluted earnings per unit:



	For the Year Ended December 31,
	2017			2016			2015
	(in thousands, except per unit amounts)
NET INCOME (LOSS)	$	157,153		$	20,188		$	(101,305	)
Net loss attributable to Predecessor	—			—			(450		)
Net income attributable to noncontrolling interests subsequent to initial public offering	34			12			1,260
Distributions on Series A redeemable preferred units subsequent to initial public offering	(3,117		)	(5,763		)	(7,522		)
Distributions on Series B cumulative convertible preferred units	$	(1,925	)	—			—
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS SUBSEQUENT TO INITIAL PUBLIC OFFERING	$	152,145		$	14,437		$	(108,017	)
ALLOCATION OF NET INCOME (LOSS) SUBSEQUENT TO INITIAL PUBLIC OFFERING ATTRIBUTABLE TO:
General partner interest	$	—		$	—		$	—
Common units	98,389			24,669			(54,326		)
Subordinated units	53,756			(10,232		)	(53,691		)
	$	152,145		$	14,437		$	(108,017	)
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:
Per common unit (basic)	$	1.01		$	0.26		$	(0.56	)
Weighted average common units outstanding (basic)	97,400			96,073			96,182
Per subordinated unit (basic)	$	0.56		$	(0.11	)	$	(0.56	)
Weighted average subordinated units outstanding (basic)	95,149			95,138			95,057
Per common unit (diluted)	$	1.01		$	0.26		$	(0.56	)
Weighted average common units outstanding (diluted)	97,400			96,243			96,182
Per subordinated unit (diluted)	$	0.56		$	(0.11	)	$	(0.56	)
Weighted average subordinated units outstanding (diluted)	95,149			95,138			95,057

NOTE 14 — COMMON AND SUBORDINATED UNITS

Common and Subordinated Units

The common units and subordinated units represent limited partner interests in the Partnership. The holders of common units, subordinated units, Series A redeemable preferred units, and Series B cumulative convertible preferred units are holders of separate classes of limited partner interests in the Partnership.

The partnership agreement restricts unitholders’ voting rights by providing that any units held by a person or group that owns 15% or more of any class of units then outstanding, other than the limited partners in BSMC prior to the IPO, their transferees, persons who acquired such units with the prior approval of the board of directors of the Partnership's general partner, holders of Series B cumulative convertible preferred units in connection with any vote, consent or approval of the Series B cumulative convertible preferred units as a separate class, and persons who own 15% or more of any class as a result of any redemption or purchase of any other person's units or similar action by the Partnership or any conversion of the Series B cumulative convertible preferred units at the Partnership's option or in connection with a change of control may not vote on any matter.

F-30

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The holders of common units and subordinated units are entitled to participate in distributions and exercise the rights and privileges provided to limited partners holding common units and subordinated units under the partnership agreement.

The partnership agreement generally provides that any distributions will be paid each quarter during the subordination period (as defined in our partnership agreement) in the following manner:


•	first, to the holders of the Series B cumulative convertible preferred units in an amount equal to 7% per annum, subject to certain adjustments;


•	second, to the holders of common units, until each common unit has received the applicable minimum quarterly distribution in the amounts specified below plus any arrearages from prior quarters; and


•	third, to the holders of subordinated units, until each subordinated unit has received the applicable minimum quarterly distribution.

If the distributions to common and subordinated unitholders exceed the applicable minimum quarterly distribution per unit, then such excess amounts will be distributed pro rata on the common and subordinated units as if they were a single class.

Common Unit Repurchase Program

On March 4, 2016, the Board of the Partnership's general partner authorized the repurchase of up to $50.0 million in common units through a program that terminated on September 15, 2016. The repurchase program authorized the Partnership to make repurchases on a discretionary basis as determined by management, subject to market conditions, applicable legal requirements, available liquidity, and other appropriate factors. The Partnership repurchased a total of 1.3 million common units for an aggregate cost of $20.2 million. The repurchase program was funded from the Partnership's cash on hand or availability on the Credit Facility. Repurchased common units were canceled.

NOTE 15 — AT-THE-MARKET OFFERING PROGRAM

On May 26, 2017, the Partnership commenced an at-the-market offering program (the “ATM Program”) and in connection therewith entered into an Equity Distribution Agreement with Wells Fargo Securities, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, and UBS Securities LLC, as Sales Agents (each a “Sales Agent” and collectively the “Sales Agents”). Pursuant to the terms of the ATM Program, the Partnership may sell, from time to time through the Sales Agents, the Partnership’s common units representing limited partner interests having an aggregate offering price of up to $100,000,000. Sales of common units, if any, may be made in negotiated transactions or transactions that are deemed to be “at the market” offerings as defined in Rule 415 under the Securities Act of 1933, as amended (the “Securities Act”), including sales made directly on the New York Stock Exchange or sales made to or through a market maker other than on an exchange.

Under the terms of the ATM Program, the Partnership may also sell common units to one or more of the Sales Agents as principal for its own account at a price to be agreed upon at the time of sale. Any sale of common units to a Sales Agent as principal would be pursuant to the terms of a separate agreement between the Partnership and such Sales Agent.

The Partnership intends to use the net proceeds from any sales pursuant to the ATM Program, after deducting the Sales Agents’ commissions and the Partnership’s offering expenses, for general partnership purposes, which may include, among other things, repayment of indebtedness outstanding under the Partnership’s Credit Facility.

Common units to be sold pursuant to the Equity Distribution Agreement will be offered and sold pursuant to the Partnership’s existing effective shelf-registration statement on Form S-3 (File No. 333-215857), which was declared effective by the Securities and Exchange Commission on February 8, 2017.

The Equity Distribution Agreement contains customary representations, warranties and agreements, indemnification obligations, including for liabilities under the Securities Act, other obligations of the parties and termination provisions.

Through December 31, 2017, the Partnership sold 2.0 million common units under the ATM Program for net proceeds of $32.5 million.

F-31

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 16 — SUBSEQUENT EVENTS

On February 9, 2018, the Board approved a distribution for the period October 1, 2017 to December 31, 2017 of $0.3125 per common unit and $0.20875 per subordinated unit. Distributions were paid on February 27, 2018 to unitholders of record at the close of business on February 20, 2018.

F-32

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES

SUPPLEMENTAL 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 working interests in various producing and non-producing oil and natural gas properties in several other areas throughout the U.S. Therefore, the following disclosures 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 Activities

Costs incurred in oil and natural gas property acquisition, exploration and development, whether capitalized or expensed, are presented below:



	Year Ended December 31,
	2017		2016		2015
	(in thousands)
Acquisition Costs of Properties:¹
Proved	$	96,596	$	40,242	$	2,302
Unproved	383,535		100,888		60,994
Exploration Costs	618		645		2,592
Development Costs	81,056		73,316		60,056
Total	$	561,805	$	215,091	$	125,944


^1.	See Note 4 – Oil and Natural Gas Properties Acquisitions for further discussion. Unproved properties also include purchases of leasehold prospects.

Property acquisition costs include costs incurred to purchase, lease, or otherwise acquire a property. Development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells, and to provide facilities to extract, treat, and gather natural gas. Refer below for total capitalized costs and associated accumulated DD&A and impairment.

Oil and Natural Gas Capitalized Costs

Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, and amortization, including impairments, are presented below:



	As of December 31,
	2017			2016
	(in thousands)
Proved properties	$	2,258,893		$	2,091,337
Unproved properties	988,720			605,736
Total	3,247,613			2,697,073
Accumulated depreciation, depletion, amortization, and impairment	(1,766,842		)	(1,652,930		)
Oil and natural gas properties, net	$	1,480,771		$	1,044,143

F-33

Oil and Natural Gas Reserve Information

The following table sets forth estimated net quantities of the Partnership’s proved, proved developed, and proved undeveloped oil and natural gas reserves. These reserve estimates exclude insignificant natural gas liquid quantities owned by the Partnership. Estimated reserves for the periods presented are based on the unweighted average of first-day-of-the-month commodity prices over the period January through December for the year in accordance with definitions and guidelines set forth by the SEC and the FASB.



	Crude Oil (MBbl)		Natural Gas (MMcf)		Total (MBoe)
Net proved reserves at December 31, 2014	17,067		204,256		51,109
Revisions of previous estimates¹	(197	)	(17,043	)	(3,037	)
Purchases of minerals in place²	8		367		69
Extensions, discoveries and other additions³	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
Revisions of previous estimates¹	3,007		29,024		7,844
Purchases of minerals in place⁴	1,322		5,683		2,269
Extensions, discoveries and other additions⁵	1,877		79,455		15,120
Production	(3,680	)	(47,498	)	(11,596	)
Net proved reserves at December 31, 2016	18,368		270,339		63,425
Revisions of previous estimates¹	(1,234	)	21,067		2,277
Purchases of minerals in place⁶	2,267		30,250		7,309
Extensions, discoveries and other additions⁷	2,050		38,397		8,449
Production	(3,552	)	(59,779	)	(13,515	)
Net proved reserves at December 31, 2017	17,899		300,274		67,945
Net Proved Developed Reserves⁸
December 31, 2015	15,497		174,555		44,590
December 31, 2016	18,150		223,057		55,327
December 31, 2017	17,891		233,017		56,727
Net Proved Undeveloped Reserves⁹
December 31, 2015	345		29,120		5,198
December 31, 2016	218		47,282		8,098
December 31, 2017	8		67,257		11,218


¹	Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors. The most notable technical revisions are related to well performance in certain Haynesville/Bossier wells.


²	Includes the acquisition of mineral-and-royalty reserves primarily located throughout Texas, including in the Eagle Ford Shale and Wolfcamp plays and working interest reserves, the substantial majority of which is located in the Haynesville/Bossier play in San Augustine County, Texas.


³	Includes discoveries and additions primarily related to active drilling in the Haynesville/Bossier, Bakken/Three Forks, Eagle Ford Shale, Wilcox, Granite Wash, and Fayetteville plays.


⁴	Includes the acquisition of mineral-and-royalty reserves primarily in the Marcellus and Wolfcamp plays.


⁵	Includes discoveries and additions primarily related to active drilling in the Haynesville/Bossier, Bakken/Three Forks, Wilcox, Eagle Ford, and Fayetteville plays.


⁶	Includes the acquisition of mineral-and-royalty reserves primarily in East Texas and the Permian and Williston basins.


⁷	Includes extensions and additions related to drilling activities within multiple basins.


⁸	Proved developed reserves of 61 MBoe, 74 MBoe, and 84 MBoe as of December 31, 2017, 2016, and 2015, respectively, were attributable to noncontrolling interests in the Partnership’s consolidated subsidiaries.


⁹	As of December 31, 2017, 2016, and 2015, no proved undeveloped reserves were attributable to noncontrolling interests.

F-34

Standardized Measure of Discounted Future Net Cash Flows

Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the 12-month unweighted average of first-day-of-the-month commodity prices for the periods presented. All prices are adjusted by field for quality, transportation fees, energy content and regional price differentials. Future cash inflows are computed by applying applicable prices relating to the Partnership’s proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions. There are no future income tax expenses deducted from future production revenues in the calculation of the standardized measure because the Partnership is not subject to federal income taxes. The Partnership is subject to certain state based taxes; however, these amounts are not material. See Note 2 – Summary of Significant Accounting Policies for further discussion.



	Year Ended December 31,
	2017			2016			2015
	(in thousands)
Future cash inflows	$	1,643,582		$	1,267,179		$	1,211,290
Future production costs	(211,064		)	(193,749		)	(205,861		)
Future development costs	(70,111		)	(36,509		)	(84,746		)
Future income tax expense	(2,655		)	(3,516		)	—
Future net cash flows (undiscounted)	1,359,752			1,033,405			920,683
Annual discount 10% for estimated timing	(497,103		)	(430,390		)	(365,711		)
Total¹	$	862,649		$	603,015		$	554,972


¹	Includes standardized measure of discounted future net cash flows of approximately $0.5 million, $0.6 million, and $0.7 million for December 31, 2017, 2016, and 2015, attributable to noncontrolling interests in the Partnership’s consolidated subsidiaries.

The following summarizes the principal sources of change in the standardized measure of discounted future net cash flows:



	Year Ended December 31,
	2017			2016			2015
	(in thousands)
Standardized measure, beginning of year	$	603,015		$	554,972		$	1,143,094
Sales, net of production costs	(295,941		)	(210,354		)	(222,206		)
Net changes in prices and production costs related to future production	169,608			(81,456		)	(621,065		)
Extensions, discoveries and improved recovery, net of future production and development costs	113,199			86,606			165,020
Previously estimated development costs incurred during the period	11,118			28,909			7,084
Revisions of estimated future development costs	2,653			—			669
Revisions of previous quantity estimates, net of related costs	86,228			147,507			(67,911		)
Accretion of discount	60,512			55,662			114,309
Purchases of reserves in place, less related costs	107,891			34,751			584
Other	4,366			(13,582		)	35,394
Net increase (decrease) in standardized measures	259,634			48,043			(588,122		)
Standardized measure, end of year	$	862,649		$	603,015		$	554,972

The data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations are based on a significant amount of estimates and assumptions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from historical prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.

F-35

Selected Quarterly Financial Information—Unaudited

Quarterly financial data was as follows for the periods indicated.



	First Quarter		Second Quarter			Third Quarter		Fourth Quarter²
	(In thousands, except for per unit data)
2017
Total revenue	$	124,582	$	120,524		$	89,111	$	95,442
Income (loss) from operations	65,015		57,840			26,216		23,013
Net income (loss)	61,583		54,174			22,034		19,362
Net income (loss) attributable to the general partner and common and subordinated units	60,460		53,518			21,388		16,779
Net income (loss) attributable to common and subordinated units per unit (basic)¹
Per common unit (basic)	0.37		0.33			0.16		0.15
Per subordinated unit (basic)	0.26		0.22			0.05		0.03
Net income (loss) attributable to common and subordinated units per unit (diluted)¹
Per common unit (diluted)	0.37		0.33			0.16		0.15
Per subordinated unit (diluted)	0.26		0.22			0.05		0.03
Cash distributions declared and paid per limited partner unit
Per common unit	$	0.2875	$	0.2875		$	0.3125	$	0.3125
Per subordinated unit	$	0.1838	$	0.1838		$	0.2088	$	0.2088
Total assets	$	1,199,722	$	1,250,086		$	1,246,070	$	1,576,451
Long-term debt	388,000		393,000			362,000		388,000
Total mezzanine equity	34,145		27,085			27,092		322,422
2016
Total revenue	$	64,381	$	40,569		$	99,171	$	56,712
Net income (loss)	11,610		(19,478		)	39,316		(3,979		)
Income (loss) from operations	10,749		(20,810		)	37,535		(7,286		)
Net income (loss) attributable to the general partner and common and subordinated units	8,943		(22,111		)	36,219		(8,614		)
Net income (loss) attributable to common and subordinated units per unit (basic)¹
Per common unit (basic)	0.09		(0.08		)	0.24		0.01
Per subordinated unit (basic)	0.01		(0.15		)	0.14		(0.11		)
Net income (loss) attributable to common and subordinated units per unit (diluted)¹
Per common unit (diluted)	0.09		(0.08		)	0.24		0.01
Per subordinated unit (diluted)	0.01		(0.15		)	0.14		(0.11		)
Cash distributions declared per limited partner unit
Per common unit	$	0.2625	$	0.2625		$	0.2875	$	0.2875
Per subordinated unit	$	0.1838	$	0.1838		$	0.1838	$	0.1838
Total assets	1,045,843		1,126,830			1,137,232		1,128,827
Long-term debt	116,000		285,000			299,000		316,000
Total mezzanine equity	54,001		54,001			54,015		54,015

¹See Note 13 – Earnings Per Unit in the consolidated financial statements.

² Reported volumes in the fourth quarter of 2016 were negatively impacted by production shut-ins estimated at 1.0 MBoe/d for the quarter related to offset completion work and processing plant downtime in the Haynesville Shale.

F-36