UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)

x☒ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 20162019
OR
¨☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934
For the transition period from _______________ to _______________
Commission file number 001-37362
Black Stone Minerals, L.P.
(Exact Name of Registrant As Specified in Its Charter)its charter)

Delaware47-1846692
(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
(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol (s)Name of each exchange on which registered
Common Units Representing Limited Partner InterestsBSMNew 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, or a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer” andfiler,” “smaller reporting company”company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check One):
Large Accelerated FilerxxAccelerated 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 $1,064,853,317$2,409,774,181 on June 30, 2016,28, 2019, the last business day of the registrant’s most recently completed second fiscal quarter, based on a closing price of $15.50 per unit as reported by the New York Stock Exchange on such date. As of February 22, 2017, 97,113,31019, 2020, 205,944,172 common units 95,149,984 subordinated units, and 52,69114,711,219 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 to be held on June 8, 2017.
unitholders.






BLACK STONE MINERALS, L.P.
TABLE OF CONTENTS
 
PAGE
PART I
PAGE
ITEMS 1 AND 2.
2
2922
4742
4742
4742
PART II
4843
5447
5548
7262
7263
7263
7363
7364
PART III
7465
7465
7465
7465
7465
PART IV
7566


ii
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”).
Authorization for Expenditures (AFE). A budgeting document, usually prepared by an operator, to list estimated expenses of drilling a well to a specified depth, casing point or geological objective, and then either completing or abandoning the well. This estimate of expenses is provided to partners for approval prior to commencement of drilling or subsequent operations.
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,to obtain access to proved reserves and exploration of provedprovide facilities for extracting, treating, gathering, and storing oil and natural gas reserves.gas.
Development well. A well drilled within the proved area of an oil and natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Differential. An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil 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.
Electrical log. An analysis that provides information on porosity, hydraulic conductivity, and fluid content of formations drilled in fluid-filled boreholes.
Exploitation. A drilling or other project which may target proven or unproven reserves (such asprobable or possible reserves), but which generally has a lower risk than that associated with exploration projects.

iii
GLOSSARY OF TERMS

Exploratory well. A well drilled to find and produce natural gasa new field or oil reserves not classified as proved to find a new reservoir in a field previously found to be productive of oil or natural gas or oil in another reservoir or to extend a known reservoir.
Extension well. A well drilled to extend the limits of a known reservoir.
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 a workingan 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 anglehorizontally 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 and preparing the hydrocarbons for delivery off the lease, constituting part of the current operating expenses of a working interest. Such costs include labor, supplies, repairs, maintenance, allocated overhead charges, workover costs, insurance, and other expenses incidental to production, but exclude lease acquisition or drilling or completion costs.
Log. A measurement that provides information on porosity, hydraulic conductivity, and fluid content of formations drilled in fluid-filled boreholes.
MBbls. One thousand barrels of oil or other liquid hydrocarbons.
MBoe. One thousand barrels of oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of oil.Boe.
MBoe/d. MBoe per day.
Mcf. ThousandOne 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,develop, 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 working interest owned in gross acres or gross wells, respectively.
Net revenue interest. An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty, overriding royalty, and other non-cost-bearing interests.
Natural gas. A combination of light hydrocarbons that in average pressure and temperature conditions, is foundexists in a gaseous state.state at atmospheric temperature and pressure. 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.
iv
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.

iv
GLOSSARY OF TERMS

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 ofTypically, these costs areinclude wages for workers, facilities lease costs, equipment maintenance, well repairs, logistical support, applicable taxes, and insurance.
PUD. Proved undeveloped, used to characterize reserves.
Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
Proved developed reserves. ReservesProved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Proved developed producing reserves. Reservesreserves (PDP). Proved reserves expected to be recovered from existing completion intervals in existing wells.
Proved reserves. The estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.
Proved undeveloped reserves. reserves (PUD). 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.
v
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).

v
GLOSSARY OF TERMS

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 or 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.development or operating costs.
Seismic data. Seismic data is used by scientists to interpret the composition, fluid content, extent, and geometry of rocks in the subsurface. Seismic data 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, and is often established by regulatory agencies.
Standardized measure. The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SECSecurities 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 oil and/or natural gas with low flow rates for long periods of time.
Trend. A region of oil and/or natural gas production, the geographic limits of which have not been fully 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. interest (WI). 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 0.40.4% by weight percent that is used as a benchmark for the other crude oils.
 
 

vi





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 abilitylevel of drilling activity by our operators to obtain capital or financing needed for development and exploration operations;particularly in areas such as the Shelby Trough where we have concentrated acreage positions;
•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;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.



1
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.States ("U.S."). 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 marketing our mineral assets for lease, creatively structuring the 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 onworking interest basis. We believe our interests. Our primary business objective islarge, diversified asset base and long-lived, non-cost-bearing mineral and royalty interests provide for stable to grow our reserves,growing production and reserves over time, allowing the majority of generated cash generated from operations over the long term, while paying,flow to the extent practicable, a growing quarterly distributionbe distributed to our unitholders.
We own mineral interests in approximately 15.516.8 million gross acres, with an average 45.7%43.5% ownership interest in that acreage. We also own nonparticipating royalty interestsNPRIs in 1.51.8 million gross acres and overriding royalty interestsORRIs in 1.51.7 million gross acres. These non-cost-bearing interests, which we refer to collectively as our “mineral and royalty interests,” include ownership in approximately 50,00069,000 producing wells. Our mineral and royalty interests are located in 41 states and in 64 onshore basins in the continental United States.U.S., including all of the major onshore producing basins. Many of these interests are in active resource plays, including the Bakken/Three ForksHaynesville/Bossier shales in the Williston Basin, the Eagle Ford Shale in South Texas,East Texas/Western Louisiana, the Wolfcamp/Spraberry/Bone Spring in the Permian Basin, the Niobrara/Codell ShalesBakken/Three Forks in the DJ basin, the Haynesville/Bossier Shales in East Texas/Western Louisiana,Williston Basin, and the Fayetteville ShaleEagle Ford 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.South Texas. The combination of the breadth of our asset base, and the long-lived, non-cost-bearing nature of our mineral and royalty interests, exposesand our active management expose us to potential additional production and reserves from new and existing plays without investingbeing required to invest additional capital.  
We are a publicly traded Delaware limited partnership formed on September 16, 2014. On May 6, 2015, we completed our initial public offering of 22,500,000 common units representing limited partner interests at a price to the public of $19.00 per common unit.interests. Our common units trade on the New York Stock Exchange under the symbol "BSM."
BSM files or furnishes annual reports on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K, as well as any amendments to 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.

2
PART I

Our Assets
As of December 31, 2016,2019, our total estimated proved oil and natural gas reserves were 63,42568,543 MBoe based on a reserve report prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), an independent third-party petroleum engineering firm. Of the reserves as of December 31, 2016,2019, approximately 87.2%88.9% were proved developed reserves (approximately 78.2%86.5% proved developed producing and 9.0%2.4% proved developed non-producing) and approximately 12.8%11.1% were proved undeveloped reserves. At December 31, 2016,2019, our estimated proved reserves were 29.0%25% oil and 71.0%75% 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.is provided below under "Our Properties" based on major geographical region and by material resource play as denoted on the map below.
bsm-20191231_g1.jpg


 

3

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,develop, 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 interest, 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.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 thatover which we have the most influence over.influence. 
In addition to mineral interests, we also own other types of non-cost-bearing royalty interests, which include:
nonparticipating•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•Overriding royalty interests (“ORRIs”), which are royalty interests that burden working interests and represent the right to receive a fixed, cost-free percentage of production or revenue from production from a lease. ORRIs remain in effect until the associated leases expire.
Working-Interest Participation ProgramWe may own more than one type of mineral and royalty interest in the same tract of land. For example, where we own an ORRI in a lease on the same tract of land in which we own a mineral interest, our ORRI in that tract will relate to the same gross acres as our mineral interest in that tract. As of December 31, 2019, approximately 26% of our mineral and royalty interests are leased, calculated on a cumulative gross acreage basis for all three types of mineral and royalty interests. We have relied on representations made in the relevant purchase agreements to determine leasing status of recently acquired acreage.
The majority of our producing mineral and royalty interest acreage is pooled with third-party acreage to form pooled units. Pooling proportionately reduces our royalty interest in wells drilled in a pooled unit, and it proportionately increases the number of wells in which we have such reduced royalty interest.
Non-Operated Working Interests
We own non-operated working interests related to our mineral interests in various plays across our asset base. ManyThe majority of theseour working interest exposure is in the Haynesville/Bossier play in East Texas where we own non-operated working interests werealongside XTO Energy Inc. ("XTO Energy"), a subsidiary of Exxon Mobil Corporation, and BPX Energy, a subsidiary of BP plc. In 2017, we entered into farmout arrangements (discussed below) for our entire working interest position in that area. We also hold working interests acquired through working-interestworking interest participation rights, which we often include in the terms of our leases. This participation right complements our core mineral-and-royalty-interestmineral 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-interestworking 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
Beginning in 2017, we significantly reduced the number of ourwells in which we participate with a working interests, unrelatedinterest. We generally farm out or sell these participation rights to our mineralthird parties and often retain some form of non-cost-bearing interest in those wells, such as an overriding 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.interest.
We collectively refer to these working interests as our “working-interest participation program.” When we participate in non-operated working-interestworking interest opportunities, we are required to pay our portion of the costs associated with drilling and operating these wells. Our 2017 drilling capital expenditure budget associated with our working-interest participation program is expected to range between $50 and $60 million. Approximately 90% of our 2017 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. As of December 31, 2016, we owned non-operated working interests in over 8,500 gross (328 net) wells.
Working interest production represented 35.0%25% of our total production volumes during the year ended December 31, 2016.2019. As of December 31, 2019, we owned non-operated working interests in 9,717 gross (348 net) wells.

Our 2020 capital expenditure budget associated with our non-operated working interests is expected to be approximately $5 million. The majority of this capital will be spent for workovers on existing wells in which we own a working interest.


4

Farmout Agreements
In 2017, we entered into two farmout arrangements designed to reduce our working interest capital expenditures and thereby significantly lower our capital spending other than for mineral and royalty interest acquisitions. Under these agreements, we conveyed our rights to participate in certain non-operated working interest opportunities to external capital providers while retaining value from these interests in the form of additional royalty income or retained economic interests.
On February 21, 2017, we announced that we 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. We have an approximate 50% working interest in the acreage and are the largest mineral owner. A total of 20 wells were drilled over an initial phase, beginning with wells spud after January 1, 2017. Canaan elected to participate in an additional phase that began in September 2018 and continues for the earlier of 2 years or until 20 wells have been drilled. As of December 31, 2019, a total of 17 wells have been drilled during the second phase. After the completion of the second phase, Canaan will have the option to elect to participate in a similar third phase. During the first three phases of the agreement, Canaan commits on a phase-by-phase basis and funds 80% of our drilling and completion costs and is assigned 80% of our working interests in such wells (40% working interest on an 8/8ths basis) as the wells are drilled. After the third phase, Canaan can earn 40% of our working interest (20% working interest on an 8/8ths basis) in additional wells drilled in the area by continuing to fund 40% of our costs for those wells on a well-by-well basis. We receive an ORRI before payout and an increased ORRI after payout on all wells drilled under the agreement. From the inception of the agreement through December 31, 2019, we have received $90.0 million from Canaan under the agreement as reimbursement for capital costs associated with farmed-out working interests. As of December 31, 2019, $0.9 million was included in the Other long-term liabilities line item of the consolidated balance sheet for reimbursements received associated with farmed-out working interests not yet assigned to Canaan.
On November 21, 2017, we entered into a farmout agreement with Pivotal Petroleum Partners ("Pivotal"), a portfolio company of Tailwater Capital, LLC. The farmout agreement covers substantially all of our remaining working interests under active development in the Shelby Trough area of East Texas targeting the Haynesville and Bossier shale acreage (after giving effect to the Canaan farmout) until November 2025. Pivotal will earn our remaining working interest in wells operated by XTO Energy in San Augustine County, Texas not covered by the Canaan farmout (10% working interest on an 8/8ths basis), as well as 100% of our working interests (ranging from approximately 12.5% to 25% on an 8/8ths basis) in wells operated by BPX Energy in San Augustine and Angelina Counties, Texas. Initially, Pivotal is obligated to fund the development of up to 80 wells, in designated well groups, across several development areas and then has options to continue funding our working interest across those areas for the duration of the farmout agreement. Once Pivotal achieves a specified payout for a designated well group, we will obtain a majority of the original working interest in such well group. From the inception of the agreement through December 31, 2019, a total of 68 wells have been drilled in the contract area and we have received $115.2 million from Pivotal under the agreement as reimbursement for capital costs associated with farmed-out working interests. As of December 31, 2019, $0.9 million was included in the Other long-term liabilities line item of the consolidated balance sheet for reimbursements received associated with farmed-out working interests not yet assigned to Pivotal. Our development agreement with BPX Energy terminated in 2019 with respect to the majority of our acreage covered by the agreement. As such, Pivotal retains minimal rights or obligations related to the farmout for that area. We remain engaged with Pivotal around farmout opportunities with potential new operators in the area forfeited by BPX Energy.
As a result of the farmout agreements with Canaan and Pivotal, we expect net capital requirements associated with non-operated working interests to be minimal in 2020.


5

Our Properties
Material BasinsBSM Land Regions
We divide the contiguous U.S. into major geographical regions that we refer to as "BSM Land Regions." The following provides an overview of these regions:
•Gulf Coast. The Gulf Coast region consists of the land area along the Gulf of Mexico from South Texas through Florida. This region includes the Western Gulf (onshore), East Texas Basin, Louisiana-Mississippi Salt Basin, and Producing RegionsSouth Florida Basin.
•Southwestern U.S. The Southwestern U.S. region consists of the land area north of the Mexico-United States border from north-central Texas westward through Arizona. This region includes the Permian Basin, Fort Worth Basin, Bend Arch, Palo Duro Basin, Dalhart Basin, and Marfa Basin.
•Rocky Mountains.The Rocky Mountains region consists of the land area along the Rocky Mountains from Northern New Mexico through Montana and North Dakota. This region includes the Williston Basin, Montana Thrust Belt, Bighorn Basin, Powder River Basin, Greater Green River Basin, Denver-Julesburg Basin, Uinta-Piceance Basin, Park Basin, Paradox Basin, San Juan Basin, and Raton Basin.
•Eastern U.S. The Eastern U.S. region consists of the land area east of the Mississippi River and north of the Gulf Coast region. This region includes the Michigan Basin, Illinois Basin, Appalachian Basin, and Black Warrior Basin.
•Mid-Continent. The Mid-Continent region extends from Oklahoma north through Minnesota. This region includes the Anadarko Basin, Arkoma Basin, Forest City Basin, Cherokee Platform, Marietta Basin, and Ardmore Basin.
•Western U.S. The Western U.S. region consists of the land area west of the Rocky Mountains and Southwestern U.S. regions. This region includes the San Joaquin Basin, Santa Maria Basin, Ventura Basin, Los Angeles Basin, Sacramento Basin, and Eastern Great Basin.
The following tables present information about our mineral and royalty interests and working interests by BSM Land Region:
 
Acreage as of December 31, 20191
 Mineral and Royalty Interests
Working Interests2
BSM Land RegionMineral InterestsNPRIsORRIs
Gross Acres  
Net %3
Gross Acres  
Net %4
Gross Acres  
Net %4
Gross AcresNet Acres
Gulf Coast7,924,882  52.1 %553,760  4.2 %239,634  4.1 %504,345  93,953  
Southwestern US2,765,243  25.7 %1,005,794  3.5 %202,774  1.8 %60,679  17,610  
Rocky Mountains2,123,750  15.4 %243,637  3.4 %911,583  2.5 %95,588  16,289  
Eastern US1,657,142  47.4 %1,727  4.0 %74,892  1.4 %13,487  1,346  
Mid-Continent1,286,657  34.4 %39,071  3.9 %286,257  3.7 %40,302  23,731  
Western US1,025,564  89.2 %333  1.8 %32,965  2.9 %—  —  
Total16,783,238  43.5 %1,844,322  3.7 %1,748,105  2.8 %714,401  152,929  

1 We may own more than one type of interest in the same tract of land. For example, where we have acquired non-operated working interests throughrelated to our working-interest participation programmineral interests in a given tract, our working-interestworking interest acreage in that tract will relate to the same acres as our mineral-interestmineral 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,non-operated working interests, overlap between working-interestworking interest acreage and mineral-and-royalty-interestmineral and royalty interest acreage is significant, whilecan be significant; 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, 2016 
Average Daily
Production (Boe/d)
For the Year Ended
December 31, 2016
  Mineral and Royalty Interests 
Working Interests1
 
USGS Petroleum Province2
 Mineral Interests NPRIs ORRIs Gross Net 
Louisiana-Mississippi Salt Basins 5,446,455
 162,199
 18,846
 49,170
 6,203
 5,053
Western Gulf (onshore) 1,597,765
 213,111
 98,752
 116,134
 17,394
 6,191
Williston Basin 1,323,172
 62,133
 31,884
 54,734
 7,741
 4,061
Palo Duro Basin 1,016,847
 22,791
 1,120
 —
 —
 24
Permian Basin 1,016,197
 587,167
 177,275
 8,113
 4,731
 1,441
Anadarko Basin 550,740
 13,723
 180,157
 31,313
 21,294
 1,909
Appalachian Basin 490,274
 416
 14,836
 —
 —
 874
East Texas Basin 456,110
 44,429
 30,640
 151,811
 51,589
 6,906
Arkoma Basin 338,767
 9,087
 37,957
 9,045
 2,333
 1,614
Bend Arch-Fort Worth Basin 144,246
 55,205
 40,249
 53,606
 13,585
 427
Southwestern Wyoming 22,338
 —
 75,577
 15,336
 2,477
 454
Other 3,113,014
 310,992
 798,542
 39,408
 8,924
 2,729
Total 15,515,925
 1,481,253
 1,505,835
 528,670
 136,271
 31,683


12 ExcludesThis excludes acreage for which we have incomplete seller records.
23 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 materialRefers 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.
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.  
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.
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.
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. 
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:
        Average Daily Production (Boe/d)
  As of December 31, 2016 For the Year Ended December 31,
USGS Petroleum Province1
 Acres 
Average
Ownership
Interest2
 
Average
Ownership
Leased3
 2016 2015 2014
Louisiana-Mississippi Salt Basins 5,446,455
 53.4% 9.6% 3,415
 3,384
 4,061
Western Gulf (onshore) 1,597,765
 55.0% 34.7% 4,526
 5,021
 4,099
Williston Basin 1,323,172
 14.8% 35.4% 2,534
 2,430
 1,989
Palo Duro Basin 1,016,847
 46.5% 7.2% 24
 23
 16
Permian Basin 1,016,197
 14.0% 66.6% 1,035
 585
 566
Black Warrior Basin 592,968
 54.6% 2.3% —
 39
 41
Eastern Great Basin 567,749
 96.7% 0.1% 39
 —
 —
Anadarko Basin 550,740
 32.7% 59.6% 673
 959
 790
Appalachian Basin 490,274
 39.8% 22.1% 163
 80
 89
East Texas Basin 456,110
 52.7% 39.4% 1,854
 884
 793
Arkoma Basin 338,767
 53.7% 27.6% 1,302
 1,458
 1,646
Western Great Basin 338,303
 90.5%  –
 —
 —
 —
Piedmont 179,879
 67.8%  –
 —
 —
 —
North-Central Montana 171,026
 13.7% 27.8% 9
 4
 7
Atlantic Coastal Plain 164,670
 12.8% 28.8% 199
 —
 —
Bend Arch-Fort Worth Basin 144,246
 20.5% 33.3% —
 392
 252
Cherokee Platform 111,027
 13.8% 32.4% 34
 41
 46
Florida Peninsula 90,744
 12.1% 47.6% 2
 —
 —
Illinois Basin 80,864
 53.1% 8.0% 3
 2
 1
Powder River Basin 67,055
 11.3% 12.3% —
 56
 3
Other 771,067
 32.1% 20.4% 1,295
 301
 317
Total 15,515,925
 45.7% 22.0% 17,107
 15,659
 14,716

1 The basins and regions shown in the table are consistent with USGS petroleum-province delineations.
2average ownership interest. 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 reflectsreflect the weighted averages of our ownership
6

interests in all tracts in the basin or region.BSM Land Region. Our weighted-average mineralweighted average royalty interest for all of our mineral interests is approximately 20%, which may be multiplied by our ownership interest to approximate the average net royalty interest infor our mineral and royalty interests.
34 The average percent leased reflects the weighted average of our leased acres relativeRefers 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:
        Average Daily Production (Boe/d)
  As of December 31, 2016 For the Year Ended December 31,
USGS Petroleum Province1
 Acres 
Average
Royalty
Interest2
 
Average
Percent
Leased3
 2016 2015 2014
Permian Basin 587,167
 2.1% 47.5% 19
 31
 11
Western Gulf (onshore) 213,111
 4.6% 46.0% 14
 10
 14
Louisiana-Mississippi Salt Basins 162,199
 4.9% 48.3% 1
 —
  <1
North-Central Montana 134,559
 3.0% 9.3% —
 —
 —
Marathon Thrust Belt 117,442
 4.9% 1.6% —
 —
 —
Williston Basin 62,133
 2.6% 33.0% 92
 106
 64
Bend Arch-Fort Worth Basin 55,205
 4.1% 12.1% 1
 —
 3
East Texas Basin 44,429
 2.7% 80.3% 179
 381
 2
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% 18
 8
 2
Arkoma Basin 9,087
 2.6% 83.8% 13
 21
 —
Cambridge Arch-Central Kansas Uplift 8,903
 5.5% 83.7% —
 —
 —
Southwest Montana 4,367
 6.2% 7.3% —
 —
 —
Cherokee Platform 2,635
 4.6% 33.4% —
 —
 —
Nemaha Uplift 2,334
 1.6% 41.4% —
 —
 —
Montana Thrust Belt 2,242
 4.1%  –
 —
 —
 —
Sedgwick Basin 1,850
 2.5% 82.2% —
 —
 —
Black Warrior Basin 1,500
 0.3% 100.0% —
 —
 —
Uinta-Piceance Basin 560
 1.0%  –
 —
 —
 —
Other 1,549
 5.7% 22.6% 180
 185
 151
Total 1,481,253
 3.4% 38.4% 518
 742
 247

1 The basins and regions shown in the table are consistent with USGS petroleum-province delineations.
2average royalty interest. 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. BSM Land 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.
 Mineral and Royalty InterestsWorking Interests
Gross Well Count as of December 31, 20191
Average Daily Production (Boe/d) for the Year Ended December 31,Average Daily Production (Boe/d) for the Year Ended December 31,
BSM Land Region
MRI Wells2
WI Wells  201920182017201920182017
Gulf Coast12,796  2,091  20,702  16,425  13,016  10,312  11,869  10,056  
Southwestern US31,068  1,156  7,052  5,081  2,966  180  278  426  
Rocky Mountains13,923  2,047  5,463  7,050  4,440  678  934  1,157  
Eastern US2,055  256  750  886  1,027  24  22  24  
Mid-Continent8,372  4,166  2,223  2,366  2,343  897  1,120  1,287  
Western US831  1  257  270  269  1  —  —  
Total69,045  9,717  36,447  32,078  24,061  12,092  14,223  12,950  
31 The average percent leased reflectsWe own both mineral and royalty interests and working interests in 4,199 of the weighted average of our leased acres relativewells shown in each column above.
2 Refers to our total acreage on a tract-by-tract basis in the basin or region.mineral and royalty interest wells.






ORRIsMaterial Resource Plays
The following table sets forthlisting provides an overview of the resource plays we consider most material to our current and future business. These plays accounted for 75% of our aggregate production for the year ended December 31, 2019.
•Bakken/Three Forks. The Bakken shale and underlying Three Forks formation are located in the Williston Basin, which covers parts of North Dakota, South Dakota, and Montana in the U.S., and Saskatchewan and Manitoba in Canada. The U.S. portion of the Bakken/Three Forks play is within the Rocky Mountains BSM Land Region. We have significant exposure in these plays through our mineral and royalty interests as well as through our working interests.
•Haynesville/Bossier. The Haynesville/Bossier formation, located in East Texas and Western Louisiana, is within the Gulf Coast BSM Land Region and is one of the largest producing natural gas formations in the U.S. The play’s prospective acreage is evenly divided between East Texas and Western Louisiana, and while we have significant exposure through our mineral and royalty interests and working interests across the entire play, the majority of our acreage is located in East Texas, with a particular concentration in the prolific southern portion of the Shelby Trough in San Augustine, Nacogdoches, and Angelina Counties.
•Permian-Midland. The Midland Basin, which is a sub-basin within the Permian Basin, is located in West Texas in the Southwestern U.S. BSM Land Region. It is separated from the Delaware Basin to the west by a carbonate platform called the Central Basin Platform. We refer to the various Permian-aged resource plays within the Midland Basin as the Permian-Midland. These plays include the various members of the Spraberry and Wolfcamp formations. Our interests in the Permian-Midland resource plays are almost exclusively mineral and royalty interests.
7

•Permian-Delaware. The Delaware Basin, which is a sub-basin within the Permian Basin, is located in West Texas and southeastern New Mexico in the Southwestern U.S. BSM Land Region. It is separated from the Midland Basin to the east by a carbonate platform called the Central Basin Platform. We refer to the various Permian-aged resource plays within the Delaware Basin as the Permian-Delaware. These plays include the various members of the Bone Spring, Avalon, and Wolfcamp formations. Our interests in the Permian-Delaware resource plays are almost exclusively mineral and royalty interests.
•Eagle Ford. The Eagle Ford shale is located in South Texas within the Gulf Coast BSM Land Region and produces from various depths between 4,000 and 14,000 feet. 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.
The following tables present information about our ORRIs:mineral and royalty interests and non-operated working interests by material resource play.
 
Acreage as of December 31, 20191
 Mineral and Royalty Interests
Working Interests2
Resource PlayMineral InterestsNPRIsORRIs
Gross Acres  
Net %3
Gross Acres  
Net %4
Gross Acres  
Net %4
Gross AcresNet Acres
Bakken/
Three Forks		397,824  17.1 %39,022  1.3 %12,897  1.3 %53,456  7,266  
Haynesville/Bossier403,047  61.5 %28,516  2.2 %27,384  6.8 %303,847  52,290  
Permian-Midland231,875  7.3 %138,604  1.1 %106,970  0.6 %160  4  
Permian-Delaware133,167  10.9 %37,308  0.8 %5,243  2.9 %2,482  1,151  
Eagle Ford66,967  14.3 %106,729  1.3 %48,440  2.2 %1,147  87  
      Average Daily Production (Boe/d)
  As of December 31, 2016 For the Year Ended December 31,
USGS Petroleum Province1
 Acres 
Average
Royalty
Interest2
 2016 2015 2014
North-Central Montana 457,897
 2.5% 13
 35
 36
Anadarko Basin 180,157
 2.4% 200
 232
 253
Permian Basin 177,275
 0.8% 64
 72
 60
Western Gulf (onshore) 98,752
 1.7% 157
 262
 166
Powder River Basin 85,078
 3.6% 45
 98
 50
Southwestern Wyoming 75,577
 2.0% 451
 529
 530
Uinta-Piceance Basin 63,503
 1.6% 24
 37
 32
Michigan Basin 56,512
 1.0% 18
 21
 21
Bend Arch-Fort Worth Basin 40,249
 4.7% 108
 160
 166
Arkoma Basin 37,957
 3.0% 23
 29
 23
San Juan Basin 36,239
 1.1% 6
 3
 3
Williston Basin 31,884
 2.1% 59
 76
 54
East Texas Basin 30,640
 3.6% 96
 81
 100
Northern Alaska 20,039
 1.7% 28
 32
 27
Paradox Basin 19,269
 1.1% —
 2
 2
Louisiana-Mississippi Salt Basins 18,846
 3.3% 705
 1,185
 903
Denver Basin 15,880
 3.2% 117
 83
 91
Appalachian Basin 14,836
 2.6% 693
 —
 —
Wind River Basin 7,090
 1.3% 27
 33
 31
Cambridge Arch-Central Kansas Uplift 5,762
 3.8% 3
 5
 4
Other 32,393
 1.6% 156
 911
 884
Total 1,505,835
 2.2% 2,993
 3,886
 3,436

1 The basins and regions shownWe may own more than one type of interest in the table are consistent with USGS petroleum-province delineations.same tract of land. For example, where we have acquired non-operated working interests related to our mineral interests in a given tract, our working interest acreage in that tract will relate to the same acres as our mineral interest acreage in that tract. Consequently, some of the acreage shown for one type of interest may also be included in the acreage shown for another type of interest. Because of our non-operated working interests, overlap between working interest acreage and mineral and royalty interest acreage can be significant; overlap between the different types of mineral and royalty interests is not significant.
2 This excludes acreage for which we have incomplete seller records.
3 Refers to our average ownership interest. Ownership interest is the percentage that our undivided ownership interest in a tract bears to the entire tract. The average ownership interests shown reflect the weighted averages of our ownership interests in all tracts in the resource play. Our weighted average royalty interest for all of our mineral interests is approximately 20%, which may be multiplied by our ownership interest to approximate the average net royalty interest for our mineral interests.
4 Refers to our average royalty interest. 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:
      Average Daily Production (Boe/d)
  As of December 31, 2016 For the Year Ended December 31,
USGS Petroleum Province1
 
Gross Acres2
 
Net Acres2
 2016 2015 2014
East Texas Basin 151,811
 51,589
 4,776
 2,341
 1,564
Western Gulf (onshore) 116,134
 17,394
 1,494
 1,234
 786
Williston Basin 54,734
 7,741
 1,377
 1,425
 1,386
Bend Arch-Fort Worth Basin 53,606
 13,585
 118
 108
 129
Louisiana-Mississippi Salt Basins 49,170
 6,203
 932
 1,007
 2,077
Anadarko Basin 31,313
 21,294
 1,018
 1,205
 1,402
Southwestern Wyoming 15,336
 2,477
 11
 1
 6
Michigan Basin 13,287
 1,330
 6
 6
 6
Powder River Basin 13,016
 3,389
 103
 169
 121
Arkoma Basin 9,045
 2,333
 277
 341
 360
Permian Basin 8,113
 4,731
 323
 214
 204
Denver Basin 4,923
 1,040
 130
 5
 4
Paradox Basin 2,602
 1,281
 4
 5
 5
North-Central Montana 2,080
 605
 1
 1
 1
Uinta-Piceance Basin 1,005
 482
 68
 —
 —
San Juan Basin 960
 334
 15
 11
 9
Wind River Basin 440
 43
 —
 —
 —
Southern Oklahoma 390
 92
 132
 174
 141
Cherokee Platform 328
 137
 1
 5
 9
Illinois Basin 200
 16
 —
 —
 —
Other 177
 176
 279
 128
 109
Total 528,670
 136,272
 11,065
 8,380
 8,319

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 table sets forth information about our mineral-and-royalty-interest and working-interest wells as of December 31, 2016:
Mineral and Royalty Interests Working Interests
USGS Petroleum Province1
 
Gross Well Count2
 
USGS Petroleum Province1
 
Gross Well Count2
Permian Basin 21,887
 Anadarko Basin 2,777
Anadarko Basin 3,672
 Uinta-Piceance Basin 1,037
Williston Basin 3,034
 Permian Basin 796
Louisiana-Mississippi Salt Basin 2,981
 Arkoma Basin 727
East Texas Basin 2,925
 Western Gulf (onshore) 595
Western Gulf (onshore) 2,887
 East Texas Basin 567
Arkoma Basin 1,889
 Williston Basin 541
Uinta-Piceance Basin 1,321
 Louisiana-Mississippi Salt Basin 433
Bend Arch - Fort Worth Basin 1,173
 Southern Oklahoma 408
Michigan Basin 971
 Bend Arch - Fort Worth Basin 198
Appalachian Basin 826
 Appalachian Basin 192
Southwestern Wyoming 684
 Nemaha Uplift 105
Cherokee Platform 664
 Powder River Basin 66
Denver Basin 558
 Michigan Basin 62
North-Central Montana 532
 Denver Basin 21
San Juan Basin 530
 Cherokee Platform 14
Nemaha Uplift 502
 North-Central Montana 10
San Joaquin Basin 465
 Paradox Basin 8
Powder River Basin 399
 Black Warrior Basin 5
Southern Oklahoma 376
 Southwestern Wyoming 5
Other 1,666
 Other 10
Total 49,942
 Total 8,577

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 3,259 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 is 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 63% of our aggregate production for the year ended December 31, 2016.
  
Acreage as of December 31, 20161
  Mineral and Royalty Interests Working Interests
Resource Play2
 Mineral Interests NPRIs ORRIs Gross Net
Bakken Shale 309,892
 36,341
 13,210
 50,159
 7,105
Three Forks 296,343
 33,522
 12,530
 50,361
 6,732
Haynesville Shale 283,401
 7,255
 14,719
 183,337
 53,546
Bossier Shale 252,458
 1,816
 8,642
 170,716
 52,130
Marcellus Shale 240,784
 —
 13,356
 —
 —
Canyon Lime 219,279
 —
 —
 —
 —
Wolfcamp - Midland 187,152
 97,860
 125,817
 160
 4
Tuscaloosa Marine Shale 181,497
 23,397
 689
 —
 —
Granite Wash 102,786
 5,031
 86,556
 4,840
 1,254
Fayetteville Shale 71,089
 3,918
 11,708
 —
 —
Barnett Shale 62,732
 4,164
 36,155
 13,417
 7,747
Eagle Ford Shale 60,743
 86,152
 48,920
 1,147
 87
Wolfcamp - Delaware 44,520
 28,061
 4,643
 2,642
 971

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:
        Average Daily Production (Boe/d)
  As of December 31, 2016 For the Year Ended December 31,
Resource Play1
 Acres 
Average
Ownership
Interest2
 
Average
Ownership
Leased3
 2016 2015 2014
Bakken Shale 309,892
 18.1% 72.0% 1,659
 1,746
 1,275
Three Forks 296,343
 17.7% 73.4% 968
 823
 626
Haynesville Shale 283,401
 63.6% 66.7% 3,727
 2,728
 3,152
Bossier Shale 252,458
 69.0% 64.6% 330
 351
 548
Marcellus Shale 240,784
 14.5% 34.8% 111
 71
 74
Canyon Lime 219,279
 30.6% 20.8% 16
 8
 1
Wolfcamp - Midland 187,152
 4.8% 97.3% 136
 76
 27
Tuscaloosa Marine Shale 181,497
 60.8% 68.0% 52
 46
 6
Granite Wash 102,786
 15.2% 57.7% 167
 194
 241
Fayetteville Shale 71,089
 55.8% 77.6% 1,181
 1,349
 1,529
Barnett Shale 62,732
 15.5% 58.0% 181
 239
 228
Eagle Ford Shale 60,743
 15.5% 83.8% 2,095
 2,355
 1,595
Wolfcamp - Delaware 44,520
 19.2% 94.9% 437
 148
 132

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 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:
        Average Daily Production (Boe/d)
  As of December 31, 2016 For the Year Ended December 31,
Resource Play1
 Acres 
Average
Royalty
Interest2
 
Average
Percent
Leased3
 2016 2015 2014
Wolfcamp - Midland 97,860
 0.7% 75.3% 11
 22
 5
Eagle Ford Shale 86,152
 1.5% 28.4% 14
 3
 7
Bakken Shale 36,341
 1.4% 51.3% 63
 56
 37
Three Forks 33,522
 1.2%  54.8%
 36
 50
 27
Wolfcamp - Delaware 28,061
 0.4%  83.1%
 4
 1
 2
Tuscaloosa Marine Shale 23,397
 0.5% 93.2% —
 —
 —
Haynesville Shale 7,255
 4.1% 97.1% 167
 325
 —
Granite Wash 5,031
 0.8% 100.0% 16
 5
  <1
Barnett Shale 4,164
 2.7% 86.9% 1
 —
 2
Fayetteville Shale 3,918
 0.1%  100.0%
 13
 —
 —
Bossier Shale 1,816
 2.8% 54.1% 11
 53
 —
Canyon Lime —
  –
  –
 —
 —
 —
Marcellus Shale —
  –
  –
 —
 —
 —

1 The plays above have been delineated based on information from the EIA, the USGS, or state agencies, or according to areas of the most active 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 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:
8

      Average Daily Production (Boe/d)
  As of December 31, 2016 For the Year Ended December 31,
Resource Play1
 Acres 
Average
Royalty
Interest2
 2016 2015 2014
Wolfcamp - Midland 125,817
 0.3% <1
 5
 3
Granite Wash 86,556
 1.2% 155
 115
 191
Eagle Ford Shale 48,920
 2.2% 95
 204
 96
Barnett Shale 36,155
 4.9% 109
 158
 163
Haynesville Shale 14,719
 4.4% 686
 1,111
 816
Marcellus Shale 13,356
 2.3% 37
 6
 —
Bakken Shale 13,210
 1.2% 34
 41
 27
Three Forks 12,530
 1.2% 21
 27
 18
Fayetteville Shale 11,708
 4.1% —
 —
 —
Bossier Shale 8,642
 4.7% 28
 57
 60
Wolfcamp - Delaware 4,643
 2.1% —
 —
 —
Tuscaloosa Marine Shale 689
 7.8% <1
 —
  <1
Canyon Lime —
  –
 —
 —
 —
 Mineral and Royalty InterestsWorking Interests
Gross Well Count as of December 31, 20191
Average Daily Production (Boe/d) for the Year Ended December 31,Average Daily Production (Boe/d) for the Year Ended December 31,
Resource Play
MRI Wells2
WI Wells  201920182017201920182017
Bakken/
Three Forks		3,693  509  4,150  5,007  2,769  541  693  812  
Haynesville/Bossier1,084  100  15,091  10,273  5,943  9,364  10,657  10,972  
Permian-Midland1,895  2  2,621  1,792  717  —  1  —  
Permian-Delaware527  26  2,932  2,207  791  52  65  157  
Eagle Ford874  25  1,631  1,920  1,768  12  12  16  

1 The plays above have been delineated based on information from the EIA, the USGS, or state agencies, or according to areasWe own both mineral and royalty interests and working interests in 844 of the most active industry development.wells shown in each column above.
2 AverageRefers to mineral and 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.
      Average Daily Production (Boe/d)
  As of December 31, 2016 For the Year Ended December 31,
Resource Play1
 
Gross Acres2
 
Net Acres2
 2016 2015 2014
Haynesville Shale 183,337
 53,546
 5,077
 2,909
 3,136
Bossier Shale 170,716
 52,130
 309
 135
 199
Three Forks 50,361
 6,732
 491
 551
 491
Bakken Shale 50,159
 7,105
 864
 792
 855
Barnett Shale 13,417
 7,747
 87
 104
 124
Granite Wash 4,840
 1,254
 429
 537
 647
Wolfcamp - Delaware 2,642
 971
 150
 23
 33
Eagle Ford Shale 1,147
 87
 76
 11
 —
Wolfcamp - Midland 160
 4
 1
 —
 1
Canyon Lime —
 —
 —
 —
 —
Fayetteville Shale —
 —
 23
 —
 —
Marcellus Shale —
 —
 <1
 —
 —
Tuscaloosa Marine Shale —
 —
 —
 —
 —

1 The plays above have been delineated based on information from the EIA, the USGS, or state agencies, or according to areas of the most active industry development.
2 Excludes acreage that is not quantifiable due to incomplete seller records.

wells.
Estimated Proved Reserves
Evaluation and Review of Estimated Proved Reserves
The information included in this Annual Report on Form 10-K relating to our estimated proved oil and natural gas reserves is based upon a reserve report prepared by NSAI, a third-party petroleum engineering firm,estimates as of December 31, 2016.
2019, 2018, and 2017 shown herein have been independently evaluated by NSAI, providesa worldwide leader of petroleum property analysis services for energy clients,industry and financial organizations and government agencies. 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 reservereserves report incorporated herein is Mr. J. Carter Henson,Richard B. Talley, Jr. Mr. Henson,Talley, a Licensed Professional Engineer in the State of Texas (License No. 73964)102425), has been practicing consulting petroleum engineering at NSAI since 19892004 and has over 8five years of prior industry experience. He graduated from Ricethe University of Oklahoma in 19811998 with a Bachelor of Science Degree in Mechanical Engineering.Engineering and from Tulane University in 2001 with a Master of Business Administration Degree. As technical principal, Mr. HensonTalley 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, 20162019 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 former Senior Vice President, Engineering and Geology, iswas primarily responsible for overseeing the preparation of all of our reserve estimates. Mr. Morris is a petroleum engineer with approximately 3134 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, and royalty interests in the reserves database against our well ownership system;
9

•Review of historical realized commodity prices and differentials from index prices compared to the differentials used in the reserves database;
•Evaluation of capital cost assumptions derived from Authority for Expenditure ("AFE") estimates received;
•Review of actual historical production volumes compared to projections in the reserve report;
•Discussion of material reserve variances among our internal reservoir engineers and our Senior Vice President, Engineering and Geology; and
•Review of preliminary reserve estimates by our President and Chief Executive Officersenior management 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, 20162019, 2018, and 2017 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 toTo establish reasonable certainty with respect to our estimated net proved reserves, NSAI employed technologies including, but not limited to, electrical logs, radioactivitywell 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 and royalty interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses, and quantities of recoverable oil and natural gas may vary substantially from these estimates.
10

The following table presents our estimated proved oil and natural gas reserves:
As of December 31,
 
20191
20182
20173
 (Unaudited)
Estimated proved developed reserves4:
   
Oil (MBbls)17,050  17,567  17,891  
Natural gas (MMcf)263,371  278,233  233,017  
Total (MBoe)60,945  63,939  56,727  
Estimated proved undeveloped reserves5:
 
Oil (MBbls)—  —  8  
Natural gas (MMcf)45,587  35,787  67,257  
Total (MBoe)7,598  5,965  11,218  
Estimated proved reserves: 
Oil (MBbls)17,050  17,567  17,899  
Natural gas (MMcf)308,958  314,020  300,274  
Total (MBoe)68,543  69,904  67,945  
Percent proved developed88.9 %91.5 %83.5 %
 
As of
December 31, 20161
As of
December 31, 2015
 (Unaudited)(Unaudited)
Estimated proved developed reserves2:
  
Oil (MBbls)18,150
15,497
Natural gas (MMcf)223,057
174,555
Total (MBoe)55,327
44,590
Estimated proved undeveloped reserves3:
  
Oil (MBbls)218
345
Natural gas (MMcf)47,282
29,120
Total (MBoe)8,098
5,198
Estimated proved reserves:  
Oil (MBbls)18,368
15,842
Natural gas (MMcf)270,339
203,675
Total (MBoe)63,425
49,788
Percent proved developed87.2%89.6%

1 Estimates of reserves as of December 31, 20162019 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 2019. For oil volumes, the average WTI spot oil price of $55.85 per barrel is used for estimates of reserves for all the properties as of December 31, 2019. This average price is adjusted for quality, transportation fees, and market differentials.  For natural gas volumes, the average Henry Hub price of $2.58 per MMBTU is used for estimates of reserves for all the properties as of December 31, 2019. 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 $52.15 per barrel for oil and $2.36 per Mcf for natural gas.
2 Estimates of reserves as of December 31, 2018 were prepared using oil and natural gas prices equal to the unweighted arithmetic average of the first-day-of-the-month market price for each month in the period January through December 2016.2018. For oil volumes, the average WTI spot oil price of $42.75$65.56 per barrel is used for estimates of reserves for all the properties as of December 31, 2016.2018. These average prices are adjusted for quality, transportation fees, and market differentials.  For natural gas volumes, the average Henry Hub price of $2.48$3.10 per MMBTU is used for estimates of reserves for all the properties as of December 31, 2016.2018. 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$62.81 per barrel for oil and $2.14$2.98 per Mcf for natural gas. Reserve estimates do not include any value for probable or possible
3 Estimates of 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 quantitiesas of recoverableDecember 31, 2017 were prepared using oil and natural gas may vary substantially from these estimates.
2 Proved developedprices equal to the unweighted arithmetic average of the first-day-of-the-month market price for each month in the period January through December 2017. For oil volumes, the average WTI spot oil price of $51.34 per barrel is used for estimates of reserves of 74 MBoefor all the properties as of December 31, 20162017. These average prices are 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. 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 $46.59 per barrel for oil and $2.70 per Mcf for natural gas.
4 As of December 31, 2019 and 2018, no proved developed reserves were attributable to noncontrolling interests in our consolidated subsidiaries. Proved developed reserves of 61 MBoe were attributable to noncontrolling interests in our consolidated subsidiaries as of December 31, 2017.
35 As of December 31, 2016,2019, 2018, and 2017, no proved undeveloped reserves were attributable to noncontrolling interests in our consolidated subsidiaries.
11

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, 2016,2019, which areis included as exhibitsan exhibit to this Annual Report.

Estimated Proved Undeveloped Reserves
As of December 31, 2016,2019, our PUDs comprised 218 MBbls of oil and 47,28245,587 MMcf of natural gas, for a total of 8,0987,598 MBoe. PUDs will be converted from undeveloped to developed as the applicable wells begin production.
The following tablestable summarizes our changes in PUDs during the year ended December 31, 20162019 (in MBoe):
Estimated Proved Undeveloped Reserves
(Unaudited)
Balance asAs of December 31, 201520185,1985,965 
Acquisitions of reserves—
Divestiture of reserves— 
Extensions and discoveries7,4033,366 
Revisions of previous estimates548(548)
Transfers to estimated proved developed(5,051(1,185))
Balance asAs of December 31, 201620198,0987,598 
There were no PUD reserves acquired during the year ended December 31, 2016. New PUD reserves totaling 7,4033,366 MBoe were added during the year ended December 31, 2016,2019, resulting primarily from development activities in the Haynesville/Bossier and Bakken plays, and proposals for new wells from our operators in those plays.play. In 2019 we did not acquire or divest any PUD reserves.
During the year ended December 31, 2016,2019, we had reductions of 69 Mboe related to wells removed from548 MBoe of PUD statusreserves, primarily as a result of stale permits or updated operator information. This was offset by increases in previous estimatesthe plugging and abandonment of 617 Mboe based on performance from offsetone well due to mechanical issues and analog production. This resulted in a total upward revisionconverted the remaining 1,185 MBoe of 548 Mboe comprisedPUD reserves to PDP reserves.
During the year ended December 31, 2019, no costs were incurred, net of an increase of 3,507 MMcf natural gas reserves and a decrease of 36 Mbbl of oil reserves.
Costs incurredfarmout reimbursements, relating to the development of locations that were classified as PUDs atas of December 31, 2015 were $28.9 million during the year ended December 31, 2016.2018. Additionally, during the year ended December 31, 2016,2019, we incurred $42.9$3.3 million, net of farmout reimbursements, drilling, completing, and completingrecompleting other wells whichthat were not classified as PUDs as of December 31, 2015. Estimated2018. There are no estimated future development costs during the year ended December 31, 2017 relating toprojected for the development of PUD reserves atas of December 31, 2016 are projected to be approximately $35.9 million.2019. All of our PUD drilling locations as of December 31, 20162019 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, 2016.AFE. As of December 31, 2016,2019, our PUD reserves consisted of 11 wells waiting on completion, 6 wells in various stages of completion, and 3 wells in various stages of drilling. As of December 31, 2019, approximately 12.8%11% of our total proved reserves were classified as PUDs.


12

Oil and Natural Gas Production Prices and Production Costs
Production and Price History
For the year ended December 31, 2016, 31.7%2019, 27% of our production and 53.7%57% of our oil and natural gas revenues were related to oil and condensate production and sales.sales, respectively. During the same period, natural gas and natural gas liquidsNGL sales were 68.3%73% of our production and 46.3%43% 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,
 201920182017
Production:   
Oil and condensate (MBbls)4,777  4,962  3,552  
Natural gas (MMcf)1
77,635  71,622  59,779  
Total (MBoe)17,716  16,899  13,515  
Average daily production (MBoe/d)48.5  46.3  37.0  
Realized Prices without Derivatives:   
Oil and condensate (per Bbl)$55.20  $62.53  $47.78  
Natural gas and natural gas liquids sales (per Mcf)1
$2.57  $3.47  $3.19  
Unit Cost per Boe:  
Production costs and ad valorem taxes$3.42  $3.81  $3.51  
  Year Ended December 31,
  2016 2015 2014
Production:  
  
  
Oil and condensate (MBbls)1
 3,680
 3,565
 3,005
Natural gas (MMcf)1
 47,498
 41,389
 42,273
Total (MBoe) 11,596
 10,463
 10,051
Average daily production (MBoe/d) 31.7
 28.7
 27.5
Realized Prices2:
  
  
  
Oil and condensate (per Bbl) $38.69
 $45.87
 $85.65
Natural gas and natural gas liquids (per Mcf)1
 $2.59
 $2.80
 $4.91
Unit Cost per Boe:  
  
  
Production costs and ad valorem taxes $3.06
 $3.42
 $4.93

1 As a mineral-and-royaltymineral and royalty interest owner, we are often provided insufficient and inconsistent data by our operators related to NGLs.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. As such, theAccordingly, 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 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.gas.
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, 2016, we owned
The following table sets forth information about our mineral and royalty interests or working interests in 55,260 productive wells, which consisted of 34,645 oil wells and 20,615 natural gas wells. As of December 31, 2016, we owned mineral and royalty interests in 49,942 productive wells, which consisted of 33,799 oil wells and 16,143 natural gas wells,interest and working interests in 8,577 gross productive wells and 328 net productive wells, which consisted of 2,981 gross (58 net) productive oil wells and 5,596 gross (270 net) productive natural gas wells. interest wells:
 
Productive Wells as of December 31, 20191
 Mineral and Royalty InterestsWorking Interests
Well TypeGross  Gross  Net  
Oil47,814  3,692  66  
Natural Gas21,231  6,025  282  
Total69,045  9,717  348  
1 We own both mineral and royalty interests and working interests in 3,259 of these4,199 gross wells.







13




Acreage
Mineral and Royalty Interests
The following table sets forth information relating to our acreage for our mineral and royalty interests as of December 31, 2016:2019:
BSM Land Region
Developed Acreage1
Undeveloped Acreage1
Total Acreage1
Gulf Coast670,614  8,047,662  8,718,276  
Southwestern U.S.875,580  3,098,231  3,973,811  
Rocky Mountains727,395  2,551,575  3,278,970  
Eastern U.S.82,272  1,651,489  1,733,761  
Mid-Continent553,635  1,058,350  1,611,985  
Western U.S.18,845  1,040,017  1,058,862  
Total2,928,341  17,447,324  20,375,665  
State Developed Acreage Undeveloped Acreage Total Acreage
Texas 345,935
 3,942,268
 4,288,203
Mississippi 4,816
 2,389,431
 2,394,247
Alabama 2,699
 2,045,661
 2,048,360
Arkansas 4,767
 1,264,324
 1,269,091
North Dakota 16,041
 994,028
 1,010,069
Nevada —
 792,428
 792,428
Florida —
 744,341
 744,341
Louisiana 35,354
 518,604
 553,958
Montana 20,765
 479,028
 499,793
Oklahoma 117,952
 367,857
 485,809
Other 81,557
 1,348,069
 1,429,626
Total 629,886
 14,886,039
 15,515,925
The following table sets forth information relating1 Includes acreage for mineral interests, NPRIs, and ORRIs. We may own more than one type of interest in the same tract of land. For example, where we have acquired non-operated working interests related to our mineral interests in a given tract, our working interest acreage in that tract will relate to the same acres as our mineral interest acreage in that tract. Consequently, some of the acreage shown for one type of interest may also be included in the acreage shown for another type of interest. Because of our NPRIs asnon-operated working interests, overlap between working interest acreage and mineral and royalty interest acreage can be significant; overlap between the different types of December 31, 2016:
State Developed Acreage Undeveloped Acreage Total Acreage
Texas 203,655
 818,363
 1,022,018
Montana 11,684
 169,409
 181,093
Mississippi 10,506
 62,798
 73,304
Louisiana 10,508
 62,203
 72,711
North Dakota 18,540
 18,616
 37,156
Arkansas 3,974
 29,070
 33,044
Wyoming 1,360
 17,160
 18,520
New Mexico 14,289
 960
 15,249
Oklahoma 6,976
 5,749
 12,725
Kansas 9,042
 2,983
 12,025
Other 367
 3,041
 3,408
Total 290,901
 1,190,352
 1,481,253













The following table sets forth information relating to our acreage for our ORRIs as of December 31, 2016:
State Developed Acreage Undeveloped Acreage Total Acreage
Montana 295,401
 165,496
 460,897
Texas 292,352
 57,002
 349,354
Wyoming 133,702
 40,045
 173,747
Oklahoma 157,339
 2,006
 159,345
Utah 40,510
 26,163
 66,673
New Mexico 46,151
 13,868
 60,019
Michigan 55,272
 1,239
 56,511
Colorado 27,108
 9,899
 37,007
Louisiana 15,264
 17,886
 33,150
Alaska 7,664
 12,375
 20,039
Other 74,448
 14,641
 89,089
Total 1,145,211
 360,620
 1,505,831
mineral and royalty interests is not significant.
Working Interests
The following table sets forth information relating to our acreage for our non-operated working interests as of December 31, 2016:2019:
 
Developed Acreage1
Undeveloped Acreage1
Total Acreage1
BSM Land RegionGrossNetGrossNetGrossNet
Gulf Coast241,305  38,423  263,040  55,530  504,345  93,953  
Southwestern U.S.16,030  11,693  44,649  5,917  60,679  17,610  
Rocky Mountains83,120  15,009  12,468  1,280  95,588  16,289  
Eastern U.S.13,408  1,346  79  —  13,487  1,346  
Mid-Continent39,316  23,711  986  20  40,302  23,731  
Western U.S.—  —  —  —  —  —  
Total393,179  90,182  321,222  62,747  714,401  152,929  
1 We may own more than one type of interest in the same tract of land. For example, where we have acquired non-operated working interests related to our mineral interests in a given tract, our working interest acreage in that tract will relate to the same acres as our mineral interest acreage in that tract. Consequently, some of the acreage shown for one type of interest may also be included in the acreage shown for another type of interest. Because of our non-operated working interests, overlap between working interest acreage and mineral and royalty interest acreage can be significant; overlap between the different types of mineral and royalty interests is not significant.




14
  Developed Acreage Undeveloped Acreage Total Acreage
State Gross Net Gross Net Gross Net
Texas 196,818
 53,438
 148,661
 44,391
 345,479
 97,829
North Dakota 43,369
 6,381
 7,564
 763
 50,933
 7,144
Louisiana 31,608
 4,114
 14,408
 1,436
 46,016
 5,550
Wyoming 22,290
 4,168
 6,358
 1,596
 28,648
 5,764
Michigan 13,208
 1,330
 79
 —
 13,287
 1,330
Oklahoma 11,703
 3,070
 10
 3
 11,713
 3,073
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 6,536
 2,146
 1,494
 361
 8,030
 2,507
Total 348,135
 87,587
 180,535
 48,685
 528,670
 136,272

The following table lists the net undeveloped acres, the net acres expiring in the years ending December 31, 2017, 2018,2020, 2021, and 2019,2022, and, where applicable, the net acres expiring that are subject to extension options:
  2017 Expirations 2018 Expirations 2019 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.
48,685
 17,204
 151
 12,491
 —
 1,652
 281




 2020 Expirations2021 Expirations2022 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.
62,747  3,698  1,277  4,191  549  976  395  
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.indicated, excluding wells subject to our farmout agreements. 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.
 For the Year Ended December 31, Year Ended December 31,
 2016 2015 2014 201920182017
Gross development wells:  
  
  
Gross development wells:   
Productive 47.0
 74.0
 222.0
Productive—  6.0  23.0  
Dry —
 1.0
 1.0
Dry—  —  —  
Total 47.0
 75.0
 223.0
Total—  6.0  23.0  
Net development wells:  
  
  
Net development wells:   
Productive 4.7
 2.9
 7.3
Productive—  2.5  6.1  
Dry —
 <0.1
 —
Dry—  —  —  
Total 4.7
 2.9
 7.3
Total—  2.5  6.1  
Gross exploratory wells:  
  
  
Gross exploratory wells:   
Productive —
 —
 1.0
Productive1.0  —  —  
Dry —
 —
 1.0
Dry—  1.0  —  
Total —
 —
 2.0
Total1.0  1.0  —  
Net exploratory wells:  
  
  
Net exploratory wells:   
Productive —
 —
 <0.1
Productive0.3  —  —  
Dry —
 —
 —
Dry—  1.0  —  
Total —
 —
 <0.1
Total0.3  1.0  —  
As of December 31, 2016,2019, we had 20no wells in the process of drilling, completing or dewatering, or shut in awaiting infrastructure that are not reflected in the above table.

infrastructure.

15

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-interestworking 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. ChangesThe long-term trend in environmental laws andregulation has been towards more stringent regulations, occur frequently, and any changes that impact our operators and result in more stringent and costly pollution control or waste handling, storage, transport, disposal, or cleanup requirements could materially adversely affect our business and prospects. Below is a summary of environmental laws applicable to operations on our operators.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. 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-interestworking 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-interestworking 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.


16

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 SeptemberJune 2015, newthe EPA and the U.S. Army Corps of Engineers rules defining(the “Corps”) published a final rule attempting to clarify the federal jurisdictional reach over waters of the United States ("WOTUS"). Following the change in U.S. Presidential Administrations, there have been several attempts to modify or eliminate this rule. Most recently, on January 23, 2020, the EPA and Corps replaced the WOTUS rule adopted in 2015 with the narrower Navigable Waters Protection Rule, and litigation is expected. Therefore, the scope of jurisdiction under the EPA’sCWA is uncertain at this time, and the Corps’ jurisdiction became effective. To the extent the rule expands theany increase in scope of the CWA’s jurisdiction, our operators could faceresult in increased costs andor delays with respect to obtaining permits for dredge and fillcertain activities in wetland areas. The rule has been challenged in court on the grounds that it unlawfully expands the reach of CWA programs, and implementation of the rule has been stayed pending resolution of the court challenge.for our operators. 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 issued 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 operations. Moreover, the operations of oil and natural gas production facilities. The EPA has asserted regulatory authority pursuant to the SDWA's Underground Injection Control ("UIC") program over hydraulic fracturing activities involving the use of diesel fuel in fracturing fluids and issued guidance covering such activities. The SDWA also regulates saltwater disposal wells under the Underground Injection ControlUIC 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.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 ("CAA") 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.standards, and the agency completed attainment/non-attainment designations in July 2018. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit the ability of our operators to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. More recently,Separately, 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
17

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 responseThe threat of climate change continues to findings thatattract considerable attention in the United States and in foreign countries, numerous proposals have been made and could continue to be made at the international, national, regional, and state levels of government to monitor and limit existing emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”("GHGs") present an      endangermentas well as to public healthrestrict or eliminate such future emissions. As a result, our operations as well as the operations of our operators are subject to a series of regulatory, political, litigation, and financial risks associated with the environment,production and processing of fossil fuels and emission of GHGs.
In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, require preconstructionestablish construction and operating permitspermit reviews for GHG emissions from 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 requiringsources, require the monitoring and annual reporting of GHG emissions from specified onshore and offshore oilcertain petroleum and natural gas productionsystem sources in the United States, on an annual basis, which include gathering and boosting facilities as well as GHG emissions from completions and workoversimplement New Source Performance Standards directing the reduction 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 processesfacilities in the oil and natural gas source category, including production, processing, transmissionsector. Following the change in administration, there have been attempts to modify these regulations, and storage activities. The Bureaulitigation is ongoing.
Additionally, various states and groups of Land Management (“BLM”) finalized similar rules in November 2016states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that seek to limit methane emissions from oil and natural gas developmentare focused on federal and tribal lands through limitations on venting and flaring activities. However, both the U.S. House of Representatives and the Senate have introduced resolutions seeking to repeal the BLM methane rules under the Congressional Review Act and future implementation of the BLM methane rules is uncertain. In any event, the BLM and the EPA 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 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 regionalareas GHG cap and trade programs, have emerged. Thesecarbon taxes, reporting and tracking programs, typically require major sourcesand restriction of emissions. At the international level, there is an agreement, the United Nations-sponsored "Paris Agreement," for nations to limit their GHG emissions to acquirethrough non-binding, individually determined reduction goals every five years after 2020, although the United States has announced its withdrawal from such agreement, effective November 4, 2020.
Governmental, scientific, and surrender emission allowances in return for emitting those GHGs. Although it is not possible at this predict how legislation or new regulations that may be adopted to addresspublic concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate-change-related pledges made by some candidates seeking the office of the President of the United States in 2020. These declarations have included plans to ban hydraulic fracturing, which would impactadversely affect production on our business,properties. Litigation risks are also increasing as a number of cities and other local governments have sought to bring suit against the largest oil and natural gas exploration and production companies in state or federal court, alleging among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages as a result.
There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel energy companies may elect in the future lawsto shift some or all of their investments into non-energy related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. Limitation of investments in and financing for fossil fuel energy companies could result in the restriction, delay, or cancellation of drilling programs or development or production activities.
The adoption and implementation of new or more stringent international, federal or state legislation, 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 onother regulatory initiatives that impose more stringent standards for GHG emissions could adversely affect demand forfrom the oil and natural gas produced from our properties and lowersector or otherwise restrict the value of our reserves. Restrictions on emissions of methane or carbon dioxide thatareas in which this sector may be imposed in various states, as well as state and local climate change initiatives, could adversely affect theproduce oil and natural gas industry, and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressinggenerate the GHG emissions would impactcould result in increased costs of compliance or costs of consuming, and thereby reduce demand for oil and natural gas, which could reduce the profitability of our business. Finally, it should be noted that some scientists have concluded that increasing concentrationsinterests. Additionally, political, litigation, and financial risks may result in our oil and natural gas operators restricting or cancelling production activities, incurring liability for infrastructure damages as a result of GHGsclimatic changes, or impairing their ability to continue to operate in an economic manner, which also could reduce the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severityprofitability of storms, floods, droughts, and other extreme climatic events; if anyour interests. One or more of these effects were to occur, theydevelopments could have a material adverse effect on our properties and operations.business, financial condition, or results of operation.

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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; proposedeffluent limitation guidelines in April 2015 toJune 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 seeking comment on its intent to develop regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. Also, the BLM finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and tribal lands including, for example, notice to and pre approval by BLM of the proposed hydraulic fracturing activities; development and pre approval by BLM of a plan for managing and containing flowback fluids and produced water recovered during the hydraulic fracturing process; implementation of measures designed to protect usable water from hydraulic fracturing activities; and public disclosure of the chemicals used in the hydraulic fracturing fluid. The U.S. District Court of Wyoming has temporarily stayed implementation of this rule. A final decision has not yet been issued.plants.
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.under certain limited circumstances. 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 or are considering adopting 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. Similarly, Oklahoma has imposed strict limits on the operation of disposal wells in areas with increased instances of induced seismic events. 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. For example, in April 2019, Colorado adopted legislation that requires the Colorado Oil and Gas Conservation Commission ("COGCC") to prioritize public health and environmental concerns in its decisions and delegates considerable new authority to local governments to regulate surface impacts. Some local communities have adopted additional restrictions for oil and gas activities, such as requiring greater setbacks, and other groups have sought a cessation of permit issuances entirely until the COGCC publishes new rules in keeping with the legislation. Additionally, activist groups have submitted new ballot proposals for the 2020 election year, including proposals for increased drilling setbacks and increased bonding requirements. We cannot predict what additional state or local requirements may be imposed in the future on oil and gas operations in the states in which we own interests. In the event state, local, or municipal 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.

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Occupational Safety and Health Act
The OSHAOccupational 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. ThisFor example, recently, there have been renewed calls to review protections currently in place for the Dunes Sagebrush Lizard, whose habitat includes portions of the Permian Basin, and to reconsider listing the species under the ESA. Likewise, there have been calls to review protections in place for the Greater Sage Grouse, which can be found across a large swath of the northwestern United States in oil and gas producing states. The listing of either of these species, or any others, in areas where we hold interests 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.
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Marketing and Major Customers
If we were to lose a significant customer, such loss could impact revenue derived from our mineral-and-royalty-interestmineral and royalty interest or working-interestworking 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 oil and natural gas revenues for the periods indicated:
 
  For the Year Ended December 31,
  2016 2015 2014
Exxon Mobil 11.0% * *
Chesapeake Energy Corporation * * 10.0%
*Accounted for less than 10% of total revenues for the period indicated.



 Year Ended December 31,
 201920182017
XTO Energy18%  15%  21%  
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 (the "Board") 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, 2016,2019, Black Stone Management had 108115 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.
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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 distributiondistributions on our common and subordinated units. If we make distributions, the holders of our Series B cumulative convertible preferred unitholdersunits 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 distributiondistributions to our common and subordinated unitholders. Our Series B cumulative convertible preferred unitholders have priority with respect to rights to share in distributions over our common and subordinated unitholders.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.Board.
The amount of cash we haveare able 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 haveare able 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 a returndistribution of capitalour assets and the value of our common units willcould be adversely affected, which will eventually cause our cash distributions per unit to decrease.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—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 willmay 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;imports and exports of oil and natural gas;
•political and economic conditions in oil producing regions, including the Middle East, Africa, South America, and Russia;
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•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. For example, duringThe table below demonstrates such volatility for the five years prior to December 31, 2016, the spot priceperiods presented.
Year Ended December 31, 2019During the Five Years Prior to 2020As of December 31,
HighLow
High2
Low3
201920182017
WTI spot crude oil ($/Bbl)1
$66.24  $46.31  $77.41  $26.19  $61.14  $45.15  $60.46  
Henry Hub spot natural gas ($/MMBtu)1
4.25  1.75  6.24  1.49  2.09  3.25  3.69  
1  Source: EIA
2  High prices for West Texas Intermediate light sweet crude oil, which we refer to as WTI has ranged from a high of $110.62 per Bbl in 2013 to a low of $26.19 per Bbl in 2016. During the same period, theand Henry Hub spot market price of natural gas has ranged from a low of $1.49were in 2016 to a high of $8.15 per MMBtu in 2014. During 2016, the2018
3  Low prices for WTI spot price of oil ranged from $26.19 to $54.01 per Bbl and the Henry Hub spot market price of natural gas ranged from $1.49 to $3.80 per MMBtu. On December 31, 2014, the WTI spot price for oil was $53.45 per Bbl and the Henry Hub spot market price of natural gas was $3.14 per MMBtu. On December 31, 2015, the WTI spot price for oil was $37.13 per Bbl and the Henry Hub spot market price of natural gas was $2.28 per MMBtu. On December 31,were in 2016 the WTI spot price for oil was $53.75 per Bbl, and the Henry Hub spot market price of natural gas was $3.71 per MMBtu.

Any prolonged substantial decline in the price of oil and natural gas will likely have a material adverse effect on our financial condition, results 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.  
OilBased on the EIA forecasts for 2020 and 2021, oil prices have declined substantially fromare expected to trade in a lower range compared to recent historical highs and may remain depressed for the foreseeable future.highs. Approximately 53.7%57% of our 20162019 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 distributiondistributions 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 $53.75$61.14 per Bbl on December 31, 2016.2019. 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 continue to remainare depressed for lengthy periods,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 oil will continue tomay negatively impact the value of our estimated proved reserves
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and the amount that we are allowed to borrow under our bank credit facilityCredit Facility (defined below) 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.
NaturalBased on the EIA forecasts for 2020 and 2021, natural gas prices have declined substantially from historical highs and are expected to remain depressed for the foreseeable future.trade in a range lower than historical highs. Approximately 68.3%43% of our 2016 total production was2019 oil and natural gas on a “Btu-equivalent” basis.revenues were derived from natural gas and natural gas liquids sales. Any additionalfuture 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 distributiondistributions on all of our outstanding common and subordinated units, perhaps materially.
During the nineten years prior to December 31, 2016,2019, natural gas prices at Henry Hub have ranged from a high of $13.31$8.15 per MMBtu in 20082014 to a low of $1.49 per MMBtu in 2016. On December 31, 2016,2019, the Henry Hub spot market price of natural gas was $3.71$2.09 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 in 2020, 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 continue to remainare depressed for lengthy periods,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 will continue tomay negatively impact the value of our estimated proved reserves and the amount that we are allowed to borrow under our bank credit facilityCredit 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.
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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, 2016,2019, 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.
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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.
Cessation or protracted slowdown of activity in the Shelby Trough area could adversely affect our results of operations.
In 2019, we generated 14% of our royalty revenues and 58% of our working interest revenues from two operators in the Shelby Trough area of the Haynesville play in East Texas, where we own a concentrated, relatively high-interest royalty position. These operators have recently decided to limit their Shelby Trough drilling activity, and one of the operators has released acreage in the area. Geographic and operator concentration heightens the effect of operational risks, including:
•operators’ diversion of drilling capital to other areas, where our royalty interest is less meaningful or nonexistent;
•adverse changes to the operators’ financial positions;
•unanticipated geographic or environmental constraints in the Shelby Trough; or
•delay or cancellation of construction or operation of LNG export facilities in the Gulf of Mexico.
If drilling activity in this area does not resume at the previous rate, production may decrease, reducing cash generated from operations and, without offsetting cost reductions, cash available for distribution.
We may experience delays in the payment of royalties and be unable to replace operators that do not make required royalty payments, and we may 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,non-operated working interests, 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 have made and may make and expect to continue to makein the future substantial capital expenditures in connection with the acquisition of mineral and royalty interests and, to a lesser extent, participation in our working-interest participation program.non-operated working interests. To date, we have financed capital expenditures primarily with funding from cash generated by operations, limited borrowings under our credit facility,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.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.
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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.
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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, 20162019, 2018, and 2017 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, 20162019, 2018, and 2017 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 yearyears ended December 31, 20162019, 2018, and 2017, 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.
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Conservation measures, and 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.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. On February 24, 2020, Holbrook F. Dorn, Senior Vice President, Business Development, and Brock Morris, Senior Vice President, Engineering and Geology, departed from their positions, and we implemented a broad workforce reduction. If we are unable to manage an orderly transition, our business may be adversely affected.
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
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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 continuallygenerally imposed increasingly strict requirements forrelated to water use and disposal, air pollution control, and solid waste management.
Laws and regulations governing exploration and production may also affect production levels. Our operators must comply with federal and state 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—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 particularly natural gas, 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 Safe Drinking Water Act (“SDWA”)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 U.S. Environmental Protection Agency (“EPA”),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 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 ruleseffluent limitation guidelines in June 2016 to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants; and issuedplants.
Additionally, in May 2015 an Advanced Notice of Proposed Rulemaking seeking comment on its intent to develop regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. Also, the Bureau of Land Management (“BLM”) finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and tribal lands including, for example, notice to and by BLM of the proposed hydraulic fracturing activities; development and    by BLM of a plan for managing and containing flowback fluids and produced water recovered during the hydraulic fracturing process; implementation of measures designed to protect usable water from hydraulic fracturing activities; and public disclosure of the chemicals used in the hydraulic fracturing fluid. The U.S. District Court of Wyoming has temporarily stayed implementation of this rule. A final decision has not yet been issued.
In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final 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.under certain limited circumstances. The EPA has not proposed to take any action in response
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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, including Colorado, North Dakota, Louisiana, Oklahoma, and Texas, have adopted or are considering adopting 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”)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. Similarly, Oklahoma has imposed strict limits on the operation of disposal wells in areas with increased instances of induced seismic events. 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. For example, in April 2019, Colorado adopted legislation that requires the COGCC to prioritize public health and environmental concerns in its decisions and delegates considerable new authority to local governments to regulate surface impacts. Some local communities have adopted additional restrictions for oil and gas activities, such as requiring greater setbacks, and other groups have sought a cessation of permit issuances entirely until the COGCC publishes new rules in keeping with the legislation. Additionally, activist groups have submitted new ballot proposals for the 2020 election year, including proposals for increased drilling setbacks and increased bonding requirements. We cannot predict what additional state or local requirements may be imposed in the future on oil and gas operations in the states in which we own interests. In the event state, local, or municipal 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.
Our credit facilityCredit Facility has substantial restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions.
Our credit facilityCredit 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 further 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, declinesdecreases in reserves, lending requirements, or regulations or certain other circumstances. As of December 31, 2016,2019, we had outstanding borrowings of $316.0$394.0 million and the aggregate maximum credit amounts of the lenders were $1.0 billion. Our borrowing base determined by the lenders under our credit facilityCredit Facility in October 20162019 is $500.0$650.0 million and the next semi-annual redetermination is scheduled for April 2017.2020. 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,Credit Facility, or sell assets, debt, or common units.equity. 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,Credit Facility, which could materially adversely affect our business, financial condition, results of operations, and distributions to our unitholders.
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The operating and financial restrictions and covenants in our credit facilityCredit Facility restrict, and any future financing agreements likely will restrict, our ability to finance future operations or capital needs, engage in, expand, or pursue our business activities, or pay distributions. Our credit facilityCredit Facility restricts, and any future credit facilityCredit 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 facilityCredit 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 facilityCredit Facility and our outstanding borrowings are not in excess of our borrowing base. While we currently are not restricted by our credit facilityCredit 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.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,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 facilityCredit Facility are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our credit facility,Credit Facility, the lenders can seek to foreclose on our assets.
The adoptionOn July 27, 2017, the U.K. Financial Conduct Authority announced that it intends to stop persuading or compelling banks to submit LIBOR rates after 2021. Our Credit Facility includes provisions to determine a replacement rate for LIBOR if necessary during its term, which require that we and our lenders agree upon a replacement rate based on the then-prevailing market convention for similar agreements. We currently do not expect the transition from LIBOR to have a material impact on us. However, if clear market standards and replacement methodologies have not developed as of the time LIBOR becomes unavailable, we may have difficulty reaching agreement on acceptable replacement rates under our Credit Facility. In the event that we do not reach agreement on an acceptable replacement rate for LIBOR, outstanding borrowings under the Credit Facility would revert to a floating rate equal to the alternative base rate (which, as of the time that LIBOR becomes unavailable, is equal to the greater of the Prime Rate and the Federal Funds effective rate plus 0.50%) plus the applicable margin for the alternative base rate which ranges between 0.75% and 1.75%. If we are unable to negotiate replacement rates on favorable terms, it could have a material adverse effect on our financial condition, results of operations, and cash distributions to unitholders. Please read “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Credit Facility” for a description of the interest rate on outstanding borrowings under our Credit Facility.
A series of risks arising out of the threat of climate change legislation by Congress could result in increased operating costs, and reduced demand forlimit the areas in which oil and natural gas production may occur, and reduce demand for the products that our operators produce.
In responseThe threat of climate change continues to findings thatattract considerable attention in the United States and in foreign countries, numerous proposals have been made and could continue to be made at the international, national, regional, and state levels of government to monitor and limit existing emissions of carbon dioxide, methane,GHGs as well as to restrict or eliminate such future emissions. As a result, our operations as well as the operations of our operators are subject to a series of regulatory, political, litigation, and other greenhouse gases (“GHGs”) present an      endangerment to public healthfinancial risks associated with the production and processing of fossil fuels and emission of GHGs.
In the environment,United States, no comprehensive climate change legislation has been implemented at the federal level. However, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, require preconstructionestablish construction and operating permitspermit reviews for GHG emissions from 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 requiringsources, require the monitoring and annual reporting of GHG emissions from specified onshore and offshore oilcertain petroleum and natural gas productionsystem sources in the United States, on an annual basis, which include gathering and boosting facilities as well as GHG emissions from completions and workoversimplement New Source Performance Standards directing the reduction 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 processesfacilities in the oil and natural gas source category, including production, processing, transmission,sector. Following the change in administration, there have been attempts to modify these regulations, and storage activities. The BLM finalized similar rules in November 2016litigation is ongoing.
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Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that seekare focused on such areas GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, there is an agreement, the United Nations-sponsored "Paris Agreement," for nations to limit methanetheir GHG emissions through non-binding, individually determined reduction goals every five years after 2020, although the United States has announced its withdrawal from such agreement, effective November 4, 2020.
Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate-change-related pledges made by some candidates seeking the office of the President of the United States in 2020. These declarations have included plans to ban hydraulic fracturing, which would adversely affect production on our properties. Litigation risks are also increasing as a number of cities and other local governments have sought to bring suit against the largest oil and natural gas development onexploration and production companies in state or federal court, alleging among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and tribal lands through limitations on ventingtherefore are responsible for roadway and flaring activities. However, bothinfrastructure damages as a result.
There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel energy companies may elect in the U.S. Housefuture to shift some or all of Representativestheir investments into non-energy related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and the Senate have introduced resolutions seekingsome of them may elect not to repeal the BLM methane rules under the Congressional Review Actprovide funding for fossil fuel energy companies. Limitation of investments in and future implementation of the BLM methane rules is uncertain. In any event, the BLM and the EPA methane rules have substantial similarities with respect to pollution control equipment and “LDAR” requirements. These rulesfinancing for fossil fuel energy companies could result in increased compliance coststhe restriction, delay or cancellation of drilling programs or development or production activities.
The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards 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 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 lowersector or otherwise restrict the value of our reserves. Restrictions on emissions of methane or carbon dioxide thatareas in which this sector may be imposed in various states, as well as state and local climate change initiatives, could adversely affect theproduce oil and natural gas industry, and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressinggenerate the GHG emissions would impactcould result in increased costs of compliance or costs of consuming, and thereby reduce demand for oil and natural gas, which could reduce the profitability of our business.interests. Additionally, political, litigation and financial risks may result in our oil and natural gas operators restricting or cancelling production activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing their ability to continue to operate in an economic manner, which also could reduce the profitability of our interests. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation. Finally, it should be noted that somemany 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.
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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 companyproviders 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 attacksVarious security risks, including cybersecurity threats, data breaches, and other disruptions, could significantly affect us.
Cyber
Various security risks, including cyber attacks on businesses, have escalated in recent years. WeAs one of the largest owners and managers of oil and natural gas mineral interests in the United States, we rely on electronic systems and networks to control and manage our business and have multiple layers of security to monitor, mitigate risksand manage these risks. However, these systems and networks, as well as our operators’ systems and networks and third-party infrastructure and operations, such as pipelines and transportation facilities, may be subject to sophisticated and deliberate security attacks and security breaches, which could lead to the corruption or loss of cyber attack.sensitive and valuable data, delays in production or delivery, difficulty in completing and settling transactions, challenges in maintaining our books and records, environmental damage, communication interruptions, material adverse effects on our reputation or financial position and other operational disruptions and third-party liabilities, including the cost of remedial actions. Cyber attacks and data breaches in particular are becoming more sophisticated and include, but are not limited to, malicious software, ransomware, attempts to gain unauthorized access to data, employee and third-party errors, and other electronic security breaches. If however, we or our operators were to experience an attack or a breach and our security measures failed, the potential consequences to our businesses and the communities in which we operate could be significant. In addition, our efforts to monitor, mitigate and manage these evolving risks may result in increased capital and operating costs, but there can be no assurance that such efforts will be sufficient to prevent attacks or breaches from occurring. 
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—Securities — Cash Distribution Policy.”
The board of directors of our general partnerBoard 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.all on our common units. If we make distributions, our preferredSeries 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 are paid each quarter as follows: (i) first, to the holders of Series B cumulative convertible preferred units in an amount of approximately $25.00equal to 7% per preferred unit,annum, subject to certain adjustments, and (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. The preferred units have a right to further participate (on an as-converted basis) in quarterly distributions in excess of the quarterly preferred distribution

amount under certain circumstances that we do not expect to occur. Even if those additional distributions do occur, considering that the outstanding preferred units are convertible into only a relatively small number of our total outstanding common and subordinated units, we believe these additional distributions payable under those circumstances would not materially adversely affect the per unit distribution rate we would otherwise pay on our common and subordinated units. Our minimum quarterly distribution is $1.15 per common and subordinated unit on an annualized basis (or $0.26875 per unit on a quarterly basis) for the four quarters ending March 31, 2017. The minimum quarterly distribution will be $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. 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 partnerBoard could elect not to pay distributions for one or more quarters or at all. Please read
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Part II, Item 5. “Market for Registrant’s Common Equity, Related Unitholder Matters, and Issuer Purchases of Equity Securities—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.Board. 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—Securities — Cash Distribution Policy—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, and persons who acquired such units with the prior approval of the boardBoard, holders of directorsSeries 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 general partner,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.unitholders.
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•borrowings and repayment of current and future indebtedness;
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•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 preferred units are outstanding, or at any time after the subordination period has ended.unitholders.
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 Series B cumulative convertible 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 Series B cumulative convertible 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, 2016,2019, we had 95,720,686205,959,790 common units and 95,164,204 subordinated14,711,219 Series B cumulative convertible preferred units outstanding. AllEach holder may elect to convert all or any portion of the subordinatedits Series B cumulative convertible preferred units could convert into common units on no more than a one-to-oneone-for-one basis, at the endsubject to customary anti-dilution adjustments, an adjustment for any distributions that have accrued but not been paid when due, and certain other restrictions. Under certain conditions, we may elect to convert all or any portion of the subordination period.Series B cumulative convertible preferred units into common units. As of December 31, 2019 and through the date of this filing, we had not met all such conditions and therefore were not eligible to exercise our conversion right for the Series B cumulative convertible preferred units. 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.
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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’, U.S. federal income tax status does not have or is not reasonably likely to have a material
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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 held 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 U.S. federal income tax purposes, as well as ourand not being subject to a material amount of entity-level taxation by individual states.taxation. If the Internal Revenue Service (“IRS”) were to treat us as a corporation for U.S. federal income tax purposes or we were to become subject to entity-level taxation for state tax purposes, then our cash distributions to common unitholders could be substantially reduced.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. 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 U.S. federal income tax purposes unless we satisfy athe “qualifying income” requirement.requirement within Section 7704(d)(1)(E) of the Internal Revenue Code. Based upon our current operations and current Treasury Regulations, we believe that 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 U.S. federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate. Distributions to our common unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, or deductions would flow through to our common unitholders. Because aan entity-level tax would be imposed upon us as a corporation, cash distributions to our common 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 common unitholders. Therefore, treatment of us as a corporation or the assessment of a material amount of entity-level taxation would result in a material reduction in the anticipated cash generated from our operations and after-tax return to theour common 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 U.S. 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 U.S. federal income tax laws that would affect publicly traded partnerships, including elimination of partnership tax treatment for publicly traded partnerships. Although thereFor example, the "Clean Energy for America Act," which is no current legislative proposal, a prior legislativesimilar to legislation that was commonly proposed during the Obama Administration, was introduced in the Senate on May 2, 2019. If enacted, this proposal would, have eliminatedamong other things, repeal the qualifying income exception towithin Section 7704(d)(1)(E) of the treatment of all publicly traded partnerships as corporationsInternal Revenue Code upon which we rely for our treatment as a partnership for U.S. 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 publishedTreasury Department has issued, and 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, therefuture may issue, regulations interpreting those laws that affect publicly traded partnerships. There can be no assurance that there will not be further changes to U.S. federal income tax laws or the Treasury Department's interpretation of the qualifying income rules in a manner that could impact our ability to qualify as a partnership in the future.
Any modification to the U.S. federal income tax laws or interpretations thereof 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 U.S. 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 legislative, regulatory or administrative developments and proposals and their potential effect on your investment in our common units.
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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; (iii) the elimination of the deduction for certain U.S. production activities; and (iv)(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 future tax reform legislation, to accompany lower U.S. 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 increase costs or eliminate or postpone certain tax deductions that currently are available to us or our services providers with respect to oil and gas development, or increase costs, and anydevelopment. 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 U.S. 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 common unitholders.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes or any other 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 common unitholders and thus will be borne indirectly by our common unitholders.
If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess 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 common unitholders might be substantially reduced.reduced and our current and former common 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 common unitholders' behalf.
Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes an audit adjustmentsadjustment to our income tax returns,return, 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 appliableapplicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised Schedule K-1information statement to each common unitholder and former common unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our common unitholders and former common unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties or interest) 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 common unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such common unitholders did not own common units in 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, orand interest, our cash available for distribution to our common unitholders might be substantially reduced.reduced and our current and former common unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustment that were paid on such common unitholders' behalf. These rules are not applicable for tax years beginning on or prior to December 31, 2017.
Even if you, as a common unitholder, do not receive any cash distributions from us, you will be required to pay taxes on your share of our taxable income.
You will be required to pay U.S. federal income taxes and, in some cases, state and local income taxes, on your share of our taxable income, whether 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,
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such as debt exchanges, debt repurchases, or modifications of our existing debt could result in “cancellation of indebtedness income” being allocated to our common 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 common units you sell will, in effect, become taxable income to you if you sell your common units at a price greater than your tax basis in those common units, even if the price you receive is less than your original cost. In addition, because the amount realized includes a common unitholder’s share of our nonrecourse liabilities, if you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale.
A substantial portion of the amount realized from the sale of your common units, whether or not representing gain, may be taxed as ordinary income 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 common units if the amount realized on a sale of your common units is less than your adjusted basis in the common units. Net capital loss may only 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 common units, you may recognize ordinary income from our allocations of income and gain to you occurring prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of common units.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.
Investment in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, a portionvirtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, may be unrelated business taxable income and may be taxable to them. DistributionsWith respect to non-U.S. persons will betaxable years beginning after December 31, 2017, subject to withholding taxes imposed at the highest effective tax rate applicable to such non-U.S. persons, and each non-U.S. person may be required to file United States federal tax returns and pay tax on their share of our taxable income if it is treated as effectively connected income. If you areproposed aggregation rules for certain similarly situated businesses/activities issued by the Treasury Department, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a non-U.S. person, youpartnership such as ours) 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 youra tax advisor before investing in our common units.
Non-U.S. common unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our common units.
Non-U.S. common unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business (“effectively connected income”). Income allocated to our common unitholders and any gain from the sale of our common 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. common unitholder will be subject to withholding at the highest applicable effective tax rate and a non-U.S. common unitholder who sells or otherwise disposes of a common unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that common unit.
Moreover, the transferee of an interest in a partnership that is engaged in a U.S. trade or business is generally required to withhold 10% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person, and we are required to deduct and withhold from the transferee amounts that should have been withheld by the transferee but were not withheld. Because the “amount realized” includes a partner’s share of the partnership’s liabilities, 10% of the amount realized could exceed the total cash purchase price for the units. However, pending the issuance of final regulations, the IRS has suspended the application of this withholding rule to transfers of publicly traded interests in publicly traded partnerships. If recently promulgated regulations are finalized as proposed, such regulations would provide, with respect to transfers of publicly traded interests in publicly traded partnerships effected through a broker, that the obligation to withhold is imposed on the transferor’s broker and that a partner’s “amount realized” does not include a partner’s share of a publicly traded partnership’s liabilities for purposes of determining the amount subject to withholding. However, it is not clear when such regulations will be finalized and if they will be finalized in their current form.
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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 common unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss, and deduction among our common unitholders.
We generally prorate our items of income, gain, loss, and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month (the “Allocation Date”), instead of on the basis of the date a particular common unit 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 common unitholders.

A common unitholderwhose common units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of common units) may be considered to have disposed of those common units. If so, hesuch common unitholder would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and could recognize gain or loss from the disposition.
Because there are no specific rules governing the U.S. federal income tax consequences of loaning a partnership interest, a common unitholder whose common units are the subject of a securities loan may be considered to have disposed of the loaned common units. In that case, the common unitholder may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the common 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 common units may not be reportable by the common unitholder and any cash distributions received by the common unitholder as to those common units could be fully taxable as ordinary income. UnitholdersCommon unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to consult a tax advisor to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns for one calendar year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in taxable income for the unitholder’s taxable year that includes our termination. Our termination would not affect our classification as a partnership for federal income tax purposes, but it would result in our being treated as a new partnership for federal income tax purposes following the termination. If we were treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we were unable to determine that a termination occurred. The IRS has announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership may be permitted to provide only a single Schedule K‑1 to unitholders for the two short tax periods included in the year in which the termination occurs.
You, as a common unitholder, may be subject to state and local taxes and return filing requirements in statesjurisdictions where you do not live as a result of investing in our common units.
In addition to U.S. federal income taxes, you likely will be subject to other taxes, including state and local taxes, unincorporated business taxes 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.returns and pay any taxes due in these jurisdictions. You should consult with your own tax advisors regarding the filing of such tax returns, the payment of such taxes and the deductibility of any taxes paid.

Although we believe our common unitholders are entitled to a 20% deduction related to qualified business income, application of the deduction to royalty income is not free from doubt.
For taxable years beginning after December 31, 2017 and ending on or before December 31, 2025, an individual common unitholder is entitled to a deduction equal to 20% of his or her allocable share of our "qualified business income". Although we expect most of our income to qualify for this deduction, application of these rules to income from mineral interests, such as royalty income, is not entirely clear. The IRS may challenge our treatment of royalty income as qualifying for the deduction.
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Although our counsel has advised us that under current law our royalty income should qualify for the deduction, no assurances can be given that the IRS will not challenge our treatment of royalty income as qualifying for the deduction.
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.


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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 subsequent to the completion of our initial public offering on May 6, 2015.
  Price Range of Common Units 
Distributions1
  High Low Per Common Unit Per Subordinated Unit
2015        
Second Quarter2
 $19.00
 $16.59
 $0.1615
 $0.1615
Third Quarter $17.50
 $13.27
 $0.2625
 $0.2625
Fourth Quarter $16.50
 $12.03
 $0.2625
 $0.18375
         
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

1
Represents cash distributions attributable to the quarter. Cash distributions declared in respect of a quarter are paid in the following quarter.
2
The price range of our common units includes our $19.00 per common unit initial public offering price on April 30, 2015. Distributions were prorated for the period from the completion of our initial public offering on May 6, 2015 through June 30, 2015.
As of February 22, 2017,19, 2020, there were 97,113,310205,944,172 common units outstanding held by 462488 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 22, 2017,19, 2020, we also had also outstanding 95,149,984 subordinated units, and 52,69114,711,219 Series B cumulative convertible preferred units. There is no established public market in which the subordinated units or theSeries B cumulative convertible 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, 20162019 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. 
bsm-20191231_g2.jpg


Comparison of Cumulative Total Return
Assumes Initial Investment of $100

As of December 31,
As of April 30, 201520152016201720182019
Black Stone Minerals, L.P.$100.00  $78.22  $109.07  $110.89  $101.80  $90.19  
S&P 500 Index100.00  99.47  111.37  135.69  129.74  170.59  
Alerian MLP Index100.00  66.99  79.25  74.08  64.88  69.14  
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  As of April 30, 2015 As of December 31, 2015 As of December 31, 2016
Black Stone Minerals, L.P. $100.00
 $78.22
 $109.07
S&P 500 Index 100.00
 99.47
 111.37
Alerian MLP Index 100.00
 66.99
 79.25
The information in this reportAnnual 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 January 10, 2017, we closed on the purchase of certain mineral interests using 625,098 common units valued at $11.8 million to fund a portion of the purchase price. The remaining portion of the purchase price was funded with cash. The issuance of the common units pursuant to the purchase and sale agreement was made in reliance upon an exemption from the registration requirements of the Securities Act of 1933 pursuant to Section 4(a)(2) thereof.
None.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
The following tables settable sets forth our purchases of our common and subordinated, units for each month during the three months ended December 31, 2016:2019:
Purchases of Common Units
PeriodTotal Number of Common Units PurchasedAverage Price Paid Per Unit
Total Number of Common Units Purchased as Part of Publicly Announced Plans or Programs2
Maximum Dollar Value of Common Units That May Yet Be Purchased Under the Plans or Programs2
October 1 – October 30, 20191
1,017  $13.19  —  $70,819,075  
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
November 1 – November 30, 2016 
110,8781
 $18.91
 —
 $—
December 1 – December 31, 2016 
29,0441
 $18.55
 —
 $—
         
Purchases of Subordinated 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
November 1 – November 30, 2016 
7,1951
 $14.66
 —
 $—

1IncludesConsists of units withheld to satisfy tax withholding obligations upon the vesting of certain restricted common and subordinated units held by our executive officerscertain employees.
2 On November 5, 2018, the Board authorized the repurchase of up to $75.0 million in common units. The repurchase program authorizes us to make repurchases on a discretionary basis as determined by management, subject to market conditions, applicable legal requirements, available liquidity, and certain other employees.appropriate factors. All or a portion of any repurchases may be made under a Rule 10b5-1 plan, which would permit common units to be repurchased when we might otherwise be precluded from doing so under insider trading laws. The repurchase program does not obligate us to acquire any particular amount of common units and may be modified or suspended at any time and could be terminated prior to completion.
Cash Distribution Policy
Our partnership agreement generally provides that we will pay any distributions are paid 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 of approximately $25.00equal to 7% per preferred unit;
annum, subject to certain adjustments; and
•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 preferred units have a right to further participate (on an as-converted basis) in quarterly distributions in excess of the quarterly preferred distribution amount under certain circumstances that we do not expect to occur. Even if those additional distributions do occur, considering that the outstanding preferred units are convertible into only a relatively small number of our total outstanding common and subordinated units, we believe these additional distributions payable under those circumstances would not materially adversely affect the per unit distribution rate we would otherwise pay on our common and subordinated units. 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
2017 0.2875 1.15
2018 0.3125 1.25
2019 and thereafter 0.3375 1.35
After March 31, 2019, the minimum quarterly distribution shall be the same as it is for each of the four quarters ending March 31, 2019. The 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 partnerBoard 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 directorsBoard may determine are appropriate. It is our intent, for at least the next several years, to finance most of our acquisitions and working-interestworking interest capital needs with cash generated from operations, borrowings under our credit facility,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 quarterlythen-current distribution levellevels on our common and subordinated units. The board of directors of our general partnerBoard 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.basis on our common units. Please read Part I, Item 1A. “Risk Factors—Factors — Risks Inherent in an Investment in Us—Us — The board of directors of our general partnerBoard may modify or revoke our cash distribution policy at any time at its discretion. Our partnership agreement does not require us to pay any distributions at all. Therefore, the fact thatall on our partnership agreement includes the concept of a minimum quarterly distribution does not provide any assurance that a distribution will be paid on the common units. If we make distributions, our Series B
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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 Series B cumulative convertible preferred units to distributions, please read “—"Series B Cumulative Convertible Preferred Units.” 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 expenditures 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 directorsBoard 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 estimate2017, $13.0 million for the period of April 1, 2017 to March 31, 2018, and $11.0 million for the period of April 1, 2018 to March 31, 2019. Due to the expiration of the subordination period, we do not intend to establish a replacement capital priorexpenditure estimate for periods subsequent to this period.March 31, 2019.
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 partnerBoard 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 facilityCredit Facility restricts our distributions if there is a default under our credit facilityCredit Facility or if our borrowing base is lower than the outstanding loans under our credit facility.Credit Facility. Among other covenants, our credit facilityCredit 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 facilityCredit 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.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.

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Subordinated Units

The limited partners of BSM’s Predecessor ownacquired all of our subordinated units. The principal difference betweenunits in connection with 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.” 
IPO. The subordination period will endunder the partnership agreement ended 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 arewere no outstanding arrearages on our common units. When the subordination period ends as a result of our havingThis test was 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 inupon the payment of the minimum quarterly distribution onfor the first quarter of 2019. Accordingly, 96,328,836 subordinated units converted into 96,328,836 common units our general partner may decide in its sole discretion to convert each subordinated unit into a number ofon May 24, 2019 and common units at a ratio that will be less than oneare no longer entitled 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.arrearages.
Series A Redeemable Preferred Units
Prior to our liquidation, and while anyUntil March 31, 2018, the holders of our outstanding Series A redeemable preferred units remain outstanding, cash or other propertyhad the option to elect to have us redeem, effective as of the partnership will be distributed 100% to ourDecember 31, 2017, their Series A redeemable preferred unitholders until the aggregate Unpaid Preferred Yield (as defined below) of eachunits at face value, plus any accrued and unpaid distributions. All 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%units not redeemed by March 31, 2018 automatically converted to common and subordinated unitholders, untilunits effective as of January 1, 2018 or as soon as practicable thereafter. Therefore, there has been distributedare currently no Series A redeemable preferred units outstanding.
Series B Cumulative Convertible Preferred Units
The holders of our Series B cumulative convertible preferred units receive cumulative quarterly distributions in an aggregate amount in respect of such calendar year equal to 10%7.0% 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 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, theface amount which would be received by the holder of a common unit or subordinated unit, as applicable, if (a) all of the preferred units were converted into or exchanged or exercised for common unitsper annum (the “Distribution Rate”), provided that the Distribution Rate will be adjusted as follows: commencing on the sixth anniversary of November 28, 2017 and duringreadjusting every two years thereafter (each, a “Readjustment Date”), the subordination period, subordinated units, (b)rate will equal the fair market valuegreater of (i) the assets ofDistribution Rate in effect immediately prior to the Partnership in excess of its liabilities as ofrelevant Readjustment Date and (ii) the date of determination of Interest Fair Market Value equaled the Value (as defined in our partnership agreement)10-year Treasury Rate as of such date, adjustedReadjustment Date plus 5.5% per annum; provided, however, that for any quarter 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, prior to reflect any increases in equity value resulting frompaying the deemed conversion, exchange or exercise of convertible securities, and (c) an amount equal to such Value (as defined in our partnership agreement), as so adjusted, were distributedquarterly distribution payable to the unitholders in accordance with the liquidation distribution provisions of the partnership agreement.
“Preferred Yield” means a yield on the outstanding preferred units, equivalent to a 10% per annum interest rate (subject to adjustment following certain events of default by the partnership) on an initial investment of $1,000, calculated based on a 365-day yearincluding any previously accrued and compounded quarterly.unpaid distributions.
“Unpaid Preferred Yield” means, with respect to each preferred unit and as of any date of determination, an amount equal to the excess, if any, of (a) the cumulative Preferred Yield from the closing of this offering through the date established, over (b) the cumulative amount of distributions made as of the date established in respect of the preferred unit.



46
ITEM 6. SELECTED FINANCIAL DATA
The financial information below should be read in conjunction with “Item“Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item“Part II, Item 8. Financial Statements and Supplementary Data” of this Annual Report.
 At December 31,
 20192018201720162015
 (in thousands, except per unit amounts)
Total revenue$487,821  $609,568  $429,659  $260,833  $392,924  
Net income (loss)214,368  295,560  157,153  20,188  (101,305) 
Net income (loss) attributable to the general partner and common units and subordinated units193,368  274,511  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  $1.46  $1.01  $0.26  $(0.56) 
Per subordinated unit (basic)0.64  1.25  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  $1.45  $1.01  $0.26  $(0.56) 
Per subordinated unit (diluted)0.64  1.25  0.56  (0.11) (0.56) 
Cash distributions declared per common and subordinated unit 
Per common unit$1.48  $1.33  $1.20  $1.10  $0.42  
Per subordinated unit0.74  1.13  0.79  0.74  0.42  
Total assets2
$1,545,208  $1,750,124  $1,576,451  $1,128,827  $1,061,436  
Long-term debt394,000  410,000  388,000  316,000  66,000  
Total mezzanine equity298,361  298,361  322,422  54,015  79,162  
  At December 31,
  2016 2015 2014 2013
  (In thousands, except per unit amounts)
Total revenue $260,833
 $392,924
 $548,321
 $463,559
Net income (loss) 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 14,437
 (108,017) * *
Net income (loss) attributable to limited partners per common and subordinated unit (basic)1
  
  
    
Per common unit (basic) 0.26
 (0.56) * *
Per subordinated unit (basic) (0.11) (0.56) * *
Net income (loss) attributable to limited partners per common and subordinated unit (diluted)1
    
    
Per common unit (diluted) 0.26
 (0.56) * *
Per subordinated unit (diluted) (0.11) (0.56) * *
Cash distributions declared per common and subordinated unit  
  
    
Per common unit 1.10
 0.42
 * *
Per subordinated unit 0.74
 0.42
 * *
Total assets2
 1,128,827
 1,061,436
 1,326,782
 1,444,413
Long-term debt 316,000
 66,000
 394,000
 451,000
Total mezzanine equity 54,015
 79,162
 161,165
 161,392

* Information is not applicable for the periods prior to our IPO.
1 See Note 1413 – 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$249.6 million for the years ended December 31, 2016 and 2015, 2014,respectively. We did not have impairments of oil and 2013, respectively.natural gas properties for the years ended December 31, 2019, 2018, and 2017.




47
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.” This discussion includes a comparison of our results of operations and liquidity and capital resources for 2019 and 2018. For the discussion of changes from 2017 to 2018 and other financial information related to 2017, refer to “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations" in our 2018 Annual Report on Form 10-K, which was filed with the SEC on February 26, 2019.

Overview
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 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, creativecreatively structuring ofthe terms on those leases to encourage and accelerate drilling activity, and selectively participating alongside our lessees on a working-interestworking interest basis. Our primary business objective is to growWe believe our reserves, production,large, diversified asset base and cash generated from operations over the long term, while paying, to the extent practicable, a growing 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."
Ourlong-lived, non-cost-bearing mineral and royalty interests consistprovide for stable to growing production and reserves over time, allowing the majority of generated cash flow to be distributed to unitholders.
As of December 31, 2019, our mineral and royalty interests were located in approximately 15.5 million acres, with an average 47.5% ownership interest41 states in that acreage, NPRIs in 1.5 million acres, and ORRIs in 1.5 million acres.the continental United States including all of the major onshore producing basins. These non-cost-bearing interests include ownership in over 50,000approximately 69,000 producing wells. We also own non-operated working interests, a significant portion of which are on our 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 control of the oil and natural gas production fromproduced is transferred to the associated acreagecustomer and collectability of the sales price is sold.reasonably assured. 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
2016 Commodity PricesGeneral and Administrative Expense Reductions

OilWe have taken significant steps to reduce our general and natural gas commodity pricing generally constitutesadministrative expenses, including broad workforce reductions and lower Board and executive compensation levels. In light of this initiative and the largest single variable that impacts our operating results. The volatilityconstrained acquisition environment, Brock Morris, Senior Vice President, Engineering and Geology, and Holbrook Dorn, Senior Vice President, Business Development, have stepped down from their roles. We expect to incur a one-time cash charge of approximately $5 million in the valuefirst quarter of these commodities is reflected in the fact that the 2016 WTI oil spot price ranged from a low of $26.19 per Bbl to a high of $54.01 per Bbl and the 2016 Henry Hub natural gas spot price ranged from a low of $1.49 per MMBtu to a high of $3.80 MMBtu. Despite the negative financial impacts of a low commodity price environment, our active marketing of mineral interests, effective commodity hedging practices, and diligent monitoring of expenses and capital spending enabled us to generate favorable 2016 operating results.2020 associated with severance agreements for affected employees.

2016 Acquisitions

On January 8, 2016,In 2019 we acquired mineral and royalty interests primarily in the Permian Basin for $10.0 million. On June 15, 2016, we acquired an oil and natural gas mineral package primarily located in Weld County, Colorado for $34.0 million. On June 17, 2016, we acquired a diverse oil and natural gas mineral asset package from Freeport-McMoRan Oil and Gas Inc. and certain of its affiliates for $87.6 million. On August 8, 2016, we acquired mineral interests located in Midland and Glasscock Counties ofEast Texas for $8.3 million. Throughout 2016, we acquired certain other oil and natural gas assets for approximately $1.2 million in the aggregate. These transactions met targeted acquisition volumes that were included in our budget and provided near term production and cash flow as well as future development potential that will fuel our planned distribution growth.

2017 Acquisitions
During January 2017, the Partnership closed four mineral interest transactions in Loving County, Texas for approximately $32.0aggregate consideration of $43.1 million in cash with borrowings from the Senior Credit facility, and $11.8$0.9 million of the Partnership'sin our common units. Two Haynesville/Bossier Shale mineral interest transactions closed for $6.4 million. Two additional mineral interestAdditional information regarding acquisitions closedis contained in Angelina County,Note 4 – Oil and Natural Gas Properties to our consolidated financial statements included elsewhere in this Annual Report.
Shelby Trough Update
As previously disclosed, drilling activity has slowed on our Shelby Trough acreage in East Texas, for approximately $8.6 million.


Farmout Agreement
On February 21, 2017,in part due to the Partnership announcedcurrent natural gas price environment. XTO Energy Inc. has informed us that it had entered into a farmout agreementintends to postpone most of its drilling and completion activity until late 2020 or thereafter. In addition, BPX Energy (“BPX”) has significantly reduced current development in the Shelby Trough and has released over 100,000 gross acres. Much of this area has been delineated with Canaan Resource Partners ("Canaan") which covers certainseismic data and through BPX’s drilling to date with successful wells in both the Haynesville and Bossier shale acreage in San Augustine County, Texas operated by XTO Energy Inc. The Partnership has an average 50% working interestshales. While a protracted slowdown of activity in the Shelby Trough would reduce production and, in turn, cash available for distribution, we currently expect to place that acreage and is the largest mineral owner. A total of 58 wells are anticipated to be drilled over an initial phase, beginning with wells spud after January 1, 2017. At its option, Canaan may participateanother operator or operators in two additional phases with each phase estimated to last approximately two years. During the three phases2020.
End of the Subordination Period
48
The subordination period under the partnership agreement Canaan will commitended on the first business day after we 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 phase-by-phase basisperiod of four consecutive, non-overlapping quarters ending on or after March 31, 2019, and fund 80%there were no outstanding arrearages on the common units. This test was met upon the payment of the Partnership's drillingdistribution for the first quarter of 2019. Accordingly, each outstanding subordinated unit converted into one common unit on May 24, 2019 and completion costs and will be assigned 80%the priority right 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 continuingcommon unitholders ceased to fund 40% of the Partnership's costs for those wells on a well-by-well basis. The Partnership will receive a base overriding royalty interest (“ORRI”) before payout and an additional ORRI after payout on all wells drilled under the agreement. The execution of this agreement is anticipated to reduce the Partnership's future capital obligations by approximately $30-$35 million in 2017 and by an average of $40-$50 million annually, thereafter.exist.
Common Unit Repurchase Program
On March 4, 2016,November 5, 2018, the Board of Directors of our general partner (the “Board”) authorized the repurchase of up to $50.0$75.0 million in common units through a program that terminated on September 15, 2016.units. The repurchase program authorizedauthorizes us to make repurchases on a discretionary basis as determined by management, subject to market conditions, applicable legal requirements, available liquidity, and other appropriate factors. All or a portion of any repurchases may be made under a Rule 10b5-1 plan, which would permit common units to be repurchased when we might otherwise be precluded from doing so under applicable laws. The repurchase program does not obligate us to acquire any particular amount of common units and may be modified or suspended at any time and could be terminated prior to completion. We will periodically report the number of common units repurchased. In 2019, we repurchased a total of 1.3 million136,665 common units for an aggregate cost of $20.2$2.2 million. As of December 31, 2019, we have repurchased $4.2 million in common units under the repurchase program since inception. The repurchase program wasis funded from our cash on hand or available revolving credit facility. Repurchased commonavailability under the Credit Facility. Any repurchased units wereare canceled.

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. Recently, oil and natural gas prices have remained significantly below prices seen over the past five years. The EIA expects the pace of inventory builds to slow considerably in 2017 and 2018. The EIA also believesforecasts that continuing global inventory builds will contribute toWTI oil prices remaining below $60will average approximately $61.00 per Bbl through the end of 2018.in 2020 and $68.00 per Bbl in 2021. During the year ended December 31, 2016,2019, the WTI oil spot price reached a low of $26.19$46.31 per Bbl on February 11, 2016January 2, 2019 but reboundedincreased to a high of $54.01$66.24 per Bbl on December 28, 2016.April 23, 2019.
The EIA expects residential and commercialforecasts that the Henry Hub spot natural gas consumption to increase by 6.0%price will average $2.21 per MMBtu for 2020 and 5.2%, respectively, in 2017; in 2018, residential and commercial consumption are projected to be roughly unchanged from anticipated 2017 levels. Natural gas pipeline exports increased in 2016, largely due to shipments to Mexico. The EIA forecasts pipeline exports of natural gas will continue to rise due to growing demand from Mexico's electric power sector and flat natural gas production in that country. Liquified natural gas ("LNG") gross exports increased in 2016 due to the startup of Cheniere Energy, Inc's Sabine Pass LNG in Louisiana. LNG exports are expected to increase in 2017 as Sabine Pass ramps up capacity in the middle of the year. Growth in 2018 is anticipated to be driven by the start of Dominion Recourses, Inc.'s Cove Point facility in Maryland in December 2017 and new projects at Cameron LNG and Freeport LNG during the second half of 2018.  The EIA expects natural gas inventory levels to be below the previous five-year average through much of the winter period, putting upward pressure on natural gas prices.$2.53 per MMBtu for 2021. During the year ended December 31, 2016,2019, Henry Hub spot natural gas prices ranged from a lowhigh of $1.49$4.25 per MMBtu on March 4, 20162019 to a highlow of $3.80$1.75 per MMBtu on December 7, 2016.27, 2019.
To manage the variability in cash flows associated with the projected sale of our oil and natural gas production, we use various derivative instruments, which have recently consisted of fixed-price swap contracts and costless collar contracts.


The following table reflects commodity prices at the end of each quarter presented:
 2019
Benchmark PricesFourth QuarterThird QuarterSecond QuarterFirst Quarter
WTI spot crude oil ($/Bbl)1
$61.14  $54.09  $58.20  $60.19  
Henry Hub spot natural gas ($/MMBtu)1
$2.09  $2.37  $2.42  $2.73  
  2016
Benchmark Prices 
Fourth
Quarter
 
Third
Quarter
 
Second
Quarter
 
First
Quarter
WTI spot oil ($/Bbl) $53.75
 $47.72
 $48.27
 $36.94
Henry Hub spot natural gas ($/MMBtu) $3.71
 $2.84
 $2.94
 $1.98
1 Source: EIA
Rig Count
As we are not anthe operator of record on any producing 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.
49
The following table shows the rig count at the closeend of each quarter presented:
 2019
U.S. Rotary Rig Count1
Fourth QuarterThird QuarterSecond QuarterFirst Quarter
Oil677  713  793  816  
Natural gas125  146  173  190  
Other3  1  1  —  
Total805  860  967  1,006  
  2016
U.S. Rotary Rig Count 
Fourth
Quarter
 
Third
Quarter
 
Second
Quarter
 
First
Quarter
Oil 525
 425
 330
 372
Natural gas 132
 96
 90
 92
Other 1
 1
 1
 —
Total 658
 522
 421
 464
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. According toThe EIA forecasts that inventories will conclude the EIA, natural gas inventories reached a record high of 4,047 Bcf during mid-November 2016; however, subsequent draws were larger than normal and inventories ended December below the previous five-year average for the first time sincewithdrawal season, which is the end of April 2015. The EIA believes that March 2017 through October 2017 inventories will build2020, at a slower pacealmost 2.0 Tcf, or 14% higher than the five-year average. In 2018, theThe EIA expects inventories to followwill reach almost 4.1 Tcf at the typical seasonal pattern.end of October 2020, which would be the highest end-of-October inventory level on record.
The following table shows natural gas storage volumes by region at the closeend of each quarter presented:
 

 2019
Region1
Fourth QuarterThird QuarterSecond QuarterFirst Quarter
 (Bcf)
East771  826  526  210  
Midwest905  973  568  241  
Mountain173  199  134  64  
Pacific251  291  255  113  
South Central1,093  1,029  907  502  
Total3,193  3,318  2,390  1,130  

1  Source: EIA
50
  2016
Region 
Fourth
Quarter
 
Third
Quarter
 
Second
Quarter
 
First
Quarter
  (Bcf)
East 737
 899
 632
 439
Midwest 921
 1,045
 742
 555
Mountain 207
 237
 198
 147
Pacific 275
 318
 315
 262
South Central 1,171
 1,181
 1,253
 1,065
Total 3,311
 3,680
 3,140
 2,468
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;derivative instruments; and
EBITDA, •Adjusted EBITDA and Distributable cash available for distribution.flow.
Volumes of Oil and Natural Gas Produced
In order to assesstrack and trackassess the performance of our assets, we monitor and analyze our production volumes from the various basins and plays that compriseconstitute our extensive asset base. We also regularly compare projected volumes to actual reported volumes and investigate unexpected variations.variances.
Commodity Prices
Factors Affecting the Sales Price of Oil and Natural Gas
The prices we receive for oil, natural gas, and natural gas liquids (“NGLs”)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. As a result of our geographic diversification, we are not exposed to concentrated differential risks associated with any single play, trend, or basin.

•Oil. The substantial majority of our oil production is sold at prevailing market prices, which fluctuate in response to many factors that 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 American Petroleum Institute (“API”)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.

51
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 fixed-pricevariable-to-fixed-price swaps, fixed-price contracts, costless collars, and other contractual arrangements. We generally employ a “rolling hedge” strategy whereby we hedge a significant portion of our proved developed producing reserves 12 to 24 months into the future. The impact of these derivative instruments could affect the amount of revenue we ultimately realize. Since 2015, we have only entered into
Our open derivative contracts consist of fixed-price swap contracts and costless collar contracts. Under fixed-price swap contracts, a counterparty is required to make a payment to us if the settlement price for any settlement period is less than the swap strike price. Conversely, we are required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap strike price. Our costless collar contracts contain a fixed floor price and a fixed ceiling price. If the market price exceeds the fixed ceiling price, we pay the difference between the fixed ceiling price and the market settlement price. If the market price is below the fixed floor price, we receive the difference between the market settlement price and the fixed floor price. If the market price is between the fixed floor and fixed ceiling price, no payments are due from either party. If we have multiple contracts outstanding with a single counterparty, unless restricted by our agreement, we will net settle the contract payments.
We may employ contractual arrangements other than fixed-price swap contracts and costless collar 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, 2016 and as of the date of this filing2019 are detailed in Note 5 – Derivatives andCommodity Derivative Financial Instruments to our consolidated financial statements included elsewhere in this Annual Report. Our credit agreement limits the extent
Pursuant to which we can hedge our future production. Under the terms of our credit agreement,Credit Facility, we are ableallowed to hedge substantially allcertain 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. As of December 31, 2019, we had hedged 82.6% of our estimatedavailable oil and condensate hedge volumes and 61.9% of our available natural gas hedge volumes for 2020.
We intend to continuously monitor the production from our proved developed producing reserves based onassets and the most recent reserve information providedcommodity price environment, and will, from time to our lenders.time, add additional hedges within the percentages described above related to such production for the following 12 to 30 months. We do not enter into derivative instruments for speculative purposes. Including derivative contracts entered into after December 31, 2016, we have hedged 90.3% and 97.2% of our available oil and condensate hedge volumes and 91.1% and 60.3% of our available natural gas hedge volumes for 2017 and 2018, respectively.
Non-GAAP Financial Measures
EBITDA, Adjusted EBITDA and Distributable cash available for distributionflow 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. We define Adjusted EBITDA as EBITDAamortization adjusted for impairment of oil and natural gas properties, accretion of ARO,asset retirement obligations, unrealized gains and losses on commodity derivative instruments, and non-cash equity-based compensation. We define Distributable cash available for distributionflow as Adjusted EBITDA plus or minus amounts for certain non-cash operating activities, estimated replacement capital expenditures during the subordination period, cash interest expense, and distributions to noncontrolling interests and preferred unitholders.
EBITDA, Adjusted EBITDA and Distributable cash available for distributionflow 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 GAAPgenerally accepted accounting principles (“GAAP”) in the U.S. as measures of our financial performance. EBITDA,
Adjusted EBITDA and Distributable cash available for distributionflow 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 EBITDA, Adjusted EBITDA and Distributable cash available for distributionflow may differ from computations of similarly titled measures of other companies.
52
The following table presents a reconciliation of EBITDA, Adjusted EBITDA, and cash available for distribution to net income (loss), the most directly comparable GAAP financial measure, to Adjusted EBITDA and Distributable cash flow for the periods indicated.indicated:
 Year Ended December 31,
 201920182017
 (in thousands)
Net income (loss)$214,368  $295,560  $157,153  
Adjustments to reconcile to Adjusted EBITDA: 
Depreciation, depletion, and amortization109,584  122,653  114,534  
Interest expense21,435  20,756  15,694  
Income tax expense (benefit)(335) 2,309  —  
Accretion of asset retirement obligations1,117  1,103  1,026  
Equity-based compensation20,484  30,134  33,045  
Unrealized (gain) loss on commodity derivative instruments32,817  (53,066) (11,691) 
Adjusted EBITDA399,470  419,449  309,761  
Adjustments to Distributable cash flow:  
Change in deferred revenue42  1,260  (2,086) 
Cash interest expense(20,394) (19,757) (14,817) 
(Gain) loss on sale of assets, net—  (3) (931) 
Estimated replacement capital expenditures1
(2,750) (11,500) (13,500) 
Cash paid to noncontrolling interests—  (211) (120) 
Preferred unit distributions(21,000) (21,025) (5,042) 
Distributable cash flow$355,368  $368,213  $273,265  


  Year Ended December 31,
  2016 2015 2014
  (In thousands)
Net income (loss) $20,188
 $(101,305) $169,187
Adjustments to reconcile to Adjusted EBITDA:    
  
Add:    
  
Depreciation, depletion and amortization 102,487
 104,298
 111,962
Interest expense 7,547
 6,418
 13,509
EBITDA 130,222
 9,411
 294,658
Add:  
  
  
Impairment of oil and natural gas properties 6,775
 249,569
 117,930
Accretion of asset retirement obligations 892
 1,075
 1,060
Equity-based compensation1
 43,138
 18,000
 11,340
Unrealized loss on commodity derivative instruments 81,253
 —
 —
Less:    
  
Unrealized gain on commodity derivative instruments —
 (27,063) (39,283)
Adjusted EBITDA 262,280
 250,992
 385,705
Adjustments to reconcile to cash generated from operations:  
  
  
Add:  
  
  
Restructuring charges —
 4,208
 —
Incremental general and administrative related to initial public offering —
 1,303
 —
Loss on sales of assets, net —
 —
 32
Less:    
  
Deferred revenue (870) (660) (2,589)
Cash interest expense (6,676) (5,483) (12,544)
Gain on sales of assets, net (4,793) (4,873) —
Estimated replacement capital expenditures2
 (11,250) —
 —
Cash generated from operations 238,691
 245,487
 370,604
Less:  
  
  
Cash paid to noncontrolling interests (111) (208) (307)
Redeemable preferred unit distributions (5,763) (11,562) (15,720)
Cash generated from operations available for
   distribution on common and subordinated
   units and reinvestment in our business
 $232,817
 $233,717
 $354,577
1 On April 25, 2016, the Compensation Committee of the Board approved a resolution to change the settlement feature of certain employee long-term incentive compensation 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.
2 On August 3, 2016, theThe Board established a replacement capital expendituresexpenditure estimate of $15.0 million for the period of April 1, 2016 to March 31, 2017. There was no established estimate2017, $13.0 million for the period of April 1, 2017 to March 31, 2018, and $11.0 million for the period of April 1, 2018 to March 31, 2019. Due to the expiration of the subordination period, we do not intend to establish a replacement capital expenditures prior to this period.
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 operationsexpenditure estimate for periods priorsubsequent to our IPO.March 31, 2019.



53


Results of Operations
Year Ended December 31, 20162019 Compared to Year Ended December 31, 20152018
The following table shows our production, revenues,revenue, and operating expenses for the periods presented:
 
 Year Ended December 31,
 20192018Variance
 (dollars in thousands, except for realized prices)
Production:    
Oil and condensate (MBbls)4,777  4,962  (185) (3.7)%
Natural gas (MMcf)1
77,635  71,622  6,013  8.4 %
Equivalents (MBoe)17,716  16,899  817  4.8 %
Realized prices, without derivatives:      
Oil and condensate ($/Bbl)$55.20  $62.53  $(7.33) (11.7)%
Natural gas ($/Mcf)1
2.57  3.47  (0.90) (25.9)%
Equivalents ($/Boe)$26.13  $33.05  $(6.92) (20.9)%
Revenue:      
Oil and condensate sales$263,678  $310,278  $(46,600) (15.0)%
Natural gas and natural gas liquids sales1
199,265  248,243  (48,978) (19.7)%
Lease bonus and other income29,833  36,216  (6,383) (17.6)%
Revenue from contracts with customers492,776  594,737  (101,961) (17.1)%
Gain (loss) on commodity derivative instruments(4,955) 14,831  (19,786) (133.4)%
Total revenue$487,821  $609,568  $(121,747) (20.0)%
Operating expenses:      
Lease operating expense$17,665  $18,415  $(750) (4.1)%
Production costs and ad valorem taxes60,533  64,364  (3,831) (6.0)%
Exploration expense397  7,943  (7,546) (95.0)%
Depreciation, depletion, and amortization109,584  122,653  (13,069) (10.7)%
General and administrative63,353  76,712  (13,359) (17.4)%
Other expense:
Interest expense21,435  20,756  679  3.3 %
  Year Ended December 31,
  2016 2015 Variance
  (Dollars in thousands, except for realized prices and per BOE data)
Production:  
  
  
  
Oil and condensate (MBbls)1
 3,680
 3,565
 115
 3.2 %
Natural gas (MMcf)1
 47,498
 41,389
 6,109
 14.8 %
Equivalents (MBoe) 11,596
 10,463
 $1,133
 10.8 %
Revenue:  
  
  
  
Oil and condensate sales $142,382
 $163,538
 $(21,156) (12.9)%
Natural gas and natural gas liquids sales 122,836
 116,018
 6,818
 5.9 %
Gain (loss) on commodity derivative instruments (36,464) 90,288
 (126,752) (140.4)%
Lease bonus and other income 32,079
 23,080
 8,999
 39.0 %
Total revenue $260,833
 $392,924
 $(132,091) (33.6)%
Realized prices:  
  
  
  
Oil and condensate ($/Bbl) $38.69
 $45.87
 $(7.18) (15.7)%
Natural gas ($/Mcf)1
 $2.59
 $2.80
 $(0.21) (7.5)%
Equivalents ($/Boe) $22.87
 $26.72
 $(3.85) (14.4)%
Operating expenses:  
  
  
  
Lease operating expense $18,755
 $21,583
 $(2,828) (13.1)%
Production costs and ad valorem taxes 35,464
 35,767
 (303) (0.8)%
Exploration expense 645
 2,592
 (1,947) (75.1)%
Depreciation, depletion, and amortization 102,487
 104,298
 (1,811) (1.7)%
Impairment of oil and natural gas properties 6,775
 249,569
 (242,794) (97.3)%
General and administrative 73,139
 77,175
 (4,036) (5.2)%

1 As a mineral-and-royalty-interestmineral 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.
RevenuesRevenue
The $132.1 million decrease in total revenuesTotal revenue for the year ended December 31, 20162019 decreased compared to the year ended December 31, 2015 was2018. The decrease in total revenue from the corresponding period is primarily 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 higherdecreased oil and condensate sales and natural gas and NGL volumes and $9.0 million in additionalsales as a result of lower realized commodity prices, lower lease bonus and other income.income, and a loss on commodity derivative instruments in 2019 compared to a gain in 2018. The overall decrease was partially offset by an increase in natural gas production. Production for 2019 averaged 48.5 MBoe per day, an increase of 2.2 MBoe per day compared to 2018.
Oil and condensate sales. Oil and condensate sales during 2016for the year ended December 31, 2019 were lower than the corresponding period in 2015 primarily2018 due to a steep declinedecreased production volumes and lower realized commodity prices. The decrease in realized prices.oil and condensate production was primarily driven by lower production in the Bakken/Three Forks and Eagle Ford plays. Our mineral-and-royalty-interest
54
mineral and royalty interest oil and condensate volumes accounted for 77.3%92% and 76.8%90% of total oil and condensate volumes for the yearyears ended December 31, 20162019 and the year ended December 31, 2015,2018, 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 revenues increasedand NGL sales decreased for the year ended December 31, 20162019 as compared to 2015. During 2016, increasesthe year ended December 31, 2018 due to lower realized commodity prices, partially offset by increased production volumes. The increase in production from our Haynesville and Wilcox properties served to more than


mitigate the impact of further depressed realized natural gas production was primarily driven by higher production in the Haynesville/Bossier play. Mineral and NGL prices. Mineral-and-royalty-interestroyalty interest production made up 59.3%accounted for 69% and67.3%60% of our natural gas volumes for theyearyears endedDecember 31,2016 2019and 2015,2018, respectively.
Gain (loss) on commodity derivative instruments.  In 2016,  During 2019, we recognized $16.0 million of neta loss from our commodity derivative instruments compared to a gain in 2018. Cash settlements we receive represent realized gains, while cash settlements we pay represent realized losses related to our commodity derivative instruments. In addition to cash settlements, we also recognize fair value changes on our commodity derivative instruments in each reporting period. The changes in fair value result from oil commodity contracts, which included $27.5new positions and settlements that may occur during each reporting period, as well as the relationships between contract prices and the associated forward curves. During 2019, we recognized $27.9 million of realized gains and $32.8 million of unrealized losses from our commodity derivatives, 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$38.2 million of realized gains, compared to $32.6losses and $53.1 million of combinedunrealized gains in 2015, of which $21.4 million2018. The realized gains from our commodity derivatives during 2019 were primarily related to cash settlements received on natural gas derivative instruments, while the realized gains.losses during 2018 were primarily related to cash settlements paid on oil derivative instruments. The unrealized losses on our commodity contracts in 2019 and the unrealized gains in 2018 were primarily driven by changes in the forward commodity price curves for oil during each period.
Lease bonus and other income.When we lease our mineral interests, we generally receive an upfront cash payment, or a lease bonus. Lease bonus income can vary substantively between periods because it is derived from individual transactions with operators, some of which may be significant. Lease bonus and delay rental revenue increasedother income was lower for the year ended December 31, 2016,2019, as compared to 2015.  In 2016, we successfully closed several significant lease transactionsthe same period in Jasper, Tyler, Pecos, and Newton Counties of Texas,2018. Leasing activity in the Red River parishBakken/Three Forks, Haynesville/Bossier, Permian, and Woodbine plays, as well as proceeds from the settlement of Louisiana,a dispute with one of our operators, made up the majority of lease bonus and other income in Potter County of Pennsylvania.   Closings in 2015 included large lease transactions2019. Leasing activity in the Wolfcamp,Bakken/Three Forks, Haynesville/Bossier, Permian, and Austin Chalk plays made up the Eagle Ford Shale,majority of lease bonus and various playsother income in East Texas and in Southern Mississippi.2018.
Operating Expenses
Lease operating expenses. expense. Lease operating expense includes normally recurring expenses associated with our non-operated working interests necessary to produce hydrocarbons from our non-operated working interests in 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, 2016in 2019 as compared to 2015,2018, primarily due to lower workover expense, realized cost efficiencies resulting from the currently depressed industry market, the plugging of certain uneconomicaldecreased repairs and maintenance and other nonrecurring expenses on wells in which we own a non-operating working interest wells, and fewer remedial projects initiated by our operators.interest.
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, 2016,2019, production and ad valorem taxes increased overdecreased as compared to the year ended December 31, 2015, generally2018, as a result of higherlower commodity prices, partially offset by increased natural gas production volumes.
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 the years ended December 31, 2016 and 20152019 primarily resulted fromconsisted of costs incurred to acquire third-party 3-D seismic information related to our mineral and royalty interests from a third-party service provider.interests. Exploration expense for 2018 primarily related to the costs incurred on the PepperJack B#1 well.
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 increaseddecreased for the year ended December 31, 20162019 as compared to 2015,2018, primarily due to higher production rates offset by the impact of a reduced cost basis resulting from impairment charges related to prior periods.lower depletion rates partially offset by higher production volumes. Lower depletion rates in 2019 were primarily driven by increases in estimated proved developed producing reserve quantities in the Haynesville/Bossier formation and the Permian Basin.
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. Impairments of $250.0 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.
55
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, 2016,2019, general and administrative expenses decreased compared to 2015. In 2016, personnel costs and costs attributable to our long-term incentive plans were lower2018, primarily due to one-timelower costs associated with our incentive compensation awards grantedplans. This decrease was driven by higher costs recognized in 2018 on incentive compensation awarded in connection with our initial public offering in 2015, as a result ofhigher costs recognized in 2018 due to outperformance relative to performance targets, and lower costs recognized in 2019 on performance-based incentive awards due to the decrease in 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.common unit price period over period.

Other Expense

Interest expense. InterestFor the year ended December 31, 2019, interest expense increased compared to 2018, primarily due to higher average outstanding borrowings partially offset by lower interest rates under our credit facility. OutstandingCredit Facility. The increase in average outstanding borrowings during 2016 were higher than 2015,was primarily due to additional loan proceeds for multiplethe funding of acquisitions preferred unit redemptions,in 2019 and common unit repurchases.2018.























Year Ended December 31, 2015 Compared to Year Ended December 31, 2014
The following table shows our production, revenues, and expenses for the periods presented:
  Year Ended December 31,
  2015 2014 Variance
  (Dollars in thousands, except for realized prices and per BOE data)
Production:  
  
  
  
Oil and condensate (MBbls)1
 3,565
 3,005
 560
 18.6 %
Natural gas (MMcf)1
 41,389
 42,273
 (884) (2.1)%
Equivalents (MBoe) 10,463
 10,051
 $412
 4.1 %
Revenue:  
  
  
  
Oil and condensate sales $163,538
 $257,390
 $(93,852) (36.5)%
Natural gas and natural gas liquids sales 116,018
 207,456
 (91,438) (44.1)%
Gain (loss) on commodity derivative instruments 90,288
 37,336
 52,952
 141.8 %
Lease bonus and other income 23,080
 46,139
 (23,059) (50.0)%
Total revenue $392,924
 $548,321
 $(155,397) (28.3)%
Realized prices:  
  
  
  
Oil and condensate ($/Bbl) $45.87
 $85.65
 $(39.78) (46.4)%
Natural gas ($/Mcf)1
 $2.80
 $4.91
 $(2.11) (43.0)%
Equivalents ($/Boe) $26.72
 $46.25
 $(19.53) (42.2)%
Operating expenses:  
  
  
  
Lease operating expense $21,583
 $21,233
 $350
 1.6 %
Production costs and ad valorem taxes 35,767
 49,575
 (13,808) (27.9)%
Exploration expense 2,592
 631
 1,961
 310.8 %
Depreciation, depletion, and amortization 104,298
 111,962
 (7,664) (6.8)%
Impairment of oil and natural gas properties 249,569
 117,930
 131,639
 111.6 %
General and administrative 77,175
 62,765
 14,410
 23.0 %

1 As a mineral-and-royalty-interest owner, we are often provided insufficient and inconsistent data on NGL volumes by our operators. As a result, we are unable to reliably 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.
Revenues
The decrease in total revenues for the year ended December 31, 2015 compared to the year ended December 31, 2014 was due to a decrease of $228.9 million from lower realized commodity prices and $23.1 million of reduced lease bonus activity, partially offset by $52.9 million of gains attributable to commodity derivative instruments and $43.6 million related to higher oil and condensate production volumes.
Oil and condensate sales. Oil and condensate sales during 2015 were lower than the corresponding period in 2014 primarily due to a steep decline in realized prices. Our mineral-and-royalty-interest oil volumes accounted for 76.8% and 74.7% of total oil and condensate volumes for the year ended December 31, 2015 and the year ended December 31, 2014, respectively. Our mineral-and-royalty-interest oil volumes increased in 2015 relative to 2014 primarily driven by production increases from new wells in the Bakken/Three Forks and Eagle Ford plays. Our working-interest oil and condensate volumes increased during 2015 versus 2014 primarily due to volumes added from new wells in the Bakken/Three Forks and Wilcox plays.
Natural gas and natural gas liquids sales. Natural gas revenues decreased for the year ended December 31, 2015 as compared to 2014. A significant decline in the realized natural gas and NGL prices for the year ended December 31, 2015 versus the corresponding period in 2014 was primarily responsible for the decrease in our natural gas and NGL revenues.


Mineral-and-royalty-interest production made up 67.3% and67.8% of our natural gas volumes for theyear endedDecember 31,2015and 2014, respectively.
Gain on commodity derivative instruments.  In 2015, we recognized $57.7 million of gains from oil commodity contracts, of which $15.9 million were realized, compared to $27.5 million of combined gains in 2014, virtually all of which were unrealized. In 2015, we recognized $32.6 million of gains from natural gas commodity contracts, of which $11.2 million were unrealized, compared to $9.8 million of net gains in 2014, of which $11.8 million were unrealized gains.
Lease bonus and other income. Lease bonus and delay rental revenue decreased for the year ended December 31, 2015 as compared to 2014. In 2014, we successfully closed several large leases in the Canyon Lime and Canyon Wash plays in north Texas, the Permian Basin in west Texas, the Austin Chalk and Woodbine play in east Texas, the Tuscaloosa Marine Shale play in Mississippi and the Bakken play in North Dakota.  While we closed large lease transactions in 2015 in Wolfcamp, Eagle Ford Shale, and various plays in East Texas and in Southern Mississippi, the total number of leases was down significantly from 2014.
Operating Expenses
Lease operating expenses. Lease operating expense increased slightly for the year ended December 31, 2015 as compared to 2014, primarily due to higher oil and condensate production.
Production costs and ad valorem taxes. For the year ended December 31, 2015, production and ad valorem taxes decreased over the year ended December 31, 2014, generally as a result of lower realized commodity prices and estimated mineral reserve valuations.
Exploration expense. Exploration expense for the year ended December 31, 2015 increased from the year ended December 31, 2014, primarily due to 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 decreased for the year ended December 31, 2015 as compared to 2014, 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 for the years ended December 31, 2015 and 2014 primarily resulted from changes in reserve values due to declines in future expected realized net cash flows as a result of lower commodity prices.
General and administrative. For the year ended December 31, 2015, general and administrative expenses increased compared to 2014. In 2015, personnel costs and costs attributable to our long-term incentive plans were $12.3 million higher primarily due to an increase in incentive compensation awards granted subsequent to our IPO and certain restructuring costs.  We also incurred an additional $2.5 million for our Sarbanes-Oxley Act compliance project and other consulting work during 2015.
Interest expense. Interest expense decreased due to lower average outstanding borrowing under our credit facility. Outstanding borrowings during 2015 were lower than 2014, primarily due to payments made towards the outstanding balance of our credit facility with proceeds from our IPO.
Liquidity and Capital Resources
Overview
Our primary sources of liquidity are cash generated from operations, borrowings under our credit facility,Credit Facility, and proceeds from the issuance of equity and debt. Our primary uses of cash are for distributions to our unitholders, reducing outstanding borrowings under our Credit Facility, and for investing in our business, specifically the acquisition of mineral and royalty interests and our selective participation on a non-operated working-interestworking interest basis in the development of our oil and natural gas properties. 
The board of directors of our general partnerBoard has adopted a policy pursuant to which, distributions equal in amount to the applicableat a minimum, quarterly distributiondistributions 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 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 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 partnerBoard may change the foregoing distribution policy at any time and from time to time.
We intend to finance our future acquisitions and working-interest capital needs with cash generated from operations, borrowings from our credit facility,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 partnerBoard established a replacement capital expenditure estimate of $15.0 million for the period of April 1, 2016 to March 31, 2017.2017, $13.0 million for the period of April 1, 2017 to March 31, 2018, and $11.0 million for the period of April 1, 2018 to March 31, 2019. Due to the expiration of the subordination period, we do not intend to establish a replacement capital expenditure estimate for periods subsequent to March 31, 2019.
Cash Flows
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018
The following table shows our cash flows for the periods presented:
 Year Ended December 31,
 20192018Change
 (in thousands)
Cash flows provided by operating activities$412,720  $385,378  $27,342  
Cash flows used in investing activities(48,623) (163,804) 115,181  
Cash flows provided by (used in) financing activities(361,392) (221,802) (139,590) 
  Year Ended December 31,
  2016 2015 2014
  (In thousands)
Cash flows provided by operating activities $196,656
 $284,735
 $396,125
Cash flows used in investing activities (221,542) (90,998) (101,110)
Cash flows provided by (used in) financing activities 21,425
 (195,307) (310,335)
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015
Operating Activities. Activities. Our operating cash flow isflows are dependent, in large part, on our production, realized commodity prices, leasing revenues,derivative settlements, lease bonus revenue, and operating expenses. For the year ended December 31, 2016,The increase in cash flows from operating activities decreased by $88.1 million. This decreaseoperations 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 milliona net increase 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.
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014
Operating Activities. For the year ended December 31, 2015, cash flows from changes in operating activities decreased by $111.4 million. This decrease was primarily due to lower cash collections of $190.0 million related to oilassets and natural gas sales and lease bonus revenue asliabilities for 2019 compared to 2014; the impact of $65.2 million in highera net decrease for 2018
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and net cash collections related to thereceived on settlement of commodity derivative instruments for 2019 compared to net cash paid for 2018. The overall increase in cash flows from operations was partially offset the decrease resulting from lowerby decreased oil and condensate sales and natural gas and NGL sales driven by lower realized commodity prices and decreased lease bonus.bonus and other income.
Investing Activities. The netActivities. Net cash used in investing activities decreased by $10.1 million in 20152019 as compared to 20142018. The decrease was primarily due to a reduction of $26.2 million in capitalreduced oil and natural gas property acquisitions and expenditures, for our working interests, net of proceeds from the sales of oil and natural gas properties and a contractual termination payment related to a leasehold prospect.  An increase of $16.7 million spent on acquisitions partially offset the overall decrease in net cash used in investing activities.our farmout agreements.
Financing Activities. For the year ended December 31, 2015, the net cashActivities. Cash flows used in financing activities decreased $115.0 millionfor 2019 increased as compared to 2014. During 2015, we used2018. The increase was primarily due to increased distributions to common and subordinated unitholders and net proceeds from our IPO to repay substantially all of our outstanding indebtednessrepayments under our credit facility.  The proceeds receivedCredit Facility in excess of2019 compared with net borrowing in 2018. We also sold no common units under our net repayments resulted in a decrease in net cash used in financing activities from 2014.  Monies borrowed to fund a $41.5 million cash tender offer for our preferred units plus unpaid accrued yield partially offset the overall decrease in net cash used in financing activities.at-the-market offering program during 2019.


Development Capital Expenditures
AtIn the beginningfirst 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.
Our 2017 drilling expenditures are2020 capital expenditure budget associated with our non-operated working interests is expected to be between $50.0approximately $5 million, and $60.0 million. Approximately $50 millionnet of our drillingfarmout reimbursements. The majority of this capital budget will be spent for workovers on existing wells in which we own a working interest.
During 2019, we spent approximately $4.3 million associated with our non-operated working interests, net of farmout reimbursements. The majority of this capital was spent for workovers on existing wells in which we own a working interest or for acquiring new leasehold acreage for subsequent farmout in the Haynesville/Bossier playplay.
During 2018, we spent approximately $36.3 million associated with the remainder expected to be spent in various plays including the Bakken/Three Forks and Wolfcamp plays. On February 16, 2017, we entered into a farmout agreement which will reduce our future capital requirements and will generate additional royalty income. The farmout covers ournon-operated working interests within an approximate 34,000-acre block in San Augustine County, Texas. We expectcertain Haynesville/Bossier wells in the Shelby Trough area of East Texas, net of farmout agreementreimbursements, related to reduce our capital obligations by approximately $30-$35 millioncompletions in 2017 and by an average of $40-$50 million annually, thereafter.
During 2016,wells which were spud prior to the farmouts. In the PepperJack prospect area, we spent $73.3approximately $11.9 million during 2018 to drill and log two wells targeting the Lower Wilcox formation. We spent an additional $0.5 million related to drillingthe completion costs for the PepperJack A#1 well in the fourth quarter of 2018.
Acquisitions
During 2019, we spent approximately $43.1 million and completion costs. We also spent $141.1issued common units valued at $0.9 million related to fouracquisitions of mineral and royalty interests, which also included proved oil and natural gas properties.
During 2018 we spent approximately $127.3 million and issued common units valued at $22.6 million related to acquisitions in 2016 as well as a final holdback payment from an acquisition in 2015. of mineral and royalty interests, which also included proved oil and natural gas properties.
See Note 4 - Acquisitions in– Oil and Natural Gas Properties to the consolidated financial statements included elsewhere in this Annual Report for further discussion.additional information.
During 2015, we spent approximately $62.3 million on eight acquisitions. We also incurred 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.
Credit Facility
On January 23, 2015, we amended and restatedPursuant to our $1.0 billion senior secured revolving credit agreement. Under this thirdagreement, as amended and restated credit facility,(the "Credit Facility"), 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. On October 28, 2015, the third amended and restated credit facility was further amended to extend the term of the agreement from February 3, 2017 to February 4, 2019. Borrowings under the third amended and restated credit facilityCredit Facility may be used for the acquisition of properties, cash distributions, and other general corporate purposes. Our regular, semi-annual borrowing base redetermination process resulted in a decrease of the borrowing base from $550.0 million to $450.0 million, effective April 15, 2016. Our fall 2016 borrowing base redetermination process resulted in an increase in the borrowing base from $450.0 million to $500.0 million, which became effective October 31, 2016.Credit Facility terminates on November 1, 2022. As of December 31, 2016,2019, we had outstanding borrowings of $316.0$394.0 million at a weighted-average interest rate of 3.26%4.05%.

The borrowing base under the third amended and restated credit agreement is redetermined semi-annually, typically in April and October of each year, by the administrative agent, taking into consideration the estimated loan value of our oil and natural gas properties consistent with the administrative agent’s normal oil and natural gas 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
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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 in between scheduled redeterminations. We also 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. Effective May 4, 2018, the borrowing base redetermination increased the borrowing base from $550.0 million to $600.0 million. Effective October 31, 2018, the borrowing base was further increased to $675.0 million and remained at that level until the most recent redetermination, effective October 23, 2019, which reduced the borrowing base to $650.0 million.
Outstanding borrowings under the third amended and restated credit facilityCredit Facility 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,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. ThroughPrior to October 2016,31, 2018, 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 2016 borrowing base redetermination, the applicable margin ranges from 1.00% to 2.00% in the case of the alternative base rate and from 2.00% to 3.00 %3.00% in the case of LIBOR, depending on the borrowings outstanding in relation to the borrowing base. Effective October 31, 2018, the applicable margin for the alternative base rate was reduced to between 0.75% and 1.75% and the applicable margin for LIBOR was reduced to between 1.75% and 2.75%.
We are obligated to pay a quarterly commitment fee ranging from a 0.375% to 0.500% annualized rate on the unused portion of the borrowing base, depending on the amount of the borrowings outstanding in relation to the borrowing base. Principal may be optionally repaid from time to time 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. The third amended and restated credit facilityOur Credit Facility is secured by liens on substantially all of our producing properties.oil and natural gas production and assets.


The third amended and restatedOur 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 swapderivative agreements, as well as require the maintenance of certain financial ratios. The third amended and restated credit agreement contains two financial covenants: total debt to EBITDAX of 3.5:1.0 or less;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 third amended and restated credit agreement (including due to athe failure to satisfy one of the financial covenants) or during any time that our borrowing base is lower than the loans outstanding under the third amended and restated credit facility.agreement. The lenders have the right to accelerate all of the indebtedness under the third amended and restated credit facilityagreement upon the occurrence and during the continuance of any event of default, and the third amended and restated credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy, and change of control. There are no cure periods for events 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, 2016,2019, we were in compliance with all debt covenants.
On July 27, 2017, the U.K. Financial Conduct Authority announced that it intends to stop persuading or compelling banks to submit LIBOR rates after 2021. Our Credit Facility includes provisions to determine a replacement rate for LIBOR if necessary during its term, which require that we and our lenders agree upon a replacement rate based on the then-prevailing market convention for similar agreements. We currently do not expect the transition from LIBOR to have a material impact on us. However, if clear market standards and replacement methodologies have not developed as of the time LIBOR becomes unavailable, we may have difficulty reaching agreement on acceptable replacement rates under our Credit Facility. In the event that we do not reach agreement on an acceptable replacement rate for LIBOR, outstanding borrowings under the Credit Facility would revert to a floating rate equal to the alternative base rate (which, as of the time that LIBOR becomes unavailable, is equal to the greater of the Prime Rate and the Federal Funds effective rate plus 0.50%) plus the applicable margin for the alternative base rate which ranges between 0.75% and 1.75%. If we are unable to negotiate replacement rates on favorable terms, it could have a material adverse effect on our financial condition, results of operations, and cash distributions to unitholders.
Contractual Obligations
The following table summarizes our minimum payments as of December 31, 20162019 (in thousands):
 Payments due by period
 TotalLess Than 1 Year1-3 Years3-5 YearsMore Than 5 Years
Credit facility$394,000  $—  $394,000  $—  $—  
Operating lease obligations5,606  1,371  2,796  1,439  —  
Purchase commitments1,049  1,049  —  —  —  
Total$400,655  $2,420  $396,796  $1,439  $—  

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  Payments due by period
  Total Less Than 1 Year 1-3 Years 3-5 Years More Than 5 Years
Credit facility $316,000
 $—
 $316,000
 $—
 $—
Operating lease obligations 3,296
 1,603

1,693
 —
 —
Purchase commitments 967
 967
 —
 —
 —
Total $320,263
 $2,570
 $317,693
 $—
 $—
Off-Balance Sheet Arrangements
At December 31, 2016,2019, 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 MethodUse of AccountingEstimates
The preparation of consolidated financial statements in conformity with GAAP requires us 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.
Our 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. Our 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.
We useevaluate 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 our fair value estimates and cause us to perform analyses to determine if our oil and natural gas properties are impaired. As future commodity prices cannot be predicted accurately, actual results could differ significantly from estimates.
Oil and Natural Gas Properties
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, are capitalized. The cost of property acquisitions, successful exploratory wells, development costs, and support equipment and facilities are initially capitalized when incurred. Acquisitions of proved oil and natural gas properties and working interests are generally considered business combinations and are recorded at their estimated fair value as of the acquisition date. Acquisitions that consist of all or substantially all unproved oil and natural gas properties are generally 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
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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 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 DD&A. DD&A of producing oil and natural gas properties is recorded based on athe units-of-production methodology. Acquisitionmethod. 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, and capitalized development costs are amortized on the basis of proved developed reserves.undeveloped. Proved reserves are estimated quantities of oil and natural gas that can be estimatedwhich geological and engineering data demonstrate with reasonable certainty to be economically producible from a given date forward,commercially recoverable in future years from known reservoirs under existing economic and operating conditions. DD&A expense related to our producing oil and natural gas properties was $109.0 million, $122.5 million, and $114.3 million for the years ended December 31, 2019, 2018, and 2017, respectively.


conditions, operating methods, and government regulations. A sustained low price environment could decrease our estimateWe 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, which would increasefuture commodity prices, timing of future production, operating costs, future capital expenditures, and a risk-adjusted discount rate. There was no impairment of proved oil and natural gas properties for the rateyears ended December 31, 2019, 2018, and 2017.
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 we record depletion expense and reduce net income. Additionally, a decline in proved reserve estimates may impactpoint an impairment loss is recognized to the outcomeextent the carrying value exceeds the estimated recoverable value. The carrying value of ourunproved properties, including unleased mineral rights, is determined based on management’s assessment of producingfair 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 impairment. the years ended December 31, 2019, 2018, and 2017.
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, 20162019 reserve report. Applying this discount results in an approximate 7.0%2% reduction of estimated proved reserve volumes as compared to the undiscounted pricing scenario used in our December 31, 20162019 reserve report prepared by NSAI.
Other exploratory costs, including annual delay rentals and geological and geophysical costs, are expensed when incurred. Mineral and royalty interests and working interests are recorded at cost at the time of acquisition. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized.
The costs of unproved leaseholds and mineral interests are capitalized as unproved properties pending the results of exploration efforts. As unproved leaseholds are determined to be proved, the related costs are transferred to proved properties. Unproved and non-producing property costs are assessed periodically, on a property-by-property basis, and an impairment loss is recognized to the extent, if any, the recorded value has been impaired. Mineral interests are recorded at cost at the time of acquisition. Mineral interests are assessed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. This assessment is performed by comparing carrying values to valuation estimates and impairment is recognized to the extent that book value exceeds estimated recoverable value. Any impairment will generally be based on geographic or geologic data and our estimated future cash flows related to our properties.
We evaluate impairment of producing properties whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. We estimate the undiscounted future cash flows expected in connection with the properties and compare such undiscounted future cash flows to the carrying amount of the properties to determine if the carrying amount is recoverable. When the carrying amount of a property exceeds its estimated undiscounted future cash flows, the carrying amount is reduced to its fair value. Fair value is calculated as the present value of estimated future discounted 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 markets for oil and natural gas have a history of significant price volatility. However, a sustained low price environment could result in lower NYMEX forward strip prices and lower estimates of future cash flows expected from our properties. Such decrease in cash flow estimates could result in recording additional impairment for our properties if such circumstances indicated the carrying amount of the asset may not be recoverable.
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 and equipment.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 productionunits-of-production consistent with the related asset.
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Revenues from Contracts with Customers
Accounting Standards Codification ("ASC") 606, Revenue Recognition
We recognize revenue when it is realized or realizablefrom Contracts with Customers, requires us to identify the distinct promised goods and earned. Revenues are considered realized or realizableservices within a contract which represent separate performance obligations and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii)determine the seller’stransaction price to allocate to the buyer is fixed or determinable, and (iv) collectability is reasonably assured.performance obligations identified. We recognize oiladopted ASC 606 using the modified retrospective method, which was applied to all existing contracts for which all (or substantially all) of the revenue had not been recognized under legacy revenue guidance as of the date of adoption, January 1, 2018.
Oil and natural gas revenue from our interests in producing wells when the associated production is sold. To the extent actual volumes and pricessales
Sales of oil and natural gas are unavailable for a given reporting period becauserecognized at the point control of timing or information not received from third parties, the expectedproduct is transferred to the customer and collectability of the sales volume and prices for these properties are estimated and recorded within accounts receivable. Crude oilprice is reasonably assured. Oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. NaturalThe price we receive for natural gas contracts’ pricing provisions areis 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 onAs each unit of product represents a monthly basis.separate performance obligation and the consideration is variable as it relates to oil and natural gas prices, we recognize revenue from oil and natural gas sales using the practical expedient for variable consideration in ASC 606.
Our other sources of revenue include mineral leaseLease bonus and other income
We also earn revenue from lease bonuses and delay rentals, which are recognized as revenue according to the terms of the lease agreements.rentals. We generate lease bonus revenue fromby leasing our mineral interests to exploration and production companies. TheA lease agreements transferagreement represents our contract with a customer and generally transfers the rights to any oil or natural gas discovered, to the operators, grantgrants us a right to a specified royalty interest, and requirerequires that drilling and completion operations be donecommence within a specified time period. We recognize such lease bonus revenue at which timeControl is transferred to the lessee and we have satisfied our performance obligation when the lease agreement has beenis executed, such that revenue is recognized when the lease bonus payment is determinedreceived. At the time we execute the lease agreement, we expect to be collectable, andreceive the lease bonus payment within a reasonable time, though in no case more than one year, such that we have no further
obligation to refundnot adjusted the payment.expected amount of consideration for the effects of any significant financing component per the practical expedient in ASC 606. We also recognize revenue from delay rentals to the extent drilling has not started within the specified period, payment has been collected,received, and we have no further obligation to refund the payment.
DerivativesAllocation of transaction price to remaining performance obligations
Oil and natural gas sales
We have utilized the practical expedient in ASC 606 which states we are not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. As we have determined that each unit of product generally represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
Lease bonus and other income
Given that we do not recognize lease bonus or other income until a lease agreement has been executed, at which point its performance obligation has been satisfied, and payment is received, we do not record revenue for unsatisfied or partially unsatisfied performance obligations as of the end of the reporting period. Overall, there were no material changes in the timing of the satisfaction of our performance obligations or the allocation of the transaction price to our performance obligations in applying the guidance in ASC 606 as compared to legacy GAAP.
Prior-period performance obligations
We record oil and natural gas revenue in the month production is delivered to the purchaser. As a non-operator, we have limited visibility into the timing of when new wells start producing and production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded within the Accounts receivable line item in the accompanying consolidated balance sheets. The difference between our estimates and the actual amounts received for oil and natural gas sales is recorded in the
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month that payment is received from the third party. For the years ended December 31, 2019 and 2018, revenue recognized in the reporting periods related to performance obligations satisfied in prior reporting periods was immaterial.
Commodity Derivative Financial Instruments
Our ongoing operations expose us to changes in the market price for oil and natural gas. To mitigate the given commodity price risk associated with its operations, we use commodity derivative financial instruments. From time to time, such instruments may include fixed-price contracts, variable to fixedvariable-to-fixed price swaps, costless collars, fixed-price contracts, and other contractual arrangements. We do not enter into derivative instruments for speculative purposes. In addition, we currently employ a “rolling hedge” strategy whereby we generally hedge our proved developed producing reserves 12 to 24 months into the future. 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.sheets. 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.Board. Total compensation expense for unit-based awards is calculated based on the number of units grantedexpected 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,estimate, are likelyprobable to vest, by the grant-datemeasurement-date (i.e., the last day of each reporting period date) fair value and recognized using the accelerated or straight-line attribution method.methods, depending on the terms of the award. Equity-based compensation expense related to unit-based awards is included in generalGeneral 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 109 – Incentive Compensation within the consolidated financial statements included elsewhere in this Annual Report for additional information.
Prior to our initial public offering, the board of directors of our Predecessor determined the fair value of unit-based awards by considering 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.


ItemITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Commodity Price Risk
Our major market risk exposure is the pricing of oil, natural gas, and natural gas liquidsNGLs 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 floatingthe difference between the fixed contract price and the market settlement price. The designated floatingmarket settlement 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 – Derivatives andCommodity Derivative Financial Instruments and Note 6 – Fair Value MeasurementMeasurements 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 yeartwelve months ended December 31, 2016.2019. Applying this discount results in an approximate 7.0%2% reduction of proved reserve volumes as compared to the undiscounted December 31, 20162019 SEC pricing scenario.
62
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, 2016,2019, we had nine counterparties, all of which are rated Baa3Baa1 or better by Moody’s. Six of our counterpartiesMoody’s and are lenders under our credit facility.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, 2016,2019, we had $316.0$394.0 million of outstanding borrowings under our credit facility,Credit Facility, bearing interest at a weighted-average interest rate of 3.26%4.05%. 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 $3.2$3.9 million for the year ended December 31, 2016,2019, 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, 2016.2019 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.
63
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, 2016,2019, 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, 2016.2019.
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, 2016,2019, which is included in the Annual Report on page F-3.F-4.
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, 2016,2019, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


ITEM 9B. OTHER INFORMATION
None.


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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 20172020 Annual Meeting of Limited Partners (“20172020 Proxy Statement”), which will be filed with the SEC not later than 120 days after December 31, 2016.2019.
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 20172020 Proxy Statement, which will be filed with the SEC not later than 120 days after December 31, 2016.2019.
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 20172020 Proxy Statement, which will be filed with the SEC not later than 120 days after December 31, 2016.2019.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
Information required by this item is incorporated by reference to the 20172020 Proxy Statement, which will be filed with the SEC not later than 120 days after December 31, 2016.2019.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Information required by this item is incorporated by reference to the 20172020 Proxy Statement, which will be filed with the SEC not later than 120 days after December 31, 2016.2019.



65

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 NumberDescription
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 on Form 8-K filed on November 29, 2017 (SEC File No. 001-37362))
Exhibit NumberDescription
3.1Certificate 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)).
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)).
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., as amended (incorporated herein by reference to Exhibit 3.23.1 of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on May 6, 2015 (SEC File No. 001-37362)).
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)).
10.1^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)).
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)).
Description of Securities
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)).
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)).
66

First Amendment to ThirdFourth 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 October 28, 2015,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)).
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 Black Stone Minerals, L.P.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 Parent MLP,Documentation Agent, and a syndicate of lenders (incorporated herein by reference to Exhibit 10.1dated as of Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on October 28, 2015 (SEC File No. 001-37362)).February 7, 2018.
10.3*Second Amendment to ThirdFourth Amended and Restated Credit Agreement dated as of October 31, 2016, 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, and a syndicate of lenders.
10.4Third 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, 2015October 31, 2018 (incorporated herein by reference to Exhibit 10.2 to10.1 of Black Stone Minerals, L.P.’s Registration StatementCurrent Report on Form S-18-K filed on March 19, 2015November 5, 2018 (SEC File No. 333-202875)001-37362)).
10.5^Employment Agreement by and between Black Stone Minerals Company, L.P. and Thomas L. Carter, Jr. effective as of April 1, 2009 (incorporated herein by reference to Exhibit 10.3 to Black Stone Minerals, L.P.’s Registration Statement on Form S-1 filed on March 19, 2015 (SEC File No. 333-202875)).


10.6^
10.5^
First Amendment to Employment Agreement by and between Black Stone Minerals Company, L.P. and Thomas L. Carter, Jr. effective as of June 25, 2014 (incorporated herein by reference to Exhibit 10.4 to Black Stone Minerals, L.P.’s 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 STI Award Grant Notice and STI Award Agreement (Leadership) under the Black Stone Minerals, L.P. Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.1 to Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on February 2, 2016 (SEC File No. 001-37362).
10.17^Form of LTI Award Grant Notice and LTI Award Agreement (Leadership) under the Black Stone Minerals, L.P. Long-Term 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 2,19, 2016 (SEC File No. 001-37362).
10.18^Form of STI Award Grant Notice and STI Award AgreementLetter (Leadership) under the Black Stone Minerals, L.P. Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.17 of Black Stone Minerals, L.P.'s Annual Report on Form 10-K filed on February 28, 2018 (SEC File No. 001-37362)).
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 February 19, 2016December 12, 2017 (SEC File No. 001-37362)).
10.19^Form of LTI Award Grant Notice and LTI Award Agreement (Leadership) under the Black Stone Minerals, L.P. Long-Term Incentive Plan (incorporated herein by reference to Exhibit 10.2 Black Stone Minerals, L.P.’s Current Report on Form 8-K filed on February 19, 2016 (SEC File No. 001-37362)).


10.20^Separation and Consulting Agreement and General Release of Claims, dated as of November 21, 2016, by and among Marc Carroll, Black Stone Natural Resources Management Company, and Black Stone Minerals GP, L.L.C. (incorporated herein by reference 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)).
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*Inline XBRL Instance Document.Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
67

101.SCH*Inline XBRL Taxonomy Schema Document.
101.CAL*Inline XBRL Taxonomy Calculation Linkbase Document.
101.DEF*Inline XBRL Taxonomy Definition Linkbase Document.
101.LAB*Inline XBRL Taxonomy Label Linkbase Document.
101.PRE*Inline XBRL Taxonomy Presentation Linkbase Document.

*Filed herewith.
^104*Cover Page Interactive Data File - the cover page iXBRL tags are embedded within the Inline XBRL 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.



68
















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
March 1, 2017Date: February 25, 2020By:/s/ Thomas L. Carter, Jr.
Thomas L. Carter, Jr.
President, Chief Executive Officer and Chairman

















































































69


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.
SignatureTitleDate
SignatureTitleDate
/s/ Thomas L. Carter, Jr.President, Chief Executive Officer and ChairmanMarch 1, 2017February 25, 2020
Thomas L. Carter, Jr.(Principal Executive Officer)
/s/ Jeffrey P. WoodSenior Vice President and Chief Financial OfficerMarch 1, 2017February 25, 2020
Jeffrey P. Wood(Principal Financial Officer)
/s/ Dawn K. SmajstrlaVice President and Chief Accounting OfficerMarch 1, 2017February 25, 2020
Dawn K. Smajstrla(Principal Accounting Officer)
/s/ William G. BardelDirectorMarch 1, 2017February 25, 2020
William G. Bardel
/s/ Carin M. BarthDirectorMarch 1, 2017February 25, 2020
Carin M. Barth
/s/ D. Mark DeWalchDirectorMarch 1, 2017February 25, 2020
D. Mark DeWalch
/s/ Ricky J. HaeflingerDirectorMarch 1, 2017February 25, 2020
Ricky J. Haeflinger
/s/ Jerry V. Kyle, Jr.DirectorMarch 1, 2017February 25, 2020
Jerry V. Kyle, Jr.
/s/ Michael C. LinnDirectorMarch 1, 2017February 25, 2020
Michael C. Linn
/s/ John H. LongmaidDirectorMarch 1, 2017February 25, 2020
John H. Longmaid
/s/ William N. MathisDirectorMarch 1, 2017February 25, 2020
William N. Mathis
/s/ William E. RandallDirectorFebruary 25, 2020
William E. Randall
/s/ Alexander D. StuartDirectorMarch 1, 2017February 25, 2020
Alexander D. Stuart
/s/ Allison K. ThackerDirectorMarch 1, 2017February 25, 2020
Allison K. Thacker




70

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
BLACK STONE MINERALS, L.P.
 
F-2F-2
F-5F-5
F-6F-6
F-7F-7
F-8F-8
F-9F-9

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM




TheTo 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 sheetsheets of Black Stone Minerals, L.P. and subsidiaries (the “Partnership”) as of December 31, 2016,2019 and 2018, the related consolidated statements of operations, equity and cash flows for each of the year thenthree years in the period ended December 31, 2016. These2019, and the related notes (collectively referred to as the “consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States)statements”). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall 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 consolidated financial position of Black Stone Minerals, L.P. and subsidiariesthe Partnership at December 31, 2016,2019 and 2018, and the consolidated results of theirits operations and theirits cash flows for each of the year thenthree years in the period ended December 31, 2016,2019, 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"), Black Stone Minerals, L.P.’sthe Partnership’s internal control over financial reporting as of December 31, 2016,2019, 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 March 1, 2017February 25, 2020, 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.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Depreciation, Depletion and Amortization (“DD&A”) of Oil and Natural Gas Properties
Description of the MatterAt December 31, 2019, the net book value of the Partnership’s oil and natural gas properties was $1,432 million, and depreciation, depletion and amortization (“DD&A”) expense was $109 million for the year then ended. As discussed in Note 2, under the successful efforts method of accounting, DD&A is recorded based on the units-of-production method. Capitalized development costs are amortized on the basis of proved developed reserves, as estimated by independent petroleum engineers. Leasehold acquisition costs and costs to acquire proved properties are amortized on the basis of total proved reserves, also estimated by independent petroleum engineers. Proved oil and natural gas reserves are 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. Significant judgment is required by the independent petroleum engineers in evaluating geological and engineering data used to estimate oil and natural gas reserves. Estimating reserves also requires the selection of inputs, including oil and natural gas price assumptions, future operating and capital costs assumptions and tax rates by jurisdiction, among others. Because of the complexity involved in estimating oil and natural gas reserves, management used independent petroleum engineers to prepare the oil and natural gas reserve estimates as of December 31, 2019.

F-2

Auditing the Partnership’s DD&A calculation is especially complex because of the use of the work of the independent petroleum engineers and the evaluation of management’s determination of the inputs described above used by the engineers in estimating proved oil and natural gas reserves.
How We Addressed the Matter in Our AuditWe obtained an understanding, evaluated the design and tested the operating effectiveness of the Partnership’s controls over its process to calculate DD&A, including management’s controls over the completeness and accuracy of the financial data provided to the engineers for use in estimating proved oil and natural gas reserves.
Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the independent petroleum engineers used to prepare the oil and natural gas reserve estimates. In addition, in assessing whether we can use the work of the independent petroleum engineers we evaluated the completeness and accuracy of the financial data and inputs described above used by the engineers in estimating proved oil and natural gas reserves by agreeing them to source documentation and we identified and evaluated corroborative and contrary evidence. We also tested the mathematical accuracy of the DD&A calculations, including comparing the proved oil and natural gas reserve amounts used to the Partnership’s reserve report.
Revenues from Contracts with Customers Accrual
Description of the MatterAt December 31, 2019, the Partnership had $71 million in accrued revenues from contracts with customers. As discussed in Note 2, the Partnership records revenue in the month production is delivered to the purchaser. As a non-operator, the Partnership has limited visibility into the timing of when new wells start producing and production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, the Partnership is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded within the Accounts receivable line item in the consolidated balance sheets.
Auditing the Partnership’s revenues from contracts with customers accrual is complex and judgmental because it involves the evaluation of subjective management inputs and assumptions used in the calculation. Additionally, auditing the accrual is challenging because the Partnership’s mineral and royalty interests include ownership in a significant amount of producing wells.
How We Addressed the Matter in Our AuditWe obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Partnership’s process to estimate the revenues from contracts with customers accrual, including management’s controls over the significant assumptions and completeness and accuracy of the data used in the calculation.
Our audit procedures included, among others, testing the significant inputs to the calculation of the revenues from contracts with customers accrual by agreeing them to source documentation and evaluating corroborative and contrary evidence. These inputs included oil and natural gas price assumptions and production estimates. Additionally, we assessed the completeness and accuracy of the revenues from contracts with customers accrual through analytic procedures, and we assessed the historical accuracy of the revenues from contracts with customers accrual through lookback procedures.

/s/ Ernst & Young LLP

We have served as the Partnership’s auditor since 2016.
Houston, TXTexas
March 1, 2017February 25, 2020





F-3













REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM





TheTo 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, 2016,2019, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the, ("the COSO criteria)criteria”). In our opinion, Black Stone Minerals, L.P. and subsidiaries’subsidiaries ("the Partnership”) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, 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, 2019 and 2018, the related consolidated statements of operations, equity and cash flows for each of the three years in the period ended December 31, 2019, and the related notes and our report dated February 25, 2020, 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 regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).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.
In our opinion, Black Stone Minerals, L.P. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Black Stone Minerals, L.P. and subsidiaries as of December 31, 2016, and the related consolidated statements of operations, equity and cash flows for the year then ended December 31, 2016 of Black Stone Minerals, L.P. and subsidiaries and our report dated March 1, 2017 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Houston, TX
March 1, 2017







REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


The Partners of
Black Stone Minerals, L.P.
Houston, Texas
We have audited the accompanying consolidated balance sheet of Black Stone Minerals, L.P. and subsidiaries (the “Partnership”) as of December 31, 2015, and the related consolidated statements of operations, equity, and cash flows for each of the two years in the period ended December 31, 2015.  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 audits.February 25, 2020
We conducted our audits 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 audits 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 audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Black Stone Minerals, L.P. and subsidiaries at December 31, 2015, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America.
/s/ BDO USA, LLP
Houston, Texas
F-4
March 8, 2016




BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands)
 As of December 31,
 20192018
ASSETS
CURRENT ASSETS  
Cash and cash equivalents$8,119  $5,414  
Accounts receivable78,214  113,148  
Commodity derivative assets14,790  37,970  
Prepaid expenses and other current assets1,168  1,001  
TOTAL CURRENT ASSETS102,291  157,533  
PROPERTY AND EQUIPMENT      
Oil and natural gas properties, at cost, using the successful efforts method of accounting, includes unproved properties of $1,073,447 and $1,063,883 at December 31, 2019 and 2018, respectively3,302,340  3,441,188  
Accumulated depreciation, depletion, amortization, and impairment(1,870,412) (1,865,692) 
Oil and natural gas properties, net1,431,928  1,575,496  
Other property and equipment, net of accumulated depreciation of $11,622 and $11,048 at December 31, 2019 and 2018, respectively2,300  385  
NET PROPERTY AND EQUIPMENT1,434,228  1,575,881  
DEFERRED CHARGES AND OTHER LONG-TERM ASSETS8,689  16,710  
TOTAL ASSETS$1,545,208  $1,750,124  
LIABILITIES, MEZZANINE EQUITY, AND EQUITY      
CURRENT LIABILITIES      
Accounts payable$5,309  $4,149  
Accrued liabilities22,702  60,089  
Commodity derivative liabilities159  —  
Other current liabilities1,633  528  
TOTAL CURRENT LIABILITIES29,803  64,766  
LONG-TERM LIABILITIES      
Credit facility394,000  410,000  
Accrued incentive compensation2,110  1,813  
Commodity derivative liabilities18  —  
Asset retirement obligations15,653  14,948  
Other long-term liabilities6,820  55,973  
TOTAL LIABILITIES448,404  547,500  
COMMITMENTS AND CONTINGENCIES (Note 11)
MEZZANINE EQUITY      
Partners' equity — Series B cumulative convertible preferred units, 14,711 and 14,711 units outstanding at December 31, 2019 and 2018, respectively298,361  298,361  
EQUITY      
Partners' equity — general partner interest—  —  
Partners' equity — common units, 205,960 and 108,363 units outstanding at December 31, 2019 and 2018, respectively798,443  714,823  
Partners' equity — subordinated units, 0 and 96,329 units outstanding at December 31, 2019 and 2018, respectively—  189,440  
TOTAL EQUITY798,443  904,263  
TOTAL LIABILITIES, MEZZANINE EQUITY, AND EQUITY$1,545,208  $1,750,124  
 As of December 31,
 2016 2015
ASSETS 
  
CURRENT ASSETS 
  
Cash and cash equivalents$9,772
 $13,233
Accounts receivable68,181
 41,246
Commodity derivative assets—
 48,260
Prepaid expenses and other current assets1,036
 856
TOTAL CURRENT ASSETS78,989
 103,595
PROPERTY AND EQUIPMENT 
  
Oil and natural gas properties, at cost, using the successful efforts method of accounting, includes unproved properties of $605,736 and $524,563 at December 31, 2016 and 2015, respectively2,697,073
 2,482,211
Accumulated depreciation, depletion, amortization, and impairment(1,652,930) (1,543,796)
Oil and natural gas properties, net1,044,143
 938,415
Other property and equipment, net of accumulated depreciation of $14,327 and $14,660 at December 31, 2016 and 2015, respectively528
 179
NET PROPERTY AND EQUIPMENT1,044,671
 938,594
DEFERRED CHARGES AND OTHER LONG-TERM ASSETS5,167
 19,247
TOTAL ASSETS$1,128,827
 $1,061,436
LIABILITIES, MEZZANINE EQUITY AND EQUITY 
  
CURRENT LIABILITIES 
  
Accounts payable$4,142
 $5,036
Accrued liabilities50,952
 58,003
Commodity derivative liabilities16,237
 —
TOTAL CURRENT LIABILITIES71,331
 63,039
LONG-TERM LIABILITIES 
  
Credit facility316,000
 66,000
Accrued incentive compensation1,485
 7,902
Commodity derivative liabilities482
 —
Deferred revenue518
 3,257
Asset retirement obligations13,350
 10,585
TOTAL LIABILITIES403,166
 150,783
COMMITMENTS AND CONTINGENCIES (Note 12)

 

MEZZANINE EQUITY 
  
Partners' equity - redeemable preferred units, 53 and 77 units outstanding at December 31, 2016 and 2015, respectively54,015
 79,162
EQUITY 
  
Partners' equity - general partner interest—
 —
Partners' equity - common units, 95,721 and 96,162 units outstanding at December 31, 2016 and 2015, respectively489,023
 574,648
Partners' equity - subordinated units, 95,164 and 95,057 units outstanding at December 31, 2016 and 2015, respectively181,602
 255,699
Noncontrolling interests1,021
 1,144
TOTAL EQUITY671,646
 831,491
TOTAL LIABILITIES, MEZZANINE EQUITY AND EQUITY$1,128,827
 $1,061,436
The accompanying notes to consolidated financial statements are an integral part of these financial statements.


F-5

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per unit amounts)
Year Ended December 31, Year Ended December 31,
2016 2015 2014 201920182017
REVENUE 
  
  
REVENUE   
Oil and condensate sales$142,382
 $163,538
 $257,390
Oil and condensate sales$263,678  $310,278  $169,728  
Natural gas and natural gas liquids sales122,836
 116,018
 207,456
Natural gas and natural gas liquids sales199,265  248,243  190,967  
Lease bonus and other incomeLease bonus and other income29,833  36,216  42,062  
Revenue from contracts with customersRevenue from contracts with customers492,776  594,737  402,757  
Gain (loss) on commodity derivative instruments(36,464) 90,288
 37,336
Gain (loss) on commodity derivative instruments(4,955) 14,831  26,902  
Lease bonus and other income32,079
 23,080
 46,139
TOTAL REVENUE260,833
 392,924
 548,321
TOTAL REVENUE487,821  609,568  429,659  
OPERATING (INCOME) EXPENSE 
  
  
OPERATING (INCOME) EXPENSE         
Lease operating expense18,755
 21,583
 21,233
Lease operating expense17,665  18,415  17,280  
Production costs and ad valorem taxes35,464
 35,767
 49,575
Production costs and ad valorem taxes60,533  64,364  47,474  
Exploration expense645
 2,592
 631
Exploration expense397  7,943  618  
Depreciation, depletion and amortization102,487

104,298

111,962
Impairment of oil and natural gas properties6,775

249,569

117,930
Depreciation, depletion, and amortizationDepreciation, depletion, and amortization109,584  122,653  114,534  
General and administrative73,139
 77,175
 62,765
General and administrative63,353  76,712  77,574  
Accretion of asset retirement obligations892

1,075

1,060
Accretion of asset retirement obligations1,117  1,103  1,026  
(Gain) loss on sale of assets, net(4,793) (4,873) 32
(Gain) loss on sale of assets, net—  (3) (931) 
Other expense—
 1,593
 1,424
TOTAL OPERATING EXPENSE233,364
 488,779
 366,612
TOTAL OPERATING EXPENSE252,649  291,187  257,575  
INCOME (LOSS) FROM OPERATIONS27,469
 (95,855) 181,709
INCOME (LOSS) FROM OPERATIONS235,172  318,381  172,084  
OTHER INCOME (EXPENSE) 
  
  
OTHER INCOME (EXPENSE)         
Interest and investment income656
 58
 28
Interest and investment income159  183  49  
Interest expense(7,547) (6,418) (13,509)Interest expense(21,435) (20,756) (15,694) 
Other income (expense)(390) 910
 959
Other income (expense)472  (2,248) 714  
TOTAL OTHER EXPENSE(7,281) (5,450) (12,522)TOTAL OTHER EXPENSE(20,804) (22,821) (14,931) 
NET INCOME (LOSS)20,188
 (101,305) 169,187
NET INCOME (LOSS)214,368  295,560  157,153  
NET INCOME (LOSS) ATTRIBUTABLE TO PREDECESSOR—
 (450) (169,187)
NET INCOME (LOSS) ATTRIBUTABLE TO NONCONTROLLING INTERESTS SUBSEQUENT TO INITIAL PUBLIC OFFERING12
 1,260
 —
DISTRIBUTIONS ON REDEEMABLE PREFERRED UNITS SUBSEQUENT TO INITIAL PUBLIC OFFERING(5,763) (7,522) —
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS SUBSEQUENT TO INITIAL PUBLIC OFFERING$14,437
 $(108,017) $—
ALLOCATION OF INCOME (LOSS) SUBSEQUENT TO INITIAL PUBLIC OFFERING ATTRIBUTABLE TO: 
  
  
Net (income) loss attributable to noncontrolling interestsNet (income) loss attributable to noncontrolling interests—  (24) 34  
Distributions on Series A redeemable preferred unitsDistributions on Series A redeemable preferred units—  (25) (3,117) 
Distributions on Series B cumulative convertible preferred unitsDistributions on Series B cumulative convertible preferred units(21,000) (21,000) (1,925) 
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITSNET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS$193,368  $274,511  $152,145  
ALLOCATION OF NET INCOME (LOSS):ALLOCATION OF NET INCOME (LOSS):         
General partner interest$—
 $—
  
General partner interest$—  $—  $—  
Common units24,669
 (54,326)  
Common units169,375  154,662  98,389  
Subordinated units(10,232) (53,691)  
Subordinated units23,993  119,849  53,756  
$14,437
 $(108,017)  
 $193,368  $274,511  $152,145  
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT: 
  
  
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:         
Per common unit (basic)$0.26
 $(0.56)  
Per common unit (basic)$1.01  $1.46  $1.01  
Weighted average common units outstanding (basic)96,073
 96,182
  
Weighted average common units outstanding (basic)168,230  106,064  97,400  
Per subordinated unit (basic)$(0.11) $(0.56)  
Per subordinated unit (basic)$0.64  $1.25  $0.56  
Weighted average subordinated units outstanding (basic)95,138
 95,057
  
Weighted average subordinated units outstanding (basic)37,740  96,099  95,149  
Per common unit (diluted)$0.26
 $(0.56)  Per common unit (diluted)$1.01  $1.45  $1.01  
Weighted average common units outstanding (diluted)96,243
 96,182
  Weighted average common units outstanding (diluted)168,376  121,264  97,400  
Per subordinated unit (diluted)$(0.11) $(0.56)  Per subordinated unit (diluted)$0.64  $1.25  $0.56  
Weighted average subordinated units outstanding (diluted)95,138
 95,057
  Weighted average subordinated units outstanding (diluted)37,740  96,346  95,149  
DISTRIBUTIONS DECLARED AND PAID SUBSEQUENT TO INITIAL PUBLIC OFFERING: 
  
  
Per common unit$1.10
 $0.424
  
Per subordinated unit$0.74
 $0.424
  
The accompanying notes to consolidated financial statements are an integral part of these financial statements.


F-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, 2013164,133
 $716,403
 —
 —
 $—
 $—
 $—
 $716,403
Conversion of Predecessor redeemable preferred units15
 221
 —
 —
 —
 —
 —
 221
Issuance of Predecessor units for acquisition of oil and natural gas properties104
 2,258
 —
 —
 —
 —
 —
 2,258
Repurchase of Predecessor units(239) (5,199) —
 —
 —
 —
 —
 (5,199)
Restricted Predecessor units granted, net of forfeitures471
 —
 —
 —
 —
 —
 —
 —
Equity-based compensation—
 11,340
 —
 —
 —
 —
 —
 11,340
Distributions to Predecessor unitholders and non-controlling interests—
 (225,273) —
 —
 —
 —
 —
 (225,273)
Net income attributable to Predecessor—
 169,187
 —
 —
 —
 —
 —
 169,187
Distributions on Predecessor redeemable preferred units—
 (15,720) —
 —
 —
 —
 —
 (15,720)
BALANCE AT DECEMBER 31, 2014164,484
 653,217
 —
 —
 —
 —
 —
 653,217
Conversion of Predecessor redeemable preferred units2,750
 39,240
 —
 —
 —
 —
 —
 39,240
Restricted Predecessor units granted562
 —
 —
 —
 —
 —
 —
 —
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 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
Restricted units granted, net of forfeitures—
 —
 993
 (56) —
 —
 —
 —
Equity-based compensation—
 —
 —
 —
 21,022
 2,823
 —
 23,845
Conversion of redeemable preferred units—
 —
 184
 241
 2,625
 3,439
 —
 6,064
Repurchases of common and subordinated units—
 —
 (1,618) (78) (27,436) —
 —
 (27,436)
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 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
 
Common
units
Subordinated
units
Partners'
equity—
common
units
Partners'
equity—
subordinated
units
Noncontrolling
interests
Total
equity
BALANCE AT DECEMBER 31, 201695,721  95,164  $489,023  $181,602  $1,021  $671,646  
Conversion of Series A redeemable preferred units201  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 costs2,002  —  32,458  —  —  32,458  
Issuance of common units for property acquisitions4,348  —  71,723  —  —  71,723  
Restricted units granted, net of forfeitures1,630  —  —  —  —  —  
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, 2017103,456  95,388  $603,116  $164,138  $867  $768,121  
Conversion of Series A redeemable preferred units736  964  10,498  13,750  —  24,248  
Repurchases of common and subordinated units(623) (23) (10,879) (342) —  (11,221) 
Purchase of noncontrolling interests—  —  (1,026) —  (680) (1,706) 
Issuance of common units, net of offering costs2,244  —  40,537  —  —  40,537  
Issuance of common units for property acquisitions1,234  —  22,657  —  —  22,657  
Restricted units granted, net of forfeitures1,316  —  —  —  —  —  
Equity-based compensation—  —  40,733  219  —  40,952  
Distributions—  —  (141,777) (108,174) (211) (250,162) 
Charges to partners' equity for accrued distribution equivalent rights—  —  (3,698) —  —  (3,698) 
Distributions on Series A redeemable preferred units—  —  (13) (12) —  (25) 
Distributions on Series B cumulative convertible preferred units—  —  (21,000) —  —  (21,000) 
Net income (loss)—  —  175,675  119,861  24  295,560  
BALANCE AT DECEMBER 31, 2018108,363  96,329  $714,823  $189,440  $—  $904,263  
Conversion of subordinated units96,329  (96,329) 142,149  (142,149) —  —  
Repurchases of common and subordinated units(966) —  (16,287) —  —  (16,287) 
Issuance of common units, net of offering costs—  —  (43) —  —  (43) 
Issuance of common units for property acquisitions57  —  943  —  —  943  
Restricted units granted, net of forfeitures2,177  —  —  —  —  —  
Equity-based compensation—  —  23,490  —  —  23,490  
Distributions—  —  (233,155) (71,284) —  (304,439) 
Charges to partners' equity for accrued distribution equivalent rights—  —  (2,852) —  —  (2,852) 
Distributions on Series B cumulative convertible preferred units—  —  (21,000) —  —  (21,000) 
Net income (loss)—  —  190,375  23,993  —  214,368  
BALANCE AT DECEMBER 31, 2019205,960  —  $798,443  $—  $—  $798,443  
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,
 201920182017
CASH FLOWS FROM OPERATING ACTIVITIES   
Net income (loss)$214,368  $295,560  $157,153  
Adjustments to reconcile net income (loss) to net cash provided by operating activities:         
Depreciation, depletion, and amortization109,584  122,653  114,534  
Accretion of asset retirement obligations1,117  1,103  1,026  
Amortization of deferred charges1,041  905  877  
(Gain) loss on commodity derivative instruments4,955  (14,831) (26,902) 
Net cash (paid) received on settlement of commodity derivative instruments27,862  (38,235) 15,211  
Equity-based compensation20,484  30,134  33,044  
Exploratory dry hole expense3  6,785  —  
Deferred rent—  1,283  —  
(Gain) loss on sale of assets, net—  (3) (931) 
Changes in operating assets and liabilities:   
Accounts receivable35,044  (31,531) (6,084) 
Prepaid expenses and other current assets(167) 210  (177) 
Accounts payable, accrued liabilities, and other(1,191) 11,474  (5,671) 
Settlement of asset retirement obligations(380) (129) (228) 
NET CASH PROVIDED BY OPERATING ACTIVITIES412,720  385,378  281,852  
CASH FLOWS FROM INVESTING ACTIVITIES         
Acquisitions of oil and natural gas properties(43,051) (124,081) (425,667) 
Additions to oil and natural gas properties(64,782) (166,970) (55,842) 
Additions to oil and natural gas properties leasehold costs(980) (6,263) (2,806) 
Purchases of other property and equipment(2,488) (21) (207) 
Proceeds from the sale of oil and natural gas properties1,174  9,009  11,102  
Proceeds from farmouts of oil and natural gas properties61,504  124,522  19,171  
NET CASH USED IN INVESTING ACTIVITIES(48,623) (163,804) (454,249) 
CASH FLOWS FROM FINANCING ACTIVITIES         
Proceeds from issuance of common units, net of offering costs(43) 40,537  32,458  
Proceeds from issuance of Series B cumulative convertible preferred units, net of offering costs—  —  293,469  
Distributions to common and subordinated unitholders(304,439) (250,121) (194,799) 
Distributions to Series A redeemable preferred unitholders—  (690) (3,777) 
Distributions to Series B cumulative convertible preferred unitholders(21,000) (17,675) —  
Distributions to noncontrolling interests—  (211) (120) 
Distributions equivalents paid(2,981) —  —  
Redemption of Series A redeemable preferred units—  (2,115) (19,704) 
Repurchases of common and subordinated units(16,929) (10,579) (8,185) 
Purchase of noncontrolling interests—  (1,706) —  
Borrowings under credit facility334,500  373,500  292,500  
Repayments under credit facility(350,500) (351,500) (220,500) 
Debt issuance costs and other—  (1,242) (3,075) 
NET CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES(361,392) (221,802) 168,267  
NET CHANGE IN CASH AND CASH EQUIVALENTS2,705  (228) (4,130) 
Cash and cash equivalents — beginning of the year5,414  5,642  9,772  
Cash and cash equivalents — end of the year$8,119  $5,414  $5,642  
SUPPLEMENTAL DISCLOSURE         
Interest paid$20,470  $19,761  $14,761  
 Year Ended December 31,
 2016 2015 2014
CASH FLOWS FROM OPERATING ACTIVITIES 
  
  
Net income (loss)$20,188
 $(101,305) $169,187
Adjustments to reconcile net income (loss) to net cash provided by operating activities: 
  
  
Depreciation, depletion, and amortization102,487
 104,298
 111,962
Impairment of oil and natural gas properties6,775
 249,569
 117,930
Accretion of asset retirement obligations892
 1,075
 1,060
Amortization of deferred charges871
 935
 965
(Gain) loss on commodity derivative instruments36,464
 (90,288) (37,336)
Net cash received (paid) on settlement of commodity derivative instruments44,789
 63,225
 (1,947)
Equity-based compensation43,138
 18,000
 11,340
(Gain) loss on sale of assets, net(4,793) (4,873) 32
Changes in operating assets and liabilities: 
  
  
Accounts receivable(29,759) 33,586
 17,210
Prepaid expenses and other current assets(180) 95
 453
Accounts payable and accrued liabilities(23,029) 11,221
 8,003
Deferred revenue(870) (660) (2,589)
Settlement of asset retirement obligations(317) (143) (145)
NET CASH PROVIDED BY OPERATING ACTIVITIES196,656
 284,735
 396,125
CASH FLOWS FROM INVESTING ACTIVITIES 
  
  
Additions to oil and natural gas properties(80,179) (54,244) (74,201)
Purchase of other property and equipment(425) (181) (827)
Proceeds from the sale of oil and natural gas properties198
 25,705
 19,470
Acquisitions of oil and natural gas properties(141,136)
(62,278)
(45,552)
NET CASH USED IN INVESTING ACTIVITIES(221,542) (90,998) (101,110)
CASH FLOWS FROM FINANCING ACTIVITIES 
  
  
Proceeds from issuance of common units of Black Stone Minerals, L.P., net of
   offering costs
—
 399,087
 (7,587)
Borrowings under senior line of credit349,000
 245,600
 230,000
Repayments under senior line of credit(99,000) (573,600) (287,000)
Distributions to Predecessor unitholders—
 (126,383) (224,926)
Distributions to Black Stone Minerals, L.P. common and subordinated unitholders(175,943) (81,087) —
Distributions to preferred unitholders(6,385) (13,578) (15,724)
Distributions to noncontrolling interests(111) (208) —
Redemption of redeemable preferred units(18,461) (40,747) —
Repurchases of Predecessor units—
 (3,015) (5,199)
Debt issuance costs(239) (1,376) —
Note receivable-officers—
 —
 101
Repurchase of common and subordinate units(27,436) —
 —
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES21,425
 (195,307) (310,335)
NET CHANGE IN CASH AND CASH EQUIVALENTS(3,461) (1,570) (15,320)
CASH AND CASH EQUIVALENTS - beginning of the year13,233
 14,803
 30,123
CASH AND CASH EQUIVALENTS - end of the year$9,772
 $13,233
 $14,803
SUPPLEMENTAL DISCLOSURE     
Interest paid$6,535
 $5,478
 $12,754
NON-CASH ACTIVITIES     
Accrued Predecessor distributions payable$—
 $(53,248) $347
Conversion of redeemable preferred units$(6,064) $(39,240) $(221)
Accrued distributions payable for redeemable preferred units$(1,324) $(2,016) $(4)
Property additions and acquisitions financed through accounts payable and accrued liabilities$26,553
 $21,496
 $14,130
Public offering costs capitalized and offset against proceeds from initial public offering$—
 $7,587
 $—
Asset retirement obligations incurred$2,009
 $272
 $2,505
Accrued distribution equivalent rights$847
 $159
 $—
Liabilities assumed as consideration for oil and natural gas properties acquired$—
 $—
 $7,000
Acquisition of oil and natural gas properties financed through issuance of Predecessor units$—
 $—
 $2,258
Deferred revenue (settled) assumed through acquisition of oil and natural gas properties$—
 $—
 $(2,657)
The accompanying notes to consolidated financial statements are an integral part of these financial statements.

F-8
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




NOTE 1—1 — BUSINESS AND BASIS OF PRESENTATION
Description of the business: 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. 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”) ownthat owns oil and natural gas mineral interests in the United States. In connection with the IPO, BSMC was merged into a wholly owned subsidiary of BSM, 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 preferred units of BSM at a conversion ratio of one to one. The merger is 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 minerals interests, which make up the vast majority of the asset base, thebase. 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 most41 states in the continental United States ("U.S."), including all of the major onshore oil and natural gas producing basins spread across 41 states and 61 onshore oil and natural gas producing basins of the continental U.S.basins. The Partnership also owns non-operated working interests in certain oil and natural gas properties. On May 6, 2015, the Partnership completed its initial public offering (the "IPO") of 22,500,000 common units representing limited partner interests. The Partnership's common units trade on the New York Stock Exchange under the symbol "BSM."
Basis of presentation: Presentation
The accompanying audited consolidated financial statements of the Partnership have been prepared in accordance with generally accepted accounting principles (“GAAP”) in the United StatesU.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.Partnership, which also includes the results of the Noble Acquisition (as defined below) for the period from November 28, 2017 through December 31, 2019, as discussed in Note 4 – Oil and Natural Gas Properties.
In the opinion of management, all 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 consolidated financial statements reflect all normal recurring adjustments that, in the opinion of management, are necessary for a fair presentation.
Certain reclassifications have been made to the prior periods presented to conform to the current period financial statement presentation. The reclassifications have no effect on the consolidated financial position, results of operations, or cash flows of the Partnership.
The Partnership evaluates the significant terms of its investments to determine the method of accounting to be applied to each respective investment. Investments in which the Partnership has less than a 20% ownership interest and does not have control or exercise significant influence are accounted for under theusing fair value or cost method. The Partnership’s cost method investmentminus impairment if fair value is included in deferred charges and other long-term assets in the consolidated balance sheets.not readily determinable. Investments in which the Partnership exercises control are consolidated, and the noncontrolling interests of such investments, which are not attributable directly or indirectly to the Partnership, are presented as a 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.
Segment reporting: 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.
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS




NOTE 2—2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of estimates: 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, and theas well as reported amounts of revenues and expenses duringfor the reporting periods.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
F-9
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 estimateestimates 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, asset retirement obligation (“ARO”) liabilities, 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 or oil 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: Cash Equivalents
The Partnership considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.
Concentration of credit risk: Financial instruments that potentially subject the Partnership to credit risk consist principally of cash and cash equivalent balances, 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 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’s customer base is made up of its lessees, which are primarily major integrated and international oil and natural gas companies and other operators, though the Partnership’s credit risk may extend to the eventual purchasers of oil and natural gas produced from the Partnership’s properties. 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 8 – Significant Customers for further discussion. Derivative instruments may expose the Partnership to credit risk. However, the Partnership monitors the creditworthiness of its counterparties.Accounts Receivable
Accounts receivable: The Partnership’s accounts receivable balance results primarily from operators’ sales of oil and natural gas to their customers. Accounts receivable isare 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.
Derivatives and financial instruments: The following table presents information about the Partnership's accounts receivable:
December 31,
20192018
(in thousands)
Accounts receivable:
Revenues from contracts with customers$71,022  $107,804  
Other7,192  5,344  
Total accounts receivable$78,214  $113,148  
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 commodity price risk associated with its operations, the Partnership uses commodity derivative financial instruments. From time to time, such instruments may include variable–to-fixed-pricevariable-to-fixed-price swaps, costless collars, fixed-price contracts, and other contractual arrangements. The Partnership does not enter into derivative instruments for speculative purposes.
Derivative instruments are recognized at fair value. If a right of offset exists under master netting arrangements and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on the consolidated balance sheet.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 derivativesderivative instruments are recognized on a net basis in the accompanying consolidated statements of operations within gainGain (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.
F-10
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



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.

OilThe 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 properties: 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. Exploration dry holes are charged to expense when it is determined that no commercial reserves exist. Other exploratory costs, including annual delay rentalsAcquisitions of proved oil and geological and geophysical costs, are expensed when incurred. Acquired mineral and royalty interestsnatural gas properties and working interests are generally considered business combinations and are recorded at costtheir estimated fair value as of the acquisition date. Acquisitions that consist of all or substantially all unproved oil and natural gas properties are generally considered asset acquisitions and are recorded at the time of acquisition.cost.
The costs of unproved leaseholdsleasehold and non-producing mineral interests are capitalized as unproved properties pending the results of exploration and leasing efforts. As unproved leaseholdsproperties are determined to be proved,productive, the related costs are transferred to proved oil and natural gas properties. Unproved and non-producing propertyThe 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 assessed periodically, on a property-by-property basis, and an impairment loss is recognized to the extent, if any, the recorded valueexpensed. In some circumstances, it may be uncertain whether proved commercial reserves have been discovered when drilling has been impaired. Mineral interestscompleted.  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 assessedexpensed when incurred.
Oil and natural gas properties are grouped in accordance with the Extractive Industries – Oil and Gas Topic of the Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC").  The basis for impairment when facts and circumstances indicate that their carrying value may not be recoverable. This assessmentgrouping is performed by comparing carrying valuesa reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field, which the Partnership also refers to valuation estimates and impairment is recognized to the extent that book value exceeds estimated recoverable value. Any impairment will generally be based on geographic or geologic data and our estimated future cash flows related to our properties.as a depletable unit.
As exploration and development work progresses and the reserves associated with the Partnership’s oil and natural gas properties become proven,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. AcquisitionCapitalized 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, and capitalized development costs are amortized on the basis of proved developed reserves.undeveloped. Proved reserves are estimated quantities of oil and natural gas that can be estimatedwhich geological and engineering data demonstrate with reasonable certainty to be economically producible from a given date forward,commercially recoverable in future years from known reservoirs under existing economic conditions,and operating methods, and government regulations.conditions. DD&A expense related to the Partnership’s producing oil and natural gas properties was $102.4$109.0 million, $102.7$122.5 million, and $109.9$114.3 million for the years ended December 31, 2016, 2015,2019, 2018, and 2014,2017, respectively.
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 theits 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, operating costs, future capital expenditures, and a risk-adjusted discount rate.
Impairment There was 0 impairment of proved oil and natural gas properties was $4.9 million, $127.8 million and $117.9 million for the years ended December 31, 2016, 2015,2019, 2018, and 2014, respectively. The2017.
Unproved properties are also assessed for impairment primarily resulted from declines in future expected realizable net cash flows. The charges are included inperiodically on a depletable unit basis when facts and circumstances indicate that the carrying value may not be recoverable, at which point an impairment of oil and natural gas properties onloss is recognized to the consolidated statements of operations and reflected inextent the net book
F-11
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

carrying value of oil and natural gas properties.
exceeds the estimated recoverable value. The carrying value of unproved properties, including unleased mineral rights, is periodically assessed for impairment usingdetermined based on management’s assessment of fair value. Thevalue using factors used to determine fair value are similar to those previously noted for proved properties. Impairmentproperties, as well as geographic and geologic data. There was 0 impairment of unproved properties was $1.9 million and $121.8 million for the years ended December 31, 20162019, 2018, and 2015, respectively. There was no impairment of unproved properties for the year ended December 31, 2014.2017.
Upon the sale of a complete fields of depreciable or depletable property,unit, the book value thereof, less proceeds or salvage value, is charged to income. OnUpon 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.&A, unless doing so would significantly alter the DD&A rate of the depletable unit, in which case a gain or loss would be recorded.
Other propertyProperty and equipment: 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 three3 years to seven7 years. Depreciation and amortization expense totaled $0.1$0.6 million, $1.6$0.2 million, and $2.1$0.2 million for the years ended December 31, 2016, 2015,2019, 2018, and 2014,2017, respectively.
Repairs and maintenance: 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:Liabilities
Accrued liabilities consisted of the following as of December 31, 2016 and 2015:following:
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
 December 31,
 20192018
 (in thousands)
Accrued liabilities:
Accrued capital expenditures$2,019  $32,945  
Accrued incentive compensation9,057  16,109  
Accrued property taxes8,131  5,822  
Accrued other3,495  5,213  
Total accrued liabilities$22,702  $60,089  
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Debt Issuance Costs

 As of December 31,
 2016 2015
Accrued liabilities: 
  
Accrued capital expenditures$17,775
 $20,494
Accrued incentive compensation20,898
 16,554
Accrued legal—
 7,000
Accrued severance—
 3,889
Accrued property taxes3,175
 3,699
Accrued other9,104
 6,367
TOTAL ACCRUED LIABILITIES$50,952
 $58,003
    
Debt issuance costs: Debt issuance costs consist of costs directly associated with obtaining credit with financial institutions. These costs 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 issueissuance costs are expensed in the year when the associated debt instrument is terminated. Amortization expense for debt issueissuance costs was $0.9$1.0 million, $0.9 million, and $1.0$0.9 million for the years ended December 31, 2016, 2015,2019, 2018, and 2014,2017, respectively, and is included in interest expense in the consolidated statements of operations.
Asset retirement obligations: 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 and equipment.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 productionunits-of-production consistent with the related asset.
Revenue
Leases
On January 1, 2019, the Partnership adopted ASC 842, Leases, using the modified retrospective method. ASC 842 requires the recognition: of lease assets and lease liabilities by lessees for those leases classified as operating leases under the previous
F-12
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

guidance. The Partnership recognizes revenueused January 1, 2019, the beginning of the period of adoption, as its date of initial application. The Partnership elected the package of practical expedients upon transition which will retain the lease classification for leases and any unamortized initial direct costs that existed prior to the adoption of the standard.

The adoption of the standard resulted in the recognition of operating lease right-of-use (“ROU”) assets and operating lease liabilities on the consolidated balance sheet as of January 1, 2019. ROU assets and operating lease liabilities were less than 1% of the Partnership's total assets as of December 31, 2019 and were not considered material to the Partnership. There was no related impact on the consolidated statement of operations. The standard had no impact on the Partnership’s debt covenant compliance under existing agreements.

The Partnership determines if an arrangement is a lease at inception by considering whether (1) explicitly or implicitly identified assets have been deployed in the agreement and (2) the Partnership obtains substantially all of the economic benefits from the use of that underlying asset and directs how and for what purpose the asset is used during the term of the agreement. Operating leases are included in Deferred charges and other long-term assets, Other current liabilities, and Other long-term liabilities in the consolidated balance sheets. As of December 31, 2019, none of the Partnership’s leases were classified as financing leases.

ROU assets represent the Partnership’s right to use an underlying asset for the lease term and operating lease liabilities represent the Partnership’s obligation to make lease payments arising from the lease. ROU assets are recognized at commencement date and consist of the present value of remaining lease payments over the lease term, initial direct costs, prepaid lease payments less any lease incentives. Operating lease liabilities are recognized at commencement date based on the present value of remaining lease payments over the lease term. The Partnership uses the implicit rate, when readily determinable, or its incremental borrowing rate based on the information available at commencement date to determine the present value of lease payments.

The lease terms may include periods covered by options to extend the lease when it is realized or realizablereasonably certain that the Partnership will exercise that option and earned. periods covered by options to terminate the lease when it is not reasonably certain that the Partnership will exercise that option. Lease expense for lease payments is recognized on a straight-line basis over the lease term. The Partnership made an accounting policy election to not recognize leases with terms of less than twelve months on the consolidated balance sheets and recognize those lease payments in the consolidated statements of operations on a straight-line basis over the lease term. In the event that the Partnership’s assumptions and expectations change, it may have to revise its ROU assets and operating lease liabilities.

Revenues are considered realized or realizablefrom Contracts with Customers

ASC 606, Revenue from Contracts with Customers, requires the Partnership to identify the distinct promised goods and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii)within a contract which represent separate performance obligations and determine the seller’stransaction price to allocate to the buyer is fixed or determinable, and (iv) collectability is reasonably assured.
performance obligations identified. The Partnership recognizes oiladopted ASC 606 using the modified retrospective method, which was applied to all existing contracts for which all (or substantially all) of the revenue had not been recognized under legacy revenue guidance as of the date of adoption, January 1, 2018.
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, 2016 and 2015. To the extent actual volumes and pricessales
Sales of oil and natural gas are unavailable for a given reporting period becauserecognized at the point control of timing or information not received from third parties, the expectedproduct is transferred to the customer and collectability of the sales volume and prices for these properties are estimated and recorded within accounts receivable in the accompanying consolidated balance sheets. Crude oilprice is reasonably assured. Oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. NaturalThe price the Partnership receives for natural gas contracts’ pricing provisions areis 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 onAs each unit of product represents a monthly basis.
Other sources of revenue received byseparate performance obligation and the consideration is variable as it relates to oil and natural gas prices, the Partnership includes mineralrecognizes revenue from oil and natural gas sales using the practical expedient for variable consideration in ASC 606.
Lease bonus and other income
The Partnership also earns revenue from lease bonuses and delay rentals. The Partnership generates lease bonus revenue by leasing its mineral interests to other exploration and production companies. TheA lease agreementsagreement represents the Partnership's contract with a customer and generally transfertransfers the rights to any oil or natural gas discovered, grantgrants the Partnership a right to a specified royalty interest, and requirerequires that drilling and completion operations commence within a specified time period. The Partnership recognizes such lease bonus revenue at which timeControl is transferred to the lease agreement has been executed, payment is determined to be collectable,lessee and the Partnership has satisfied its performance obligation when the lease agreement is
F-13
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

executed, such that revenue is recognized when the lease bonus payment is received. At the time the Partnership executes the lease agreement, the Partnership expects to receive the lease bonus payment within a reasonable time, though in no further obligation to refundcase more than one year, such that the payment.Partnership has not adjusted the expected amount of consideration for the effects of any significant financing component per the practical expedient in ASC 606. The Partnership also recognizes revenue from delay rentals to the extent drilling has not started within the specified period, payment has been collected,received, and the Partnership has no further obligation to refund the payment.
BLACK STONE MINERALS, L.P. AND SUBSIDIARIESProduction imbalances
NOTES TO CONSOLIDATED FINANCIAL STATEMENTSThe Partnership previously elected to utilize the entitlements method to account for natural gas production imbalances, which is no longer permitted under ASC 606. As of January 1, 2018, these amounts were de minimis.

Allocation of transaction price to remaining performance obligations

Oil and natural gas sales
The Partnership has utilized the practical expedient in ASC 606 which states the Partnership is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. As the Partnership has determined that each unit of product generally represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
Lease bonus and other income
Given that the Partnership does not recognize lease bonus or other income until a lease agreement has been executed, at which point its performance obligation has been satisfied, and payment is received, the Partnership does not record revenue for unsatisfied or partially unsatisfied performance obligations as of the end of the reporting period. Overall, there were no material changes in the timing of the satisfaction of the Partnership's performance obligations or the allocation of the transaction price to its performance obligations in applying the guidance in ASC 606 as compared to legacy GAAP.

Prior-period performance obligations
The Partnership records revenue in the month production is delivered to the purchaser. As a non-operator, the Partnership has limited visibility into the timing of when new wells start producing and production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, the Partnership is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded within the Accounts receivable line item in the accompanying consolidated balance sheets. The difference between the Partnership's estimates and the actual amounts received for oil and natural gas sales is recorded in the month that payment is received from the third party. For the years ended December 31, 2019 and 2018, revenue recognized in the reporting periods related to performance obligations satisfied in prior reporting periods was immaterial.
Income taxes: 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.
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 valueValue of financial instruments: 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, 2016
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BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2019 and 20152018 due to the short-term maturity of these instruments. See Note 6 – Fair Value MeasurementMeasurements for further discussion.
Incentive compensation: Compensation
Incentive compensation includes both equity-basedliability awards and liabilityequity-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-dategrant date fair values. Incentive compensation expense is charged to general and administrative expense.
Liability awards are awards that are expected to be settled in cash or an unknown number of common or subordinated units on their vesting dates. Liability awards are recorded as accrued liabilities based on the vested portion of the estimated fair value of the awards as of the grant date, which is subject to revision based on the impact of certain performance conditions associated with the incentive plans. The Partnership may also recognize liability awards as a result of repurchase options given
Incentive compensation expense is charged to the recipients participating in certain incentive plans.
Compensation expense for unit-based awards subsequent to the Partnership’s initial public offering is measured by the price of the unit at the measurement date, which is generally the date of grant, and is recognized in generalGeneral and administrative expense over the requisite service period. Prior to the initial public offering, the Predecessor was privately held and determining the fair value required the Predecessor to make complex and subjective judgments. The Board determined the fair value of the equity-based awards’ unit price prior to the Partnership’s initial public offering by considering various objective and subjective factors, along with input from management. To determine the fair value of the Predecessor, the Predecessor considered information provided by third-party consultants and relied on generally accepted valuation techniques, which included, but were not limited to, 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. These methods were dependent upon various assumptions to develop the estimates in the Predecessor’s operating results, commodity prices, and market-based discount rates. The Predecessor also considered publicly available information on comparable public companies and the Predecessor’s historical transactions and performance in making these estimates. The Predecessor’s limited partnership agreement contained an annual repurchase obligation of 1% of the outstanding units. An annual valuation of the Predecessor was required to establish a value basis for the repurchase obligation.  The Predecessor utilized the same valuation for repurchases and issuances of equity, if any, and as the basis for calculating the fair value of its equity awards under its long-term incentive plans.
New accounting pronouncements: The JOBS Act provides that an emerging growth company can delay adopting new or revised accounting standards until such time as those standards apply to private companies. We have irrevocably elected to “opt out” of this exemption and therefore will be subject to the same new or revised accounting standards as other public companies that are not emerging growth companies.
In May 2014, the Financial Accounting Standards Board (the “FASB”) issued an accounting standards update on a comprehensive new revenue recognition standard that will supersede Accounting Standards Codification (“ASC”) 605, Revenue Recognition. The new accounting guidance creates a framework under which an entity will allocate the transaction price to separate performance obligations and recognize revenue when each performance obligation is satisfied. 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 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
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


is applied only to the most current period presented in the financial statements with a cumulative catch-up as of the current period. In July 2015, the FASB decided to defer the original effective date by one year to be effective for annual reporting periods beginning after December 15, 2017 instead of December 15, 2016 for public entities, with early adoption permitted. The Partnership intends to use the modified retrospective adoption approach. Based on current evaluations to-date, the Partnership does not anticipate this new guidance will have a material impact on its consolidated financial statements. The Partnership is continuing to evaluate the disclosure requirements of this new guidance and does not plan on early adopting this guidance.
In February 2016, the FASB issued Accounting Standard Update (“ASU”) No. 2016-02, Leases (Topic 842), which requires lessees to recognize the lease assets and lease liabilities classified as operating leases on the balance sheet. The amendment will be effectiveconsolidated statements of operations. See Note 9 – Incentive Compensation for reporting periods beginning on or after December 15,additional discussion.
Recent Accounting Pronouncements

In August 2018, and early adoption is permitted. The Partnership is evaluating the impact that the new accounting guidance will have on its consolidated financial statements and related disclosures.
In March 2016, the FASB issued ASU No. 2016-09, Compensation – Stock Compensation2018-13, Fair Value Measurement (Topic 718): Improvements820), which will remove, modify, and add certain required disclosures on fair value measurements. As amended, Topic 820 will no longer require the disclosure of the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, the policy of timing of transfers between levels, and the valuation processes for Level 3 fair value measurements. In addition, certain modifications to employee share-based payment accounting, which includes provisions intended to simplify various aspects related to how share-based compensation payments are accounted for and presented in the financial statements. This amendmentcurrent disclosure requirements will be effective prospectively for reporting periods beginning on or after December 15, 2016, and early adoption is permitted. The Partnership is evaluating the impactmade, including clarifying that the new accounting guidance will have on its consolidated financial statements and related disclosures.
In August 2016,measurement uncertainty disclosure is to communicate information about the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments, to address diversityuncertainty 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 applicationmeasurement as of the predominance principle. Classificationreporting date. Certain disclosure requirements will also be added, including the range and weighted average of cash receiptssignificant unobservable inputs used to develop Level 3 fair value measurements. For certain unobservable inputs, an entity may disclose other quantitative information in place of the weighted average if the entity determines that other quantitative information would be a more reasonable and payments that have aspectsrational method to reflect the distribution of more than one class of cash flows shouldunobservable inputs used to develop Level 3 fair value measurements. The new standard will 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 amendments in this ASU are effective for public business entities for fiscal years beginning after December 15, 2017 and2019, including interim periods within those fiscal years. Early adoption is permitted. The Partnership is evaluatingdoes not believe the impact that the new accounting guidanceadoption of this update will have an impact on its consolidated financial statements and related disclosure.position, results of operations, or liquidity.


NOTE 3—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-interestworking 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.
The following table describes changes to the Partnership’s ARO liability:liability for the periods presented:
 
 For the year ended December 31,
 20192018
 (in thousands)
Beginning asset retirement obligations$15,475  $14,509  
Liabilities incurred209  245  
Liabilities settled(1,073) (129) 
Accretion expense1,117  1,103  
Revisions in estimated costs976  (16) 
Dispositions(620) (237) 
Ending asset retirement obligations$16,084  $15,475  
Current asset retirement obligations$431  $527  
Non-current asset retirement obligations$15,653  $14,948  

F-15
 For the year ended December 31,
 2016 2015
 (In thousands)
Beginning asset retirement obligations$10,585
 $9,381
Liabilities incurred2,009
 272
Liabilities settled(317) (143)
Accretion expense892
 1,075
Revisions in estimated costs181
 —
Ending asset retirement obligations$13,350
 $10,585


BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



NOTE 4—ACQUISITIONS4 — OIL AND NATURAL GAS PROPERTIES
Acquisitions of proved oil and natural gas properties and working interests are generally considered business combinations and are recorded at their estimated fair value as of the acquisition date. Acquisitions that consist of all or substantially all unproved oil and natural gas properties are generally considered asset acquisitions and are recorded at cost.
On January2019 Acquisitions
During the year ended December 31, 2019, the Partnership closed on multiple acquisitions of mineral and royalty interests for total consideration of $44.0 million.
Acquisitions that were considered business combinations were primarily located in the Permian Basin. These acquisitions were funded with borrowings under the Partnership's Credit Facility (as defined in Note 8 2016,- Credit Facility) and funds from operating activities. Acquisition related costs of $0.1 million were expensed and included in the General and administrative expense line item of the consolidated statement of operations for the year ended December 31, 2019. The following table summarizes these acquisitions:
Assets AcquiredConsideration Paid
ProvedUnprovedNet Working CapitalTotal Fair ValueCash
(in thousands) 
February$173  $8,437  $1  $8,611  $8,611  
March24  —  —  24  24  
June527  3,268  —  3,795  3,795  
Total fair value$724  $11,705  $1  $12,430  $12,430  
In addition, during 2019, the Partnership acquired mineral and royalty interests in the Permian Basinthat were considered asset acquisitions from various sellers for $10.0 million in cash.
On June 15, 2016, the Partnership acquired an oil and natural gas mineral asset packageaggregate of $31.6 million. These acquisitions were primarily located in Weld County, ColoradoEast Texas and the Permian Basin. The cash portion of the consideration paid for $34.0these acquisitions of $30.7 million in cash. The following table summarizeswas funded with borrowings under the Partnership's Credit Facility and funds from operating activities, and $0.9 million was funded through the issuance of common units of the Partnership based on the fair values assigned toof the properties acquired:common units issued on the acquisition dates.
2018 Acquisitions
 (In thousands)
Proved oil and natural gas properties$18,948
Unproved oil and natural gas properties14,082
Net working capital1,038
Asset retirement obligations(50)
   Total fair value$34,018
On June 17, 2016,During the year ended December 31, 2018, the Partnership acquired a diverse oil and natural gas mineral package from Freeport-McMoRan Oil and Gas, Inc. for $87.6 million in cash. The following table summarizes the fair values assigned to the properties acquired:
 (In thousands)
Proved oil and natural gas properties$20,787
Unproved oil and natural gas properties65,745
Net working capital1,026
   Total fair value$87,558

On August 8, 2016, the Partnership acquired mineral interests located in Midland and Glasscock countiesclosed on multiple acquisitions of Texas for $8.3 million in cash.
Throughout 2016, the Partnership funded certain other oil and natural gas asset acquisitions for an aggregate amount of $1.2 million in cash.
The Partnership acquired mineral and royalty interests in the Permian Basin throughout 2015. Separate transactions were closed on June 30, 2015 ($14.4 million), July 15, 2015 ($7.8 million), August 5, 2015 ($20.3 million), August 21, 2015 ($5.8 million), and September 22, 2015 ($3.4 million).
The Partnership acquired acreage in the Eagle Ford Shale play through two transactions: mineral and royalty interests in Junefor total consideration of 2015 for $0.5 million and mineral and royalty and non-operated working interests on September 24, 2015 for $9.2$149.9 million.
On June 2, 2015, the Partnership also acquired overriding royalty interests in the Utica Shale and Marcellus plays for $1.8 million.
F-16
During 2014, the Predecessor acquired mineral and royalty interests in the Permian Basin for $16.0 million and the Eagle Ford Shale play for $11.9 million. The Predecessor also acquired non-operated working interests in the Haynesville play for $24.6 million and mineral and royalty interests and non-operated working interests in various states for $2.3 million through the issuance of Predecessor units.

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



Acquisitions that were considered business combinations were primarily located in the Permian Basin. The cash portion of the consideration paid for these acquisitions was funded with borrowings under the Partnership's Credit Facility and funds from operating activities. Acquisition related costs of $0.2 million were expensed and included in the General and administrative expense line item of the consolidated statement of operations for the year ended December 31, 2018. The following table summarizes these acquisitions:
Assets AcquiredConsideration Paid
ProvedUnprovedNet Working CapitalTotal Fair ValueCashFair Value of Common Units Issued
(in thousands) 
March$984  $21,452  $133  $22,569  $22,569  $—  
June883  13,688  8  14,579  14,579  —  
July4,349  7,944  215  12,508  3,764  8,744  
August5,000  34,673  74  39,747  26,461  13,286  
September1,176  —  —  1,176  1,176  —  
November1,166  —  —  1,166  1,166  —  
Total fair value$13,558  $77,757  $430  $91,745  $69,715  $22,030  
In addition, during 2018, the Partnership acquired mineral and royalty interests that were considered asset acquisitions from various sellers for an aggregate of $58.2 million. These acquisitions were primarily located in East Texas and the Permian Basin. The cash portion of the consideration paid for these acquisitions of $57.6 million was funded with borrowings under the Partnership's Credit Facility and funds from operating activities, and $0.6 million was funded through the issuance of common units of the Partnership based on the fair values of the common units issued on the acquisition dates.
During 2018, the Partnership acquired the remaining noncontrolling interest in certain subsidiaries for $1.7 million and merged the subsidiaries into its existing structure. This acquisition was funded with borrowings under the Partnership's Credit Facility and funds from operating activities.
Noble Acquisition

On November 28, 2017 (the "Close Date"), Black Stone Minerals Company, L.P. ("BSMC"), a wholly owned subsidiary of BSM, 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 was completed in 2018 after post-closing purchase price adjustments were finalized. Since December 31, 2017, the Partnership has recorded an adjustment to the purchase price to reduce the amount allocated to unproved properties by $3.2 million, which reduces the Acquisitions of oil and natural gas properties line item of the consolidated statement of cash flows for the year ended December 31, 2018.

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BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes the final allocation of the fair value of the assets acquired and the acquisition-related costs.
Assets Acquired
ProvedUnprovedNet Working CapitalTotal Fair Value
Cash Consideration Paid1
Acquisition-Related Costs2
(in thousands)
Noble Assets$68,877  $256,542  $5,917  $331,336  $331,336  $247  

1 Represents cash consideration paid on the Close Date, as adjusted for the $3.2 million purchase price adjustment recorded during the year ended December 31, 2018.
2 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.

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,
20172016
(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 interests34  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 units99,776  20,696  
Subordinated units55,111  (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) 

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BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

2017 Acquisitions

In addition to the Noble Acquisition, the Partnership closed on multiple acquisitions of mineral and royalty interests, which were also considered business combinations, during the year ended December 31, 2017. These acquisitions were primarily focused in the Delaware Basin and East Texas. The cash portion of the consideration paid for these acquisitions was funded with borrowings under the Partnership's Credit Facility and funds from operating activities. The following table summarizes these acquisitions:

Assets AcquiredConsideration Paid
ProvedUnprovedNet Working CapitalTotal Fair ValueCashFair Value of Common Units Issued
Acquisition-Related Costs1
(in thousands)
January$5,135  $34,008  $263  $39,406  $27,380  $12,026  $1,162  
June5,006  45,477  —  50,483  4,802  45,681  1,481  
August3,277  9,984  —  13,261  4,289  8,972  107  
September3,120  —  —  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 consolidated statement of operations for the year ended December 31, 2017.

In addition, the Partnership acquired mineral and royalty interests that were considered asset acquisitions from various sellers in East Texas as reflected in the table below. The cash portion of the consideration paid for these acquisitions was funded via borrowings under the Partnership's Credit Facility.

Assets AcquiredConsideration Paid
UnprovedCashFair Value of Common Units Issued
(in thousands)
Q1 2017$21,189  $21,017  $172  
Q2 201713,329  13,329  —  
Q3 201719,946  15,205  4,741  
Q4 20172,267  2,137  130  
Total acquired$56,731  $51,688  $5,043  


F-19
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Farmout Agreements
In 2017, the Partnership entered into two farmout arrangements designed to reduce its working interest capital expenditures and thereby significantly lower its capital spending other than for mineral and royalty interest acquisitions. Under these agreements, the Partnership conveyed its rights to participate in certain non-operated working interest opportunities to external capital providers while retaining value from these interests in the form of additional royalty income or retained economic interests.

Canaan Farmout
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. ("XTO Energy"), a subsidiary of Exxon Mobil Corporation. The Partnership has an approximate 50% working interest in the acreage and is the largest mineral owner. A total of 20 wells were drilled over an initial phase, beginning with wells spud after January 1, 2017. Canaan elected to participate in an additional phase that began in September 2018 and continues for the earlier of 2 years or until 20 wells have been drilled. As of December 31, 2019, a total of 17 wells have been drilled during the second phase. After the completion of the second phase, Canaan will have the option to elect to participate in a similar third phase. During the first 3 phases of the agreement, Canaan commits on a phase-by-phase basis and funds 80% of the Partnership's drilling and completion costs and is assigned 80% of the Partnership's working interests in such wells (40% working interest on an 8/8ths basis) as the wells are drilled. After the third phase, Canaan 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 receives an overriding royalty interest (“ORRI”) before payout and an increased ORRI after payout on all wells drilled under the agreement. From the inception of the agreement through December 31, 2019, the Partnership has received $90.0 million from Canaan under the agreement as reimbursement for capital costs associated with farmed-out working interests. When such reimbursements are received prior to assigning the wells to Canaan, the Partnership records the amounts as increases to Oil and natural gas properties and Other long-term liabilities. When working interests in farmout wells are assigned to Canaan, the Partnership's Oil and natural gas properties and Other long-term liabilities are reduced by the reimbursed capital costs. As of December 31, 2019, $0.9 million was included in the Other long-term liabilities line item of the consolidated balance sheet for reimbursements received associated with farmed-out working interests not yet assigned to Canaan.

Pivotal Farmout
On November 21, 2017, the Partnership entered into a farmout agreement with Pivotal Petroleum Partners (“Pivotal”), a portfolio company of Tailwater Capital, LLC. The farmout agreement 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), until November 2025. Pivotal will earn the Partnership's remaining working interest in wells operated by XTO Energy in San Augustine County, Texas not covered by the Canaan Farmout (10% working interest on an 8/8th basis), as well as 100% of the Partnership's working interests (ranging from approximately 12.5% to 25% on an 8/8ths basis) in wells operated by BPX Energy in San Augustine and Angelina counties, Texas. Initially, Pivotal is obligated to fund the development of up to 80 wells, in designated well groups, across several development areas and then has options to continue funding the Partnership's working interest across those areas for the duration of the farmout agreement. Once Pivotal achieves a specified payout for a designated well group, the Partnership will obtain a majority of the original working interest in such well group. From the inception of the agreement through December 31, 2019, a total of 68 wells have been drilled in the contract area and the Partnership has received $115.2 million from Pivotal under the agreement as reimbursement for capital costs associated with farmed-out working interests. When such reimbursements are received prior to assigning the wells to Pivotal, the Partnership records the amounts as increases to Oil and natural gas properties and Other long-term liabilities. When working interests in farmout wells are assigned to Pivotal, the Partnership's Oil and natural gas properties and Other long-term liabilities are reduced by the reimbursed capital costs. As of December 31, 2019, $0.9 million was included in the Other long-term liabilities line item of the consolidated balance sheet for reimbursements received associated with farmed-out working interests not yet assigned to Pivotal. The Partnership's development agreement with BPX Energy terminated in 2019 with respect to the majority of the Partnership's acreage covered by the agreement. As such, Pivotal retains minimal rights or obligations related to the farmout for that area. The Partnership remains engaged with Pivotal around farmout opportunities with potential new operators in the area forfeited by BPX Energy.
As of December 31, 2018, $11.6 million and $41.2 million were included in the Other long-term liability line item of the consolidated balance sheet related to the farmout agreements with Canaan and Pivotal, respectively.

F-20
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 5—DERIVATIVES AND5 — 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 fixed-price-swap contracts, fixed price contracts,variable-to-fixed-price swaps, costless collars, fixed-price contracts, and other contractual arrangements. The Partnership enters into oil and natural gas derivative instrument contracts that contain netting arrangements with each counterparty. The Partnership does not enter into derivative instruments for speculative purposes.
As of December 31, 2016,2019, the Partnership's open derivatives contracts consisted of only fixed-price-swap contracts and costless collar contracts. A fixed-price-swapfixed-price swap contract between the Partnership and the counterparty specifies a fixed commodity price and a future settlement date. We haveA costless collar contract between the Partnership and the counterparty specifies a floor and a ceiling commodity price and a future settlement date. The Partnership has not designated any of ourits 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"revenue in the Partnership's accompyingaccompanying consolidated statementstatements of operations. All derivativeDerivative 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, 20162019 and 2015, respectively.2018. See Note 6 – Fair Value MeasurementMeasurements for further discussion.
The tablePartnership's derivative contracts expose it to credit risk in the event of nonperformance by counterparties that may adversely impact the fair value of the Partnership's commodity derivative assets. 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, 2019, the Partnership had 9 counterparties, all of which are rated Baa1 or better by Moody’s and are lenders under the Partnership's Credit Facility.
F-21
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The tables below summarizessummarize the fair value and classification of the Partnership’s derivative instruments:instruments, as well as the gross recognized derivative assets, liabilities, and amounts offset in the consolidated balance sheets as of each date: 
As of December 31, 2019
ClassificationBalance Sheet Location
Gross Fair
Value
Effect of
Counterparty Netting
Net Carrying
Value on
Balance Sheet
  (in thousands)
Assets:    
       Current assetCommodity derivative assets$19,028  $(4,238) $14,790  
       Long-term assetDeferred charges and other long-term assets713  (105) 608  
          Total assets $19,741  $(4,343) $15,398  
Liabilities:          
       Current liabilityCommodity derivative liabilities$4,397  $(4,238) $159  
       Long-term liabilityCommodity derivative liabilities123  (105) 18  
         Total liabilities $4,520  $(4,343) $177  
  
As of December 31, 2018
As at December 31, 2016
Classification Balance Sheet Location 
Gross Fair
Value
 
Effect of
Counterparty
Netting
 
Net Carrying
Value on
Balance Sheet
ClassificationBalance Sheet Location
Gross Fair
Value
Effect of
Counterparty Netting
Net Carrying
Value on
Balance Sheet
    
 (In thousands)    (in thousands)
Assets:    
  
  
Assets:    
Current asset Commodity derivative assets $3,879
 $3,879
 $—
 Current assetCommodity derivative assets$38,746  $(776) $37,970  
Long-term asset 
Deferred charges and other
long-term assets
 —
 —
 —
 Long-term assetDeferred charges and other long-term assets11,518  (1,450) 10,068  
Total assets   $3,879
 $3,879
 $—
 Total assets $50,264  $(2,226) $48,038  
Liabilities:    
  
  
Liabilities:    
Current liability Commodity derivative liabilities $20,116
 $3,879
 $16,237
 Current liabilityCommodity derivative liabilities$776  $(776) $—  
Long-term liability Commodity derivative liabilities 482
 —
 482
 Long-term liabilityCommodity derivative liabilities1,450  (1,450) —  
Total liabilities   $20,598
 $3,879
 $16,719
 Total liabilities $2,226  $(2,226) $—  
 
As of December 31, 2015
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 $48,260
 $—
 $48,260
Long-term asset 
Deferred charges and other
long-term assets
 16,274
 —
 16,274
Total assets   $64,534
 $—
 $64,534
Liabilities:    
  
  
Current liability Commodity derivative liabilities $—
 $—
 $—
Long-term liability Commodity derivative liabilities —
 —
 —
Total liabilities   $—
 $—
 $—
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. Changes in the fair valueoperations and consolidated statements of cash flows and consist of the Partnership’s commodity derivative instruments (both assets and liabilities) are as follows:following for the periods presented:
 For the year ended December 31,
Derivatives not designated as hedging instruments201920182017
 (in thousands)
Beginning fair value of commodity derivative instruments$48,038  $(5,028) $(16,719) 
Gain (loss) on oil derivative instruments(34,728) 24,300  (5,091) 
Gain (loss) on natural gas derivative instruments29,773  (9,469) 31,993  
Net cash paid (received) on settlements of oil derivative instruments(8,536) 34,905  (10,901) 
Net cash paid (received) on settlements of natural gas derivative instruments(19,326) 3,330  (4,310) 
Net change in fair value of commodity derivative instruments(32,817) 53,066  11,691  
Ending fair value of commodity derivative instruments$15,221  $48,038  $(5,028) 

F-22
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



  For the year ended December 31,
Derivatives not designated as hedging instruments 2016 2015 2014
  (In thousands)
Beginning fair value of commodity derivative instruments $64,534
 $37,471
 $(1,812)
Gain (loss) on oil derivative instruments (15,998) 57,681
 27,548
Gain (loss) on natural gas derivative instruments (20,466) 32,607
 9,788
Net cash received on settlements of oil derivative
   instruments
 (27,450) (41,786) (46)
Net cash (received) paid on settlements of natural gas
   derivative instruments
 (17,339) (21,439) 1,993
Net change in fair value of commodity derivative
   instruments
 (81,253) 27,063
 39,283
Ending fair value of commodity derivative instruments $(16,719) $64,534
 $37,471

The Partnership had the following open derivative contracts for oil as of December 31, 2016:2019:
 Volume (Bbl)Weighted Average Price (per Bbl)Range (per Bbl)
Period and Type of ContractLowHigh
Oil Swap Contracts:    
2019
Fourth quarter312,000  $58.50  $52.82  $63.75  
2020    
First quarter630,000  $57.32  $54.92  $58.65  
Second quarter630,000  57.32  54.92  58.65  
Third quarter630,000  57.32  54.92  58.65  
Fourth quarter630,000  57.32  54.92  58.65  

 Volume Weighted Average Range (Per Bbl) Volume (Bbl)Weighted Average Floor Price (Per Bbl)Weighted Average Ceiling Price (Per Bbl)
Period and Type of Contract (Bbl) (Per Bbl) Low HighPeriod and Type of Contract
Oil Swap Contracts:  
  
  
  
2017        
Oil Collar Contracts:Oil Collar Contracts:   
20192019
Fourth quarterFourth quarter20,000  $65.00  $74.00  
20202020         
First quarter 394,000
 $61.78
 $50.34
 $63.65
First quarter210,000  $56.43  $67.14  
Second quarter 405,000
 53.63
 51.45
 54.38
Second quarter210,000  56.43  67.14  
Third quarter 396,000
 $

 $

 $

Third quarter210,000  56.43  67.14  
Fourth quarter 396,000
 53.12
 52.57
 53.67
Fourth quarter210,000  56.43  67.14  


The Partnership had the following open derivative contracts for natural gas as of December 31, 2016:2019:
 Volume (MMBtu)Weighted Average Price (per MMBtu)Range (per MMBtu)
Period and Type of ContractLowHigh
Natural Gas Swap Contracts:    
2020
First quarter10,010,000  $2.69  $2.55  $2.74  
Second quarter10,010,000  2.69  2.55  2.74  
Third quarter10,120,000  2.69  2.55  2.74  
Fourth quarter10,120,000  2.69  2.55  2.74  
 















F-23
  Volume Weighted Average Range (Per MMBtu)
Period and Type of Contract (MMBtu) (Per MMBtu) Low High
Natural Gas Swap Contracts:  
  
  
  
2017        
First quarter 8,850,000
 $3.40
 $3.08
 $3.52
Second quarter 8,300,000
 3.09
 2.85
 3.18
Third quarter 7,730,000
 2.97
 2.90
 3.12
Fourth quarter 7,040,000
 3.08
 2.92
 3.29
The Partnership entered into the following derivative contracts for oil subsequent to December 31, 2016:
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



  Volume Weighted Average Range (Per Bbl)
Period and Type of Contract (Bbl) (Per Bbl) Low High
Oil Swap Contracts:  
  
  
  
2017        
First quarter 90,000
 $54.80
 $54.28
 $55.23
Second quarter 210,000
 54.90
 54.65
 55.23
Third quarter 160,000
 54.94
 54.65
 55.23
Fourth quarter 120,000
 55.00
 54.65
 55.23
2018        
First quarter 475,000
 $54.74
 $54.50
 $55.05
Second quarter 445,000
 54.73
 54.50
 54.90
Third quarter 425,000
 54.72
 54.50
 54.90
Fourth quarter 405,000
 54.72
 54.50
 54.90
The Partnership entered into the following derivative contracts for natural gas subsequent to December 31, 2016:
  Volume Weighted Average Range (Per MMBtu)
Period and Type of Contract (MMBtu) (Per MMBtu) Low High
Natural Gas Swap Contracts:  
  
  
  
2017        
First quarter 1,740,000
 $3.19
 $2.95
 $3.40
Second quarter 4,080,000
 3.16
 2.95
 3.40
Third quarter 3,480,000
 3.21
 3.13
 3.41
Fourth quarter 3,480,000
 3.22
 3.13
 3.57
2018        
First quarter 4,800,000
 $3.01
 $2.99
 $3.02
Second quarter 4,800,000
 3.01
 2.99
 3.02
Third quarter 4,800,000
 3.01
 2.99
 3.02
Fourth quarter 4,500,000
 3.01
 2.99
 3.02
NOTE 6—6 — FAIR VALUE MEASUREMENTMEASUREMENTS
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.
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, 20162019 and 2015.
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


2018.
The carrying value of ourthe Partnership's 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, 20162019 and 20152018 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 – Derivatives andCommodity 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 UsingEffect of Counterparty 
 Level 1Level 2Level 3NettingTotal
 (In thousands)
As of December 31, 2019     
Financial Assets     
Commodity derivative instruments$—  $19,741  $—  $(4,343) $15,398  
Financial Liabilities               
Commodity derivative instruments—  4,520  —  (4,343) 177  
As of December 31, 2018               
Financial Assets               
Commodity derivative instruments$—  $50,264  $—  $(2,226) $48,038  
Financial Liabilities               
Commodity derivative instruments—  2,226  —  (2,226) —  
F-24
  Fair Value Measurements Using 
Effect of
Counterparty
  
  Level 1 Level 2 Level 3 Netting Total
  (In thousands)
As of December 31, 2016  
  
  
  
  
Financial Assets  
  
  
  
  
Commodity derivative instruments $—
 $—
 $—
 $—
 $—
Financial Liabilities  
  
  
  
  
Commodity derivative instruments —
 16,719
 —
 —
 16,719
As of December 31, 2015  
  
  
  
  
Financial Assets  
  
  
  
  
Commodity derivative instruments $—
 $64,534
 $—
 $—
 $64,534
Financial Liabilities  
  
  
  
  
Commodity derivative instruments —
 —
 —
 —
 —
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 preparedestimated by estimating discounteddiscounting projected future cash flow projections.flows. The factors used to determine fair value include estimates of economic reserves, future operating and development costs, future commodity prices, timing of future production, 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 - Acquisitions.— Oil and Natural Gas Properties.
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 economicproved reserves, future commodity prices, timing of future production, operating and development costs, future commodity prices,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, 20162019 and 2015.
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


The following table presents information about the Partnership’s2018. There were no assets measured at fair value on a non-recurring basis:
  Fair Value Measurements Using Net Book  
  Level 1 Level 2 Level 3 
Value1
 Impairment
  (In thousands)
Year Ended December 31, 2016  
  
  
  
  
Impaired oil and natural gas properties $—
 $—
 $3,042
 $9,817
 $6,775
Year Ended December 31, 2015  
  
  
  
  
Impaired oil and natural gas properties $—
 $—
 $156,689
 $406,258
 $249,569
Year Ended December 31, 2014  
  
  
  
  
Impaired oil and natural gas properties $—
 $—
 $81,864
 $199,794
 $117,930
  1Amount represents net book value atbasis, after initial recognition, for the date of assessment.

The carrying value of all debt as of December 31, 2016 and 2015 approximates fair value due to variable market rates of interest. These fair values, which are Level 3 measurements, were estimated based on the Partnership’s incremental borrowing rates for similar types of borrowing arrangements, 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.
NOTE 7—RELATED PARTY TRANSACTIONS
The Predecessor executed promissory notes dated April 15, 2010, in the amount of $0.5 million to certain officers of the Predecessor. The promissory notes related to the acquisition of a partnership interest in a former affiliate by the officers, and the notes were collateralized by a security interest in the Predecessor. The aggregate outstanding note balance and interest receivable of $0.1 million was received during the yearyears ended December 31, 2014.2019, 2018, and 2017.
NOTE 8—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. Exxon MobilXTO Energy represented 11.0%approximately 18%, 15%, and 21% of total oil and natural gas revenue for the years ended December 31, 2016. No customer represented 10.0% or more of total revenue for the years ended December 31, 2015. One company, Chesapeake Energy Corporation, represented 10.0% of total revenue for the year ended December 31, 2014.2019, 2018, and 2017.
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 9—8 — CREDIT FACILITIES
Senior Line of CreditFACILITY
The Partnership maintains a senior secured revolving credit agreement, as amended, (the “Senior Line of Credit”“Credit Facility”). The Senior Line of Credit Facility has aan aggregate maximum credit amount of $1.0 billion . On October 28, 2015, the Senior Line of Credit was further amended to extend the termand terminates on November 1, 2022. The commitment of the agreement from February 3, 2017 to February 4, 2019.lenders equals the lesser of the aggregate maximum credit amount and the borrowing base. The amount of the borrowing base is redetermined semi-annually, usually in October and April, and is derived from the value of the Partnership’s oil and natural gas properties as determined by the lender syndicate using pricing assumptions that often differ from the current market for future prices. Effective October 28, 2015,May 4, 2018, the borrowing base was $550.0 million. The Partnership' semi-annual borrowing base redetermination process resulted in a decrease ofincreased the borrowing base from $550.0 million to $450.0 million, effective April 15, 2016. The Partnership's fall 2016 borrowing base redetermination process resulted in an increase in$600.0 million. Effective October 31, 2018, the borrowing base from $450.0was further increased to $675.0 million to $500.0 million, which becameand remained at that level until the most recent redetermination, effective October 31, 2016. Drawings on23, 2019, which reduced the Senior Lineborrowing base to $650.0 million.
Outstanding borrowings under the Credit Facility bear interest at a floating rate elected by the Partnership equal to an alternative base rate (which is equal to the greatest of Credit are used for the acquisition of oil and natural gas properties and for other general business purposes.
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. Prior to October 31, 2016, borrowings under2018, the Senior Lineapplicable margin ranged from 1.00% to 2.00% in the case of Credit bore interest atthe alternative base rate and from 2.00% to 3.00% in the case of 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 borrowings outstanding in relation to 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.base. Effective October 31, 2016, borrowings under2018, the Senior Line of Credit bore interest atapplicable margin for the alternative base rate was reduced to between 0.75% and 1.75% and the applicable margin for LIBOR plus a marginwas reduced to between 2.00%1.75% 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.  
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


2.75%.
The weighted-average interest rate of the Senior Line of Credit Facility was 3.26%4.05% and 1.92%4.76% as of December 31, 20162019 and 2015,2018, 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
F-25
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

percentage is less than 50%, or 0.500% per annum if the borrowing base utilization percentage is equal to or greater than 50%. The Senior Line of Credit Facility is secured by substantially all of the Partnership’s oil and natural gas production and assets.
The Senior Line of Credit Facility contains various limitations on future borrowings, leases, hedging, and sales of assets. Additionally, the Senior Line of 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, 2016,2019, the Partnership was in compliance with all financial covenants in the Senior Line of Credit.Credit Facility.
The aggregate principal balance outstanding was $316.0$394.0 million and $66.0$410.0 million at December 31, 20162019 and 2015,2018, respectively. The unused portion of the available borrowings under the Senior Line of Credit was $184.0Facility were $256.0 million and $484.0$265.0 million at December 31, 20162019 and 2015,2018, respectively.

NOTE 10—9 — INCENTIVE COMPENSATION
Overview
The Boardboard of Directorsdirectors of the Partnership’s general partner (“the Board”(the "Board") adoptedestablished 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 or subordinated units. On May 6, 2015, the Partnership registered 17,420,310 common and subordinated units that are issuable under the 2015 LTIP. 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 will beare based on a predetermined schedule as approved by the Board.Board or a committee thereof.
Incentive compensation expense is included in generalGeneral 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 providesmay also provide from time to time short-term and long-term cash long-term incentive and retention awards annually for its directors, executive officers, and certain other employees. In 2012, the Predecessor adopted a long-term incentive plan that combined both its management and senior management long-term incentive plans (the “2012 LTI Plan”). Under the 2012 LTI Plan, executive officers and certain other members of management are granted fifty percent of their incentive compensation in performance cash awards determined based on achieving specific production and reserves targets as set by the Board. Cash award compensation cliff vests on the third anniversary of the grant date, subject to satisfaction of the applicable performance targets so long as the employee remains employed through the vesting date. Certain other employees are entitled to earnreceive cash bonuses based on service criteria over a four-yearfour-year requisite service period.period ending in 2019. Payments are disbursed one-third per year over three years beginningas vesting is attained on the first anniversary following December 31a graded annual basis. The last grant of the service year.
On May 6, 2015,such cash awards with service-based graded vesting requirements was made in 2016 with vestings extending through MarchDecember 31, 2019 were also granted to certain other employees.2019.
Restricted Unit Grant Awards
The remaining fifty percent of incentive compensation was paid in the form of restricted common units of the Predecessor under the 2012 LTI Plan to executive officers and certain other members of management.  
Restricted common units of the Predecessor that were outstanding as of the date of the IPO were converted into restricted common and subordinated units of the Partnership in connection with the IPO as set forth in the table below. The converted restricted units awarded are subject to restrictions on transferability, customary forfeiture provisions, and time vesting provisions. Each converted award vests pursuant to the original vesting schedule applicable to the restricted unit award of the Predecessor.
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


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 distributions are made by the Partnership to its limited partners. ForPartnership. The grant-date fair value of these awards, granted prior to December 31, 2014, recipients could request thatnet of estimated forfeitures, is recognized ratably using the Partnership, at its discretion, repurchase up to fifty percent of the restricted common units that are scheduled to vest. As a result of the repurchase option, fifty percent of the equity awards to be vested on each vesting date were classified as a liability during the corresponding year prior to the vesting date until a request for the Partnership to repurchase was made by the recipient, or the repurchase option period ended, which was 30 days prior to the vesting date. The liability was measured periodically at fair value. straight-line attribution method.

In conjunction with the adoption of the 2015 LTIP, the provision in certainBoard approved a grant of awards to each of the Predecessor’sexecutive 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 unit agreementscommon units subject to limitations on transferability, customary forfeiture provisions, and service based graded vesting requirements that allowed award recipientsextended through March 15, 2019.

The Compensation Committee of the Board (the "Compensation Committee") annually approves a grant of awards to request cash settlement for upeach of the executive officers of the Partnership's general partner and certain other employees. Consistent with previous awards the 2019 grant includes restricted common units subject to 50%limitations on transferability, customary forfeiture provisions, and service-based graded vesting requirements through January 7, 2022. In January of their restricted unit awards was removed; as such, these awards are no longer classified as liability awards. Non-employeeeach year, non-employee directors of the Partnership’s general partner receivedreceive compensation under the 2015 LTIP in the form of fully vested common units granted after each year of service.
On May 6, 2015, in conjunction with
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BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes information about restricted units for the adoption of the 2015 LTIP, the Board approved a grant of awards to each of the Partnership’s executive officers, certain other employees, and each of the non-employee directors of the Partnership’s general partner. year ended December 31, 2019.
Number of UnitsWeighted-Average Grant-Date Fair Value per Unit
Unvested at December 31, 20181,334,016  $17.29  
Granted496,316  17.09  
Vested(778,956) 16.64  
Converted—  —  
Forfeited(13,117) 17.49  
Unvested at December 31, 20191,038,259  17.67  
The grants included 1,034,013 restricted common units subject to limitations on transferability, customary forfeiture provisions, and service-based graded vesting requirements through April 1, 2019. The holders of restricted common unit awards have all of the rights of a common unitholder, including non-forfeitable distribution rights with respect to their restricted common units. Theweighted-average grant-date fair value per unit for unit-based awards was $17.09, $17.95, and $18.48 for the years ended December 31, 2019, 2018, and 2017, respectively. As of these awards, net of estimated forfeitures, is recognized ratably using the straight-line attribution method. Additionally, non-employee directors of the Partnership’s general partner received a one-time grant totaling 63,156 fully vested common units.
On January 12, 2016, each non-employee director on the Board of Directors of the Partnership’s general partner (the “Board”) was granted 12,368 fully vested common units for service during 2015. On February 19, 2016, the Compensation Committee of the Board approved a grant of awards to each of the Partnership’s executive officers and certain other employees. These awards consisted ofDecember 31, 2019, unrecognized compensation cost associated with restricted common units and restricted performance units (in the form of phantom units) with distribution equivalent rights. The grants included 717,654 restricted common units subject to limitations on transferability, customary forfeiture provisions, and service-based graded vesting requirements through January 7, 2019. The holders of restricted common unit awards have allwas $8.5 million, which the Partnership expects to recognize over a weighted-average period of the rights of a common unitholder, including non-forfeitable distribution rights with respect to their restricted common units.1.67 years. The grant-date fair value of these awards, net of estimated forfeitures, is recognized ratably usingunits vested for the straight-line attribution method. years ended December 31, 2019, 2018, and 2017 was $12.7 million, $12.9 million, and $25.1 million, respectively. There were 0 cash payments made for vested units during the years ended December 31, 2019, 2018, and 2017.
Performance Unit Awards

The Compensation Committee of the Board also approved a grantapproves grants of 717,654 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 average performance over each of the three calendar year during the performance periodperiods commencing January 1 2016.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 period on December 31, 2018.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 likelyprobable to vest, by the grant-datemeasurement-date (i.e., the last day of each reporting period date) fair value and recognized using the accelerated or straight-line attribution method. Distribution equivalent rights formethods, depending on the restricted performance unit awards that are expected to vest are charged to partners’ capital. The Compensation Committeeterms of the Board also approved the dollar-value targets for performance-based short-term incentive compensation for executive officers of the Partnership and certain other employees. The Partnership expects to ultimately settle the authorized awards at the end of the performance period in common units of the Partnership.
On April 25, 2016, the Compensation Committee of the Board approved a resolution to change the settlement feature of certain employee long-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.
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


The following table summarizes information about restricted units for the year ended December 31, 2016.
  Units 
Weighted-Average Grant-Date Fair
Value per Unit
Units Common Subordinated Common Subordinated
Unvested at December 31, 2015 1,362,091
 442,778
 $19.08
 $19.36
Granted 985,239
 —
 10.58
 —
Vested (716,753) (224,090) 15.10
 19.80
Converted —
 —
 —
 —
Forfeited (359,362) (55,647) 17.09
 18.77
Unvested at December 31, 2016 1,271,215
 163,041
 15.29
 18.97
The weighted-average grant-date fair value for unit-based awards was $10.09, $18.79, and $20.73 for the years ended December 31, 2016, 2015, and 2014, respectively. Unrecognized compensation cost associated with restricted common and subordinated unit awards was $13.1 million and $1.3 million, respectively, as of December 31, 2016, which the Partnership expects to recognize over a weighted-average period of 2.06 years and 1.20 years for common units and subordinated units, respectively. The fair value of units vested for the years ended December 31, 2016, 2015, and 2014 was $11.9 million, $9.4 million and $8.6 million, respectively. There were no cash payments made for vested units during the years ended December 31, 2016, 2015 and 2014.
Performance Unit Grant Awards
On May 6, 2015, the Board also approved a grant of 947,142 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 four 12-month performance periods commencing April 1, 2015. 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 as follows: 16.66%, 16.67%, and 16.67% in each of the 12-month performance periods that end on March 31, 2016, March 31, 2017, and March 31, 2018, respectively.  The remaining 50% of the restricted performance units are eligible to become earned during the final 12-month performance period that ends on March 31, 2019. If the performance criteria are not met for the final performance period, the awards allow for a make-up period ending on March 31, 2020. 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 likely to vest, by the grant-date fair value and recognized using the accelerated attribution method.award. Distribution equivalent rights for the restricted performance unit awards that are expected to vest are charged to partners’ capital.

The following table summarizes information about performance units for the year ended December 31, 2016.2019.
 
Performance unitsNumber of Units
Weighted-Average Grant-Date
Fair Value per Unit
Unvested at December 31, 20181,811,810  $15.94  
Granted1
953,638  16.84  
Vested(1,378,188) 14.83  
Forfeited(18,178) 17.63  
Unvested at December 31, 20191,369,082  17.66  
Performance units Units 
Weighted-
Average Grant-
Date Fair Value
per Unit
Unvested at December 31, 2015 947,142
 $19.00
Granted 730,632
 11.36
Vested (216,177) 17.90
Forfeited (305,178) 16.88
Unvested at December 31, 2016 1,156,419
 14.94
1  Includes 457,322 of additional performance units issued based on the final performance multiplier for awards that vested in the period.
The weighted-average grant-date fair value per unit for performance unit awards was $16.84, $17.94, and $17.99 for the years ended December 31, 2019, 2018, and 2017, respectively. Unrecognized compensation cost associated with performance unit awards was $10.8$6.3 million as of December 31, 2016,2019, which the Partnership expects to recognize over a weighted-average period of 1.921.82 years. The fair value of performance units vested for the years ended December 31, 2019, and 2018 was $22.7 million, and $1.5 million, respectively. No performance units vested for the year ended December 31, 2017.

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BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



Incentive Compensation Summary
The table below summarizes incentive compensation expense recorded in generalGeneral and administrative expenses in the consolidated statements of operations for the years ended December 31, 2016, 2015,2019, 2018, and 2014.2017.
 Year Ended December 31,
Incentive compensation expense201920182017
 (In thousands)
Cash — short and long-term incentive plan$5,593  $9,301  $4,373  
Equity-based compensation — restricted common and subordinated units10,751  13,624  13,476  
Equity-based compensation — restricted performance units7,386  14,188  17,367  
Board of Directors incentive plan2,347  2,322  2,202  
Total incentive compensation expense$26,077  $39,435  $37,418  

  Year Ended December 31,
Incentive compensation expense 2016 2015 2014
  (In thousands)
Cash—long-term incentive plan $2,725
 $15,064
 $13,927
Equity-based compensation—restricted common and subordinated units 13,408
 10,137
 7,194
Equity-based compensation—restricted performance units 18,518
 4,743
 —
Board of Directors incentive plan 2,012
 3,120
 4,146
Total incentive compensation expense $36,663
 $33,064
 $25,267
NOTE 11—10 — EMPLOYEE BENEFIT PLANS
TheBlack 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%90% 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 employmentservice with the Partnership. Following three years of employment,service, future Partnership matching contributions vest immediately. The Partnership’s contributions were $0.5$0.7 million, $0.6$0.7 million, and $0.6 million for the years ended December 31, 2016, 2015,2019, 2018, and 2014,2017, respectively.
NOTE 12—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 2019. The Partnership recognizes rent expense on a straight-line basis over the lease term. Rent expense under such arrangements was $1.9 million, $1.8 million, and $1.9 million for the years ended December 31, 2016, 2015, and 2014, 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:
Year Ending December 31,(In thousands)
2017$1,603
20181,647
201935
202012
2021—
Total$3,297
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 no0 provision for potential remediation costs has been made.recorded.

Put Option Related to Noble Acquisition
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


By acquiring 100% of the issued and outstanding securities of Samedan, now NAMP Holdings, LLC, on November 28, 2017 as part of the Noble Acquisition, the Partnership acquired a 100% interest in Comin-Termin, LLC, now NAMP GP, LLC ("Holdings"), Comin 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 45.33% and 42.63% of the mineral interests held of record by Holdings and Temin, respectively, as of December 31, 2019. 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, 2019, 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, 20162019 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 13—REDEEMABLE12 — PREFERRED UNITS
The Partnership has outstanding 52,691Series A Redeemable Preferred Units
As of December 31, 2019 and 77,2162018, there were 0 Series A redeemable preferred units outstanding with a carrying value of $54.0 million and $79.2 million as of December 31, 2016 and 2015, respectively.outstanding. The aforementioned amounts include accrued distributions of $1.3 million and $1.9 million as of December 31, 2016 and 2015, respectively. TheSeries A redeemable preferred units are classified as mezzanine equity on the consolidated balance sheets since redemption is outside the control of the Partnership. The preferred units arewere entitled to an annual distribution of 10% of the outstanding funded capital of the Series A redeemable preferred units, payable on a quarterly basis in arrears.
Prior to our liquidation, and while any of ourThe Series A redeemable preferred units remain outstanding, cash or other property of the partnership will be distributed 100% to our redeemable preferred unitholders until the aggregate Unpaid Preferred Yield (as defined below) of each 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 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 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 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 preferred unit and as of any date of determination, an amount equal to the excess, if any, of (a) the cumulative Preferred Yield from the closing of this offering through the date established, over (b) the cumulative amount of distributions made as of the date established in respect of the preferred unit.
The redeemable preferred units are convertible into common and subordinated units at any time at the option of the Series A redeemable preferred unitholders. The Series A redeemable preferred units havehad 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.  unit.
The Series A redeemable preferred unitholders canhad the option to elect to have the Partnership redeem, at face value, up to 28,266all remaining Series A redeemable preferred units, effective as of December 31, 2017, and 24,425 redeemable preferred units as of December 31, 2018, plus any accrued and unpaid distributions.
The Partnership shall have the right, at its sole option, to redeem an amount ofAll Series A redeemable preferred units equal to the units beingnot redeemed by an owner of redeemable preferred units on each December 31. Any amount of a given year’s redeemable preferred units eligible for redemption not redeemed on DecemberMarch 31, shall2018 automatically convertconverted to common and subordinated units oneffective as of January 1, in the following year.2018 or as soon as practicable thereafter.
For the year ended December 31, 2016, 18,4612018, 2,115 Series A redeemable preferred units were redeemed for $19.0$2.1 million, including accrued unpaid yield. For the year ended December 31, 2016, 6,064yield, and 24,248 Series A redeemable preferred units totaling $6.1$24.2 million were converted into 184,006735,758 common units and 240,986963,681 subordinated units as a result of the mandatory conversion subsequent to December 31, 2015. 2017.
For the year ended December 31, 2015, 39,2402017, 19,704 Series A redeemable preferred units were redeemed for $20.2 million, including accrued unpaid yield, and 6,624 Series A redeemable preferred units totaling $39.2$6.6 million were converted into the equivalent of 200,996 common units and 263,247 subordinated units as a result of the mandatory conversion subsequent to December 31, 2016.
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 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 $298.4 million, including accrued distributions of $5.3 million, as of December 31, 2019 and 2018. The Series B cumulative convertible preferred units are classified as mezzanine equity on the consolidated balance sheets since certain redemption provisions are outside the control of the Partnership.
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BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



converted into the equivalent of 1,190,664 common units and 1,559,502 subordinated units on an adjusted basis. For the year ended December 31, 2014, 221 redeemable preferred units totaling $0.2 million were converted into 15,489 Predecessor units.
On November 6, 2015, the Partnership commenced a tender offer to purchase up to 100% of the then outstanding redeemable preferred units at par value plus unpaid accrued yield. The tender offer expired on December 10, 2015. The Partnership purchased and canceled 40,747 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.
NOTE 14—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 not0t material.
Net income (loss) attributable to the Partnership is allocated to ourthe Partnership's 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 Partnership assesses the Series A redeemable preferred units could be converted into 1.6 million common units and 2.1 million subordinated units as of December 31, 2016. At December 31, 2016, if the redeemableSeries B cumulative convertible preferred units were converted to common and subordinated units,on an as-converted basis for the effect would be anti-dilutive. Therefore, the redeemable preferred units are not included in thepurpose of calculating diluted EPU calculation.EPU. 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, 2016, 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 antidilutive.
The following table sets forth the computation of basic and diluted earnings per unit:
 For the Year Ended December 31,
 201920182017
 (in thousands, except per unit  amounts)
NET INCOME (LOSS)$214,368  $295,560  $157,153  
Net (income) loss attributable to noncontrolling interests—  (24) 34  
Distributions on Series A redeemable preferred units—  (25) (3,117) 
Distributions on Series B cumulative convertible preferred units(21,000) (21,000) (1,925) 
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS$193,368  $274,511  $152,145  
ALLOCATION OF NET INCOME (LOSS):   
General partner interest$—  $—  $—  
Common units169,375  154,662  98,389  
Subordinated units23,993  119,849  53,756  
 $193,368  $274,511  $152,145  
Weighted average common units outstanding:
Weighted average common units outstanding (basic)168,230  106,064  97,400  
Effect of dilutive securities146  15,200  —  
Weighted average common units outstanding (diluted)168,376  121,264  97,400  
Weighted average subordinated units outstanding:
Weighted average subordinated units outstanding (basic)37,740  96,099  95,149  
Effect of dilutive securities—  247  —  
Weighted average subordinated units outstanding (diluted)37,740  96,346  95,149  
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:     
Per common unit (basic)$1.01  $1.46  $1.01  
Per subordinated unit (basic)0.64  1.25  0.56  
Per common unit (diluted)1
1.01  1.45  1.01  
Per subordinated unit (diluted)2
0.64  1.25  0.56  
1 For the year ended December 31, 2018, diluted net income (loss) attributable to common units includes distributions on Series B cumulative convertible preferred units of $21.0 million.
2 For the year ended December 31, 2018, diluted net income (loss) attributable to subordinated units includes distributions on Series A redeemable preferred units of $0.3 million.
F-30
  For the Year Ended December 31,
  2016 2015 2014
  (In thousands, except per unit  amounts)
NET INCOME (LOSS) $20,188
 $(101,305) $169,187
NET (INCOME) LOSS ATTRIBUTABLE TO PREDECESSOR —
 (450) (169,187)
NET (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS SUBSEQUENT TO INITIAL PUBLIC OFFERING 12
 1,260
 —
DISTRIBUTIONS ON REDEEMABLE PREFERRED UNITS SUBSEQUENT TO INITIAL PUBLIC OFFERING (5,763) (7,522) —
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON AND SUBORDINATED UNITS SUBSEQUENT TO INITIAL PUBLIC OFFERING $14,437
 $(108,017) $—
ALLOCATION OF NET INCOME (LOSS) SUBSEQUENT TO INITIAL PUBLIC OFFERING ATTRIBUTABLE TO:  
  
  
General partner interest $—
 $—
  
Common units 24,669
 (54,326)  
Subordinated units (10,232) (53,691)  
  $14,437
 $(108,017)  
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON AND SUBORDINATED UNIT:  
  
  
Per common unit (basic) $0.26
 $(0.56)  
Weighted average common units outstanding (basic) 96,073
 96,182
  
Per subordinated unit (basic) $(0.11) $(0.56)  
Weighted average subordinated units outstanding (basic) 95,138
 95,057
  
Per common unit (diluted) $0.26
 $(0.56)  
Weighted average common units outstanding (diluted) 96,243
 96,182
  
Per subordinated unit (diluted) $(0.11) $(0.56)  
Weighted average subordinated units outstanding (diluted) 95,138
 95,057
  

BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



The following units of potentially dilutive securities were excluded from the computation of diluted weighted average units outstanding because their inclusion would be anti-dilutive:
For the Year Ended December 31,
201920182017
(in thousands)
Potentially dilutive securities (common units):
Series A redeemable preferred units on an as-converted basis—  189  996  
Series B cumulative convertible preferred units on an as-converted basis14,968  —  1,612  
14,968  189  2,608  
Potentially dilutive securities (subordinated units):
Series A redeemable preferred units on an as-converted basis—  —  1,304  

NOTE 15—14 — COMMON UNIT REPURCHASE PROGRAMAND SUBORDINATED UNITS


Common and Subordinated Units

The common units and subordinated units represent 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 Black Stone Minerals Company, L.P. prior to the IPO, their transferees, persons who acquired such units with the prior approval of the Board, 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.
The holders of common units are and, prior to the end of the subordination period (as defined in the Partnership agreement), the subordinated units were, entitled to participate in distributions and exercise the rights and privileges provided to limited partners holding common units and subordinated units, respectively, under the partnership agreement. The subordination period under the partnership agreement ended on the first business day after the Partnership 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 were no outstanding arrearages on the common units. This test was met upon the payment of the distribution for the first quarter of 2019. Accordingly, each outstanding subordinated unit converted into one common unit on May 24, 2019 and the priority right of the common unitholders ceased to exist.
The partnership agreement generally provides that any distributions are paid each quarter 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; and
•second, to the holders of common units.
F-31
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table provides information about the Partnership's per unit distributions to common and subordinated unitholders:
Year Ended December 31,
201920182017
DISTRIBUTIONS DECLARED AND PAID:
Per common unit$1.48  $1.33  $1.20  
Per subordinated unit1
0.74  1.13  0.79  
1 For the six months ended December 31, 2019 there were no distributions on subordinated units as all subordinated units converted into common units on May 24, 2019.
Common Unit Repurchase Program
On March 4, 2016,November 5, 2018, the Board of Directors of the Partnership's general partner (the “Board”) authorized the repurchase of up to $50.0$75.0 million in common units through a program that terminated on September 15, 2016.units. The repurchase program authorizedauthorizes 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. TheIn 2019, the Partnership repurchased a total of 1.3 million136,665 common units for an aggregate cost of $20.2$2.2 million. As of December 31, 2019, the Partnership has repurchased $4.2 million .in common units under the repurchase program since inception. The repurchase program wasis funded from the Partnership's cash on hand or available revolving credit facility. Repurchasedavailability under the Credit Facility. Any repurchased units are canceled.
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 were canceled.representing limited partner interests having an aggregate offering amount of up to $100,000,000. Sales of common units, if any, may be made in negotiated transactions or transactions that are deemed to be “at the market” offerings as defined in Rule 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.
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.
For the year ended December 31, 2019, the Partnership sold 0 common units under the ATM Program. For the year ended December 31, 2018, the Partnership sold 2,243,775 common units under the ATM Program for net proceeds of $40.5 million. For the year ended December 31, 2017, the Partnership sold 2,001,823 common units under the ATM Program for net proceeds of $32.5 million.
NOTE 16—15 — SUBSEQUENT EVENTS
Distribution
On February 9, 2017,5, 2020, the Board approved a distribution for the period from October 1, 20162019 to December 31, 20162019 of $0.2875$0.30 per common unit and $0.18375 per subordinated unit. Distributions were paid on February 27, 201724, 2020 to unitholders of record at the close of business on February 20, 2017.17, 2020.
During January 2017, the Partnership closed four mineral interest transactions in Loving County, Texas for approximately $32.0 million in cash, with borrowings from the Senior Credit facility,
F-32
BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

General and $11.8 million of the Partnership's common units. Two Haynesville/Bossier Shale mineral interest transactions closed for $6.4 million. Two additional mineral interest acquisitions closed in Angelina County, Texas for approximately $8.6 million.Administrative Expense Reductions
On February 2, 2017 the Partnership filed a shelf registration statement, on Form S-3, with the U.S. Securities and Exchange Commission for the issuance of the Partnership's common units. The filing became effective on February 8, 2017.

On February 15, 2017, the Board granted 750,892 restricted common units and 438,067 restricted performance units at a grant-date fair value of $18.30 per unit under the 2015 LTIP.
On February 21, 2017, the Partnership announced that it had entered into a farmout agreement with Canaan Resource Partners ("Canaan") which covers certain Haynesville and Bossier shale acreage in San Augustine County, Texas operated by XTO Energy Inc. The Partnership has an average 50% working interesttaken significant steps to reduce its general and administrative expenses, including broad workforce reductions and lower Board and executive compensation levels. The Partnership expects to incur a one-time cash charge of approximately $5 million in the acreage and is the largest mineral owner. A totalfirst quarter of 58 wells are anticipated to be drilled over an initial phase, beginning2020 associated with wells spud after January 1, 2017. At its option, Canaan may participate in two additional phases with each phase estimated to last approximately two years. During the 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 costsseverance agreements for those wells on a well-by-well basis. The Partnership will receive a base overriding royalty interest (“ORRI”) before payout and an additional ORRI after payout on all wells drilled under the agreement. The execution of this agreement is anticipated to reduce the Partnership's future capital obligations by approximately $30-$35 million in 2017 and by an average of $40-$50 million annually, thereafter.affected employees.

F-33
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,Texas, Louisiana, and North Dakota, Oklahoma, Pennsylvania, Texas, West Virginia, and Wyoming.Dakota. 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 United States.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,
 Year Ended December 31, 201920182017
 2016 2015 2014 (in thousands)
 (In thousands)
Acquisition Costs of Properties:1
      
Acquisition Costs of Properties1:
Acquisition Costs of Properties1:
   
Proved $40,242
 $2,302
 $13,215
Proved$2,288  $13,438  $96,596  
Unproved 100,888
 60,994
 35,706
Unproved41,643  136,079  383,535  
Exploration Costs 645
 2,592
 631
Exploration Costs3  13,544  618  
Development Costs 73,316
 60,056
 50,595
Development Costs1
Development Costs1
34,617  165,198  81,056  
Total $215,091
 $125,944
 $100,147
Total$78,551  $328,259  $561,805  
 
1.
See Note 4 – Acquisitions for further discussion. Unproved properties also include purchases of leasehold prospects.

1 See Note 4 – Oil and Natural Gas Properties for further discussion. Unproved properties include purchases of leasehold prospects. Development costs include costs incurred on farmout wells subject to reimbursement under the Partnership's farmout agreements.

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,
 20192018
 (in thousands)
Proved properties1
$2,228,893  $2,377,305  
Unproved properties1,073,447  1,063,883  
Total3,302,340  3,441,188  
Accumulated depreciation, depletion, amortization, and impairment(1,870,412) (1,865,692) 
Oil and natural gas properties, net$1,431,928  $1,575,496  
1 Proved properties include capitalized costs related to farmout wells not yet assigned.
F-34
  As of December 31,
  2016 2015
  (In thousands)
Proved properties $2,091,337
 $1,957,648
Unproved properties 605,736
 524,563
Total 2,697,073
 2,482,211
Accumulated depreciation, depletion, amortization, and impairment (1,652,930) (1,543,796)
Oil and natural gas properties, net $1,044,143
 $938,415



Oil and Natural Gas Reserve Information—UnauditedInformation
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, 201618,368  270,339  63,425  
Revisions of previous estimates 1
(2,298) 14,505  120  
Purchases of minerals in place2
2,335  31,323  7,555  
Extensions, discoveries and other additions3
3,046  43,886  10,360  
Production(3,552) (59,779) (13,515) 
Net proved reserves at December 31, 201717,899  300,274  67,945  
Revisions of previous estimates1
(35) (11,027) (1,873) 
Purchases of minerals in place4
227  419  297  
Extensions, discoveries and other additions3
4,438  95,976  20,434  
Production(4,962) (71,622) (16,899) 
Net proved reserves at December 31, 201817,567  314,020  69,904  
Revisions of previous estimates1
951  19,136  4,140  
Purchases of minerals in place4
46  279  92  
Extensions, discoveries and other additions3
3,263  53,158  12,123  
Production(4,777) (77,635) (17,716) 
Net proved reserves at December 31, 201917,050  308,958  68,543  
Net Proved Developed Reserves5
         
December 31, 201717,891  233,017  56,727  
December 31, 201817,567  278,233  63,939  
December 31, 201917,050  263,371  60,945  
Net Proved Undeveloped Reserves6
         
December 31, 20178  67,257  11,218  
December 31, 2018—  35,787  5,965  
December 31, 2019—  45,587  7,598  
  
Crude Oil
(MBbl)
 
Natural Gas
(MMcf)
 
Total
(MBoe)
Net proved reserves at December 31, 2013 18,949
 239,960
 58,942
Revisions of previous estimates1
 (1,904) (20,764) (5,365)
Purchases of minerals in place2
 89
 7,439
 1,329
Extensions, discoveries and other additions3
 2,938
 19,894
 6,254
Production (3,005) (42,273) (10,051)
Net proved reserves at December 31, 2014 17,067
 204,256
 51,109
Revisions of previous estimates1
 (197) (17,043) (3,037)
Purchases of minerals in place4
 8
 367
 69
Extensions, discoveries and other additions5
 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 place6
 1,322
 5,683
 2,269
Extensions, discoveries and other additions7
 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
Net Proved Developed Reserves8
  
  
  
December 31, 2014 16,700
 202,888
 50,514
December 31, 2015 15,497
 174,555
 44,590
December 31, 2016 18,150
 223,057
 55,327
Net Proved Undeveloped Reserves9
  
  
  
December 31, 2014 367
 1,368
 595
December 31, 2015 345
 29,120
 5,198
December 31, 2016 218
 47,282
 8,098
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-royaltymineral and royalty reserves primarily located throughoutin East Texas, including in the Eagle Ford ShalePermian Basin, and Wolfcamp plays and working interest reserves, the substantial majority of which is located in the Haynesville/Bossier play in San Augustine County, Texas.Williston Basin.
3 Includes discoveriesextensions and additions primarily related to active drilling in the Haynesville/Bossier, Bakken/Three Forks, Eagle Ford Shale, Wilcox, Granite Wash, and Fayetteville plays.activities within multiple basins.
4 Includes the acquisition of mineral-and-royaltymineral and royalty reserves primarily in the MarcellusEast Texas 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 the Permian and Denver basins.Basin.
75 Includes extensions and additions primarily related to the active drilling program in the Haynesville/Bossier play.
8 Proved developed reserves of 74 MBoe, 84 MBoe and 87 MBoe asAs of December 31, 2016, 2015,2018 and 2014, respectively,2019, 0 proved developed reserves were attributable to noncontrolling interests in the Partnership’sPartnership's consolidated subsidiaries.
9 As of December 31, 2017, proved developed reserves of 61 MBoe were attributable to noncontrolling interests.
6 As of December 31, 2018, 2017, and 2016, 2015, and 2014, no0 proved undeveloped reserves were attributable to noncontrolling interests.



F-35


Standardized Measure of Discounted Future Net Cash Flows—UnauditedFlows
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, Year Ended December 31,
 2016 2015 2014 201920182017
 (In thousands) (in thousands)
Future cash inflows $1,267,179
 $1,211,290
 $2,493,294
Future cash inflows$1,619,147  $2,038,508  $1,643,582  
Future production costs (193,749) (205,861) (405,833)Future production costs(177,550) (222,342) (211,064) 
Future development costs (36,509) (84,746) (64,968)Future development costs(54,132) (58,403) (70,111) 
Future income tax expense (3,516) —
 —
Future income tax expense(5,244) (6,333) (2,655) 
Future net cash flows (undiscounted) 1,033,405
 920,683
 2,022,493
Future net cash flows (undiscounted)1,382,221  1,751,430  1,359,752  
Annual discount 10% for estimated timing (430,390) (365,711) (879,399)Annual discount 10% for estimated timing(534,327) (663,814) (497,103) 
Total1
 $603,015
 $554,972
 $1,143,094
Total1
$847,894  $1,087,616  $862,649  
 
1 Includes standardized measure of discounted future net cash flows of approximately $0.6 million, $0.7 million, and $1.4$0.5 million for December 31, 2016, 2015, and 2014,2017 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, Year Ended December 31,
 2016 2015 2014 201920182017
 (In thousands) (in thousands)
Standardized measure, beginning of year $554,972
 $1,143,094
 $1,185,257
Standardized measure, beginning of year$1,087,616  $862,649  $603,015  
Sales, net of production costs (210,354) (222,206) (391,983)Sales, net of production costs(384,745) (475,742) (295,941) 
Net changes in prices and production costs related to future production (81,456) (621,065) 75,284
Net changes in prices and production costs related to future production(229,651) 275,091  161,221  
Extensions, discoveries and improved recovery, net of future production and development costs 86,606
 165,020
 209,651
Extensions, discoveries and improved recovery, net of future production and development costs186,424  370,695  166,616  
Previously estimated development costs incurred during the period 28,909
 7,084
 12,162
Previously estimated development costs incurred during the period—  14,509  11,118  
Revisions of estimated future development costs —
 669
 7,854
Revisions of estimated future development costs1,198  (558) 2,653  
Revisions of previous quantity estimates, net of related costs 147,507
 (67,911) (110,431)Revisions of previous quantity estimates, net of related costs51,405  (5,401) 60,476  
Accretion of discount 55,662
 114,309
 118,526
Accretion of discount109,158  86,441  60,512  
Purchases of reserves in place, less related costs 34,751
 584
 24,210
Purchases of reserves in place, less related costs1,730  8,975  113,342  
Other (13,582) 35,394
 12,564
Changes in timing and otherChanges in timing and other24,759  (49,043) (20,363) 
Net increase (decrease) in standardized measures 48,043
 (588,122) (42,163)Net increase (decrease) in standardized measures(239,722) 224,967  259,634  
Standardized measure, end of year $603,015
 $554,972
 $1,143,094
Standardized measure, end of year$847,894  $1,087,616  $862,649  
 
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-36

Selected Quarterly Financial Information—Unaudited
Quarterly financial data was as follows for the periods indicated. 
 First
Quarter		Second
Quarter		Third
Quarter		Fourth
Quarter
 (In thousands, except for per unit data)
2019
Total revenue$83,806  $163,618  $137,369  $103,028  
Income (loss) from operations14,594  100,666  75,233  44,679  
Net income (loss)9,017  95,087  70,247  40,017  
Net income (loss) attributable to the general partner and common and subordinated units3,767  89,837  64,997  34,767  
Net income (loss) attributable to common and subordinated units per unit (basic)1
Per common unit (basic)$0.02  $0.45  $0.32  $0.17  
Per subordinated unit (basic)0.02  0.39  —  —  
Net income (loss) attributable to common and subordinated units per unit (diluted)1
Per common unit (diluted)$0.02  $0.44  $0.32  $0.17  
Per subordinated unit (diluted)0.02  0.39  —  —  
Cash distributions declared and paid per limited partner unit
Per common  unit$0.3700  $0.3700  $0.3700  $0.3700  
Per subordinated unit0.3700  0.3700  —  —  
Total assets$1,711,887  $1,724,555  $1,595,813  $1,545,208  
Long-term debt435,000  436,000  413,000  394,000  
Total mezzanine equity298,361  298,361  298,361  298,361  
2018    
Total revenue$114,494  $109,309  $139,718  $246,047  
Income (loss) from operations47,960  33,524  66,180  170,717  
Net income (loss)41,957  28,690  60,775  164,138  
Net income (loss) attributable to the general partner and common and subordinated units36,655  23,488  55,503  158,865  
Net income (loss) attributable to common and subordinated units per unit (basic)1
Per common unit (basic)$0.23  $0.17  $0.27  $0.78  
Per subordinated unit (basic)0.13  0.06  0.27  0.78  
Net income (loss) attributable to common and subordinated units per unit (diluted)1
Per common unit (diluted)$0.23  $0.17  $0.27  $0.72  
Per subordinated unit (diluted)0.13  0.06  0.27  0.78  
Cash distributions declared and paid per limited partner unit
Per common unit$0.3125  $0.3125  $0.3375  $0.3700  
Per subordinated unit0.2088  0.2087  0.3375  0.3700  
Total assets$1,635,978  $1,669,464  $1,754,259  $1,750,124  
Long-term debt436,000  421,000  402,000  410,000  
Total mezzanine equity300,644  298,361  298,361  298,361  
  First Quarter Second Quarter Third Quarter 
Fourth Quarter2
  (In thousands, except for per unit data)
2016        
Total revenue $64,381
 $40,569
 $99,171
 $56,712
Income (loss) from operations 11,610
 (19,478) 39,316
 (3,979)
Net income (loss) 10,749
 (20,810) 37,535
 (7,286)
Net income (loss) attributable to the general partner and common 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) .09
 (0.08) 0.24
 0.01
Per subordinated unit (basic) .01
 (0.15) 0.14
 (0.11)
Net income (loss) attributable to common and subordinated units per unit (diluted)1
  
      
Per common unit (diluted) .09
 (0.08) 0.24
 0.01
Per subordinated unit (diluted) .01
 (0.15) 0.14
 (0.11)
Cash distributions declared and paid per limited partner unit  
      
Per common  unit 0.2625
 0.2625
 0.2875
 0.2875
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
2015        
Total revenue $91,061
 $64,803
 $137,020
 $100,040
Net income (loss) 17,299
 (122,766) 53,892
 (49,730)
Net income (loss) attributable to the general partner and common and subordinated units * (107,587) 50,916
 (51,346)
Net income (loss) attributable to common and subordinated units per unit (basic)1
        
Per common unit (basic) * (0.56) 0.27
 (0.27)
Per subordinated unit (basic) * (0.56) 0.27
 (0.27)
Net income (loss) attributable to common and subordinated units per unit (diluted)1
    
  
  
Per common unit (diluted) * (0.56) 0.27
 (0.27)
Per subordinated unit (diluted) * (0.56) 0.27
 (0.27)
Cash distributions declared per limited partner unit        
Per common  unit * * 0.1615
 0.2625
Per subordinated unit * * 0.1615
 0.2625
Total assets $1,274,291
 $1,118,569
 $1,161,446
 $1,061,436
Long-term debt 389,000
 6,000
 43,000
 66,000
Total mezzanine equity 120,889
 120,904
 120,936
 79,162

* Information is not applicable for the periods prior to the initial public offering.
1 See Note 1413 – 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-32
F-37