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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM10-Q
  
(Mark One)
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended March 31, 2021
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period _______________ to _______________
Commission File Number: 001-37362
Black Stone Minerals, L.P.
(Exact name of registrant as specified in its charter)
 
Delaware 47-1846692
(State or other jurisdiction of
incorporation or organization)
 (I.R.S. Employer
Identification No.)
   
1001 Fannin Street, Suite 2020 77002
Houston,Texas
(Address of principal executive offices) (Zip 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
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  No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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  No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act. 
Large accelerated filer Accelerated filer
Non-accelerated filer(Do not check if a smaller reporting company)Smaller reporting company
Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes  No 
As of April 30, 2021, there were 207,552,011 common units and 14,711,219 Series B cumulative convertible preferred units of the registrant outstanding.




TABLE OF CONTENTS
 
  Page
 
 
 
 
 
 




ii


PART I – FINANCIAL INFORMATION

Item 1. Financial Statements 


BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In thousands)
 March 31, 2021December 31, 2020
ASSETS  
CURRENT ASSETS  
Cash and cash equivalents$3,789 $1,796 
Accounts receivable59,288 61,908 
Commodity derivative assets315 1,149 
Prepaid expenses and other current assets1,393 1,668 
TOTAL CURRENT ASSETS64,785 66,521 
PROPERTY AND EQUIPMENT  
Oil and natural gas properties, at cost, using the successful efforts method of accounting, includes unproved properties of $937,464 at March 31, 2021 and December 31, 2020
3,164,065 3,157,818 
Accumulated depreciation, depletion, amortization, and impairment(2,009,867)(1,987,332)
Oil and natural gas properties, net1,154,198 1,170,486 
Other property and equipment, net of accumulated depreciation of $12,453 and $12,292 at March 31, 2021 and December 31, 2020, respectively
1,492 1,650 
NET PROPERTY AND EQUIPMENT1,155,690 1,172,136 
DEFERRED CHARGES AND OTHER LONG-TERM ASSETS5,674 5,321 
TOTAL ASSETS$1,226,149 $1,243,978 
LIABILITIES, MEZZANINE EQUITY, AND EQUITY 
CURRENT LIABILITIES 
Accounts payable$2,219 $3,407 
Accrued liabilities8,382 15,568 
Commodity derivative liabilities44,447 19,318 
Other current liabilities1,736 1,654 
TOTAL CURRENT LIABILITIES56,784 39,947 
LONG–TERM LIABILITIES 
Credit facility111,000 121,000 
Accrued incentive compensation243 766 
Commodity derivative liabilities 1,848 
Asset retirement obligations17,503 17,377 
Other long-term liabilities3,829 4,073 
TOTAL LIABILITIES189,359 185,011 
COMMITMENTS AND CONTINGENCIES (Note 7)
MEZZANINE EQUITY  
Partners' equity – Series B cumulative convertible preferred units, 14,711 units outstanding at March 31, 2021 and December 31, 2020
298,361 298,361 
EQUITY 
Partners' equity – general partner interest  
Partners' equity – common units, 207,542 and 206,749 units outstanding at March 31, 2021 and December 31, 2020, respectively
738,429 760,606 
TOTAL EQUITY738,429 760,606 
TOTAL LIABILITIES, MEZZANINE EQUITY, AND EQUITY$1,226,149 $1,243,978 
The accompanying notes are an integral part of these unaudited consolidated financial statements.
1



BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(In thousands, except per unit amounts)

Three Months Ended March 31,
 20212020
REVENUE  
Oil and condensate sales$44,176 $52,093 
Natural gas and natural gas liquids sales42,889 36,642 
Lease bonus and other income2,385 4,308 
Revenue from contracts with customers89,450 93,043 
Gain (loss) on commodity derivative instruments(27,882)90,011 
TOTAL REVENUE61,568 183,054 
OPERATING (INCOME) EXPENSE  
Lease operating expense2,664 3,827 
Production costs and ad valorem taxes11,842 12,376 
Exploration expense1,073 1 
Depreciation, depletion, and amortization15,632 23,182 
Impairment of oil and natural gas properties 51,031 
General and administrative12,852 11,856 
Accretion of asset retirement obligations292 272 
TOTAL OPERATING EXPENSE44,355 102,545 
INCOME (LOSS) FROM OPERATIONS17,213 80,509 
OTHER INCOME (EXPENSE) 
Interest and investment income 31 
Interest expense(1,210)(4,427)
Other income (expense)183 (1)
TOTAL OTHER EXPENSE(1,027)(4,397)
NET INCOME (LOSS)16,186 76,112 
Distributions on Series B cumulative convertible preferred units(5,250)(5,250)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS$10,936 $70,862 
ALLOCATION OF NET INCOME (LOSS):   
General partner interest$ $ 
Common units10,936 70,862 
 $10,936 $70,862 
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:  
Per common unit (basic)$0.05 $0.34 
Per common unit (diluted)$0.05 $0.34 
WEIGHTED AVERAGE COMMON UNITS OUTSTANDING:
Weighted average common units outstanding (basic)207,442 206,631 
Weighted average common units outstanding (diluted)207,442 206,631 
 The accompanying notes are an integral part of these unaudited consolidated financial statements.
2



BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
(Unaudited)
(In thousands)
Common unitsPartners' equity — common unitsTotal equity
BALANCE AT DECEMBER 31, 2020206,749 $760,606 $760,606 
Repurchases of common units(223)(1,957)(1,957)
Restricted units granted, net of forfeitures1,016 — — 
Equity–based compensation— 5,353 5,353 
Distributions— (36,272)(36,272)
Charges to partners' equity for accrued distribution equivalent rights— (237)(237)
Distributions on Series B cumulative convertible preferred units— (5,250)(5,250)
Net income (loss)— 16,186 16,186 
BALANCE AT MARCH 31, 2021207,542 $738,429 $738,429 
 
Common unitsPartners' equity — common unitsTotal equity
BALANCE AT DECEMBER 31, 2019205,960 $798,443 $798,443 
Repurchases of common units(503)(5,029)(5,029)
Restricted units granted, net of forfeitures1,238 — — 
Equity–based compensation— 1,159 1,159 
Distributions— (61,641)(61,641)
Charges to partners' equity for accrued distribution equivalent rights— (68)(68)
Distributions on Series B cumulative convertible preferred units— (5,250)(5,250)
Net income (loss)— 76,112 76,112 
BALANCE AT MARCH 31, 2020206,695 $803,726 $803,726 
The accompanying notes are an integral part of these unaudited consolidated financial statements.
3



BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In thousands)

Three Months Ended March 31,
 20212020
CASH FLOWS FROM OPERATING ACTIVITIES  
Net income (loss)$16,186 $76,112 
Adjustments to reconcile net income (loss) to net cash provided by operating activities: 
Depreciation, depletion, and amortization15,632 23,182 
Impairment of oil and natural gas properties 51,031 
Accretion of asset retirement obligations292 272 
Amortization of deferred charges257 260 
(Gain) loss on commodity derivative instruments27,882 (90,011)
Net cash (paid) received on settlement of commodity derivative instruments(4,523)8,954 
Equity-based compensation3,462 (2,894)
Exploratory dry hole expense1,049  
Changes in operating assets and liabilities:
Accounts receivable2,620 19,693 
Prepaid expenses and other current assets275 (827)
Accounts payable, accrued liabilities, and other(7,341)(14,269)
Settlement of asset retirement obligations(105)(53)
NET CASH PROVIDED BY OPERATING ACTIVITIES55,686 71,450 
CASH FLOWS FROM INVESTING ACTIVITIES  
Acquisitions of oil and natural gas properties (28)
Additions to oil and natural gas properties(191)(3,548)
Additions to oil and natural gas properties leasehold costs(21) 
Purchases of other property and equipment(2)(2)
Proceeds from the sale of oil and natural gas properties 1,266 
Proceeds from farmouts of oil and natural gas properties 3,703 
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES(214)1,391 
CASH FLOWS FROM FINANCING ACTIVITIES  
Distributions to common unitholders(36,272)(61,641)
Distributions to Series B cumulative convertible preferred unitholders(5,250)(5,250)
Repurchases of common units(1,957)(5,029)
Borrowings under credit facility39,000 67,000 
Repayments under credit facility(49,000)(73,000)
NET CASH USED IN FINANCING ACTIVITIES(53,479)(77,920)
NET CHANGE IN CASH AND CASH EQUIVALENTS1,993 (5,079)
CASH AND CASH EQUIVALENTS – beginning of the period1,796 8,119 
CASH AND CASH EQUIVALENTS – end of the period$3,789 $3,040 
SUPPLEMENTAL DISCLOSURE  
Interest paid$941 $4,173 
 The accompanying notes are an integral part of these unaudited consolidated financial statements.
4


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


NOTE 1 - BUSINESS AND BASIS OF PRESENTATION
Description of the Business
Black Stone Minerals, L.P. (“BSM” or the “Partnership”) is a publicly traded Delaware limited partnership that owns oil and natural gas mineral interests, which make up the vast majority of the asset base. The Partnership's assets also include nonparticipating royalty interests and overriding royalty interests. These interests, which are substantially non-cost-bearing, are collectively referred to as “mineral and royalty interests.” The Partnership’s mineral and royalty interests are located in 41 states in the continental United States ("U.S."), including all of the major onshore producing basins. The Partnership also owns non-operated working interests in certain oil and natural gas properties. The Partnership's common units trade on the New York Stock Exchange under the symbol "BSM."
Basis of Presentation
The accompanying unaudited interim consolidated financial statements of the Partnership have been prepared in accordance with generally accepted accounting principles ("GAAP") in the United States and pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). These unaudited interim consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q and, therefore, do not include all disclosures required for financial statements prepared in conformity with GAAP. Accordingly, the accompanying unaudited interim consolidated financial statements and related notes should be read in conjunction with the Partnership’s consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2020 ("2020 Annual Report on Form 10-K").
The unaudited interim consolidated financial statements include the consolidated results of the Partnership. The results of operations for the three months ended March 31, 2021 are not necessarily indicative of the results to be expected for the full year.
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 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 using fair value or cost minus impairment if fair value is 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 (loss) and equity.
The unaudited interim 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 unaudited interim consolidated balance sheets, statements of operations, and statements of cash flows.
Segment Reporting
The Partnership operates in a single operating and reportable segment. Operating segments are defined as components of 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.
5


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

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Significant Accounting Policies
Significant accounting policies are disclosed in the Partnership’s 2020 Annual Report on Form 10-K. There have been no changes in such policies or the application of such policies during the three months ended March 31, 2021.
Accounts Receivable

The following table presents information about the Partnership's accounts receivable:
March 31, 2021December 31, 2020
(in thousands)
Accounts receivable:
Revenues from contracts with customers$55,297 $58,181 
Other3,991 3,727 
Total accounts receivable$59,288 $61,908 

NOTE 3 - OIL AND NATURAL GAS PROPERTIES    
Divestitures
In the third quarter of 2020, the Partnership closed two separate divestitures of certain mineral and royalty properties in the Permian Basin for total proceeds, after closing adjustments, of $150.6 million. One of these transactions, effective May 1, 2020, involved the sale of the Partnership's mineral and royalty interest in specific tracts in Midland County, Texas for net proceeds of approximately $54.5 million. The other transaction, effective July 1, 2020, involved the sale of an undivided interest across parts of the Partnership's Delaware Basin and Midland Basin positions for net proceeds of approximately $96.1 million. The total book value of the assets divested through these transactions was $126.6 million at the time of sale. The Partnership recognized a $24.0 million gain associated with the divestitures in the third quarter of 2020.
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
In February 2017, the Partnership 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"), a subsidiary of Exxon Mobil Corporation. The Partnership has an approximate 50% working interest in the acreage and is the largest mineral owner. During the first three phases of the farmout 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 ORRI before payout and an increased ORRI after payout on all wells drilled under the agreement.
6


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

Canaan has participated in a total of 37 wells under the farmout agreement through March 31, 2021, covering two election phases. In 2019, XTO Energy Inc. suspended its development activities in the area due to low natural gas prices. Canaan has the right to elect to continue its participation in a third phase covering up to 20 future wells drilled under the farmout agreement should XTO resume drilling activity.
Pivotal Farmout
In November 2017, the Partnership entered into a farmout agreement (the "First Pivotal Farmout") 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 in wells operated by XTO Energy and BPX Energy 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 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. As of March 31, 2021, a total of 68 wells have been spud in the contract area subject to the First Pivotal Farmout. 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 that remains subject to the First Pivotal Farmout.
In the second quarter of 2020, the Partnership entered into a development agreement with Aethon Energy ("Aethon") to develop certain portions of the area forfeited by BPX Energy in Angelina County, Texas. The agreement provides for minimum well commitments by Aethon in exchange for reduced royalty rates and exclusive access to our mineral and leasehold acreage in the contract area. The agreement calls for a minimum of four wells to be drilled in the initial program year, which began in the third quarter of 2020, increasing to a minimum of 15 wells per year beginning with the third program year. In November 2020, the Partnership entered into a new farmout agreement (the "Second Pivotal Farmout") with Pivotal. The Second Pivotal Farmout supersedes and replaces the First Pivotal Farmout with respect to the area covered by the Aethon development agreement. The Second Pivotal Farmout covers the Partnership's share of working interest under active development by Aethon in Angelina County, Texas and continues until April 2028, unless earlier terminated in accordance to the terms of the agreement. Pivotal will earn 100% of the Partnership's working interest (ranging from approximately 12.5% to 25% on an 8/8ths basis) in wells drilled and operated by Aethon in accordance with the development agreement. Pivotal is obligated to fund the development of all wells drilled by Aethon in the initial program year and thereafter, Pivotal has certain rights and options to continue funding the Partnership's working interests for the duration of the Second Pivotal Farmout. 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. As of March 31, 2021, a total of two wells have been spud in the contract area subject to the Second Pivotal Farmout.
From the inception of the farmout agreements through March 31, 2021, the Partnership has received $90.2 million and $119.2 million from Canaan and Pivotal, respectively, under the agreements. When such reimbursements are received prior to assigning the wells to Canaan and 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 Canaan and Pivotal, the Partnership's Oil and natural gas properties and Other long-term liabilities are reduced by the reimbursed capital costs. As of March 31, 2021 and December 31, 2020, $0.1 million was included in the Other long-term liabilities line item of the consolidated balance sheets for reimbursements received associated with farmed-out working interests not yet assigned to Canaan and Pivotal.
XTO Completions Agreement
In June 2020, the Partnership entered into a new incentive agreement with XTO with respect to certain drilled but uncompleted wells ("DUCs") in the Shelby Trough. The agreement allowed for royalty relief on 13 existing DUCs if XTO completed and turned the wells to sales by March 31, 2021. As of January 18, 2021, XTO had turned all 13 DUCs to sales.
7


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

Impairment of Oil and Natural Gas Properties
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.
There was a collapse in oil prices during the first quarter of 2020 due to geopolitical events that increased supply at the same time demand weakened due to the impact of the COVID-19 pandemic. The Partnership determined these events and circumstances indicated a possible decline in the recoverability of the carrying value of certain proved properties and recoverability testing determined that certain depletable units consisting of mature oil producing properties were impaired. The Partnership recognized no impairment of oil and natural gas properties for the three months ended March 31, 2021 and $51.0 million of impairment of oil and natural gas properties for the three months ended March 31, 2020. See Note 5 - Fair Value Measurements for further discussion.
NOTE 4 - COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS
The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To mitigate the inherent commodity price risk associated with its operations, the Partnership uses oil and natural gas commodity derivative financial instruments. From time to time, such instruments may include variable-to-fixed-price swaps, costless collars, fixed-price contracts and other contractual arrangements. The Partnership enters into oil and natural gas derivative contracts that contain netting arrangements with each counterparty. The Partnership does not enter into derivative instruments for speculative purposes.
As of March 31, 2021, the Partnership’s open derivative contracts consisted of fixed-price swap contracts. A fixed-price swap contract between the Partnership and the counterparty specifies a fixed commodity price and a future settlement date. The Partnership has not designated any of its contracts as fair value or cash flow hedges. Accordingly, the changes in the fair value of the contracts are included in the consolidated statement of operations in the period of the change. All derivative gains and losses from the Partnership’s derivative contracts have been recognized in revenue in the Partnership's accompanying consolidated statements of operations. Derivative instruments that have not yet been settled in cash are reflected as either derivative assets or liabilities in the Partnership’s accompanying consolidated balance sheets as of March 31, 2021 and December 31, 2020. See Note 5 - Fair Value Measurements for further discussion.    
The Partnership'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 March 31, 2021, the Partnership had seven counterparties, all of which are rated Baa1 or better by Moody’s and are lenders under the Credit Facility.
8


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

The tables below summarize the fair values and classifications of the Partnership’s derivative instruments, as well as the gross recognized derivative assets, liabilities, and amounts offset in the consolidated balance sheets as of each date:
March 31, 2021
ClassificationBalance Sheet LocationGross
Fair Value
Effect of Counterparty NettingNet Carrying Value on Balance Sheet
  (in thousands)
Assets:
    
Current asset
Commodity derivative assets$1,573 $(1,258)$315 
Long-term asset
Deferred charges and other long-term assets756  756 
 Total assets
 $2,329 $(1,258)$1,071 
Liabilities:
    
Current liability
Commodity derivative liabilities$45,705 $(1,258)$44,447 
Long-term liability
Commodity derivative liabilities   
Total liabilities
 $45,705 $(1,258)$44,447 

December 31, 2020
ClassificationBalance Sheet LocationGross
Fair Value
Effect of Counterparty NettingNet Carrying Value on Balance Sheet
  (in thousands)
Assets:
    
Current asset
Commodity derivative assets$6,362 $(5,213)$1,149 
Long-term asset
Deferred charges and other long-term assets   
 Total assets
 $6,362 $(5,213)$1,149 
Liabilities:
    
Current liability
Commodity derivative liabilities$24,531 $(5,213)$19,318 
Long-term liability
Commodity derivative liabilities1,848  1,848 
Total liabilities
 $26,379 $(5,213)$21,166 
Changes in the fair values of the Partnership’s derivative instruments (both assets and liabilities) are presented on a net basis in the accompanying consolidated statements of operations and consolidated statements of cash flows and consist of the following for the periods presented:
 Three Months Ended March 31,
Derivatives not designated as hedging instruments20212020
(in thousands)
Beginning fair value of commodity derivative instruments$(20,017)$15,221 
Gain (loss) on oil derivative instruments(24,854)77,811 
Gain (loss) on natural gas derivative instruments(3,028)12,200 
Net cash paid (received) on settlements of oil derivative instruments4,502 (1,541)
Net cash paid (received) on settlements of natural gas derivative instruments21 (7,413)
Net change in fair value of commodity derivative instruments(23,359)81,057 
Ending fair value of commodity derivative instruments$(43,376)$96,278 
9


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

The Partnership had the following open derivative contracts for oil as of March 31, 2021:
 Weighted Average Price (Per Bbl)Range (Per Bbl)
Period and Type of ContractVolume (Bbl)LowHigh
Oil Swap Contracts:    
2021    
First Quarter220,000 $38.97 $32.64 $46.50 
Second Quarter660,000 38.97 32.64 46.50 
Third Quarter660,000 38.97 32.64 46.50 
Fourth Quarter660,000 38.97 32.64 46.50 
2022
First Quarter150,000 $55.47 $55.29 $56.10 
Second Quarter150,000 55.47 55.29 56.10 
Third Quarter150,000 55.47 55.29 56.10 
Fourth Quarter150,000 55.47 55.29 56.10 

The Partnership had the following open derivative contracts for natural gas as of March 31, 2021:
 Weighted Average Price (Per MMBtu)Range (Per MMBtu)
Period and Type of ContractVolume (MMBtu)LowHigh
Natural Gas Swap Contracts:    
2021    
Second Quarter10,010,000 $2.69 $2.52 $3.08 
Third Quarter10,120,000 2.69 2.52 3.08 
Fourth Quarter10,120,000 2.69 2.52 3.08 

NOTE 5 - FAIR VALUE MEASUREMENTS
Fair value is defined as the amount at which an asset (or liability) could be bought (or incurred) or sold (or settled) in an orderly transaction between market participants at the measurement date. Further, ASC 820, Fair Value Measurement, establishes a framework for measuring fair value, establishes a fair value hierarchy based on the quality of inputs used to measure fair value, and includes certain disclosure requirements. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk.
ASC 820 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:
Level 1—Unadjusted quoted prices for identical assets or liabilities in active markets.
Level 2—Quoted prices for similar assets or liabilities in non-active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.
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.
10


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

The carrying value of the 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 March 31, 2021 and December 31, 2020 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 4 - Commodity Derivative Financial Instruments for further discussion.
The following table presents information about the Partnership’s assets and liabilities measured at fair value on a recurring basis: 
 Fair Value Measurements UsingEffect of Counterparty NettingTotal
 Level 1Level 2Level 3
 (in thousands)
As of March 31, 2021     
Financial Assets     
Commodity derivative instruments$ $2,329 $ $(1,258)$1,071 
Financial Liabilities     
Commodity derivative instruments$ $45,705 $ $(1,258)$44,447 
As of December 31, 2020     
Financial Assets     
Commodity derivative instruments$ $6,362 $ $(5,213)$1,149 
Financial Liabilities     
Commodity derivative instruments$ $26,379 $ $(5,213)$21,166 
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 estimated by discounting projected future cash 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 3 - Oil and Natural Gas Properties.
Oil and natural gas properties are measured at fair value on a non-recurring basis using the income approach when assessing for impairment. 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. The Partnership estimated the fair value of the impaired properties using published forward commodity price curves as of the measurement date of March 31, 2020, considering locational and quality differentials based on a review of historical realizations, and using an annual discount rate of 8%.
11


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

The following table presents information about the non-recurring fair value measurements of the impaired properties:
Fair Value Measurements UsingImpairment
Level 1Level 2Level 3
(in thousands)
Three Months Ended March 31, 2021
Impaired oil and natural gas properties$ $ $ $ 
Three Months Ended March 31, 2020
Impaired oil and natural gas properties$ $ $2,044 $51,031 
The Partnership’s estimates of fair value have been determined at discrete points in time based on relevant market data. These estimates involve uncertainty, particularly in the current volatile market, and cannot be determined with precision. Changes to these estimates, particularly related to economic reserves, future commodity prices, and timing of future production could result in additional impairment charges in the future. There were no significant changes in valuation techniques or related inputs as of March 31, 2021 or December 31, 2020.
NOTE 6 - CREDIT FACILITY
The Partnership maintains a senior secured revolving credit agreement, as amended (the “Credit Facility”). The Credit Facility has an aggregate maximum credit amount of $1.0 billion. The commitment of the 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. The Partnership and the lenders (at the direction of two-thirds of the lenders) each have discretion to request a borrowing base redetermination one time between scheduled redeterminations. The Partnership also has the right to request a redetermination following the acquisition of oil and natural gas properties in excess of 10% of the value of the borrowing base immediately prior to such acquisition. Effective November 3, 2020, the borrowing base redetermination reduced the borrowing base from $430.0 million to $400.0 million, and effective April 30, 2021, the borrowing base was reaffirmed at $400.0 million and the term of the Credit Facility was extended through November 1, 2024. Please see Item 5 of Part II of this quarterly report for a more detailed description of the amendment to the Credit Facility effective April 30, 2021. The next semi-annual redetermination is scheduled for October 2021.
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 the Prime Rate, the Federal Funds effective rate plus 0.50%, or 1-month LIBOR plus 1.00%) or LIBOR, in each case, plus the applicable margin. As of March 31, 2021 and December 31, 2020, the applicable margin for the alternative base rate ranged from 1.00% to 2.00% and the applicable margin for LIBOR ranged from 2.00% to 3.00%, depending on the borrowings outstanding in relation to the borrowing base. Effective April 30, 2021, the LIBOR margin was increased to between 2.50% and 3.50% and the alternative base rate margin was increased to between 1.50% and 2.50%.
The weighted-average interest rate of the Credit Facility was 2.37% and 2.40% as of March 31, 2021 and December 31, 2020, respectively. Accrued interest is payable at the end of each calendar quarter or at the end of each interest period, unless the interest period is longer than 90 days, in which case interest is payable at the end of every 90-day period. In addition, a commitment fee is payable at the end of each calendar quarter based on either a rate of 0.375% if the borrowing base utilization percentage is less than 50%, or 0.500% per annum if the borrowing base utilization percentage is equal to or greater than 50%. The Credit Facility is secured by substantially all of the Partnership’s oil and natural gas production and assets.
The Credit Facility contains various limitations on future borrowings, leases, hedging, and sales of assets. Additionally, the Credit Facility requires the Partnership to maintain a current ratio of not less than 1.0:1.0 and a ratio of total debt to EBITDAX (Earnings before Interest, Taxes, Depreciation, Amortization, and Exploration) of not more than 3.5:1.0. As of March 31, 2021, the Partnership was in compliance with all financial covenants in the Credit Facility.
12


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

The aggregate principal balance outstanding was $111.0 million and $121.0 million at March 31, 2021 and December 31, 2020, respectively. The unused portion of the available borrowings under the Credit Facility were $289.0 million and $279.0 million at March 31, 2021 and December 31, 2020, respectively.
On March 5, 2021, the U.K. Financial Conduct Authority announced that it intends to stop persuading or compelling banks to submit LIBOR rates after December 31, 2021 for the 1-week and 2-month U.S. dollar settings and after June 30, 2023 for the remaining U.S. dollar settings. Our Credit Facility includes provisions to determine a replacement rate for LIBOR if necessary during its term, based on the secured overnight financing rate published by the Federal Reserve Bank of New York (“SOFR”). We currently do not expect the transition from LIBOR to have a material impact on us.
NOTE 7 - COMMITMENTS AND CONTINGENCIES
Environmental Matters
The Partnership’s business includes activities that are subject to U.S. federal, state, and local environmental regulations with regard to air, land, and water quality and other environmental matters.
The Partnership does not consider the potential remediation costs that could result from issues identified in any environmental site assessments to be significant to the consolidated financial statements, and no provision for potential remediation costs has been 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 March 31, 2021 will be resolved without material adverse effect on the Partnership’s financial condition or operations. 
NOTE 8 - INCENTIVE COMPENSATION
The table below summarizes incentive compensation expense recorded in the General and administrative line item of the consolidated statements of operations for the periods presented:
 Three Months Ended March 31,
20212020
 (in thousands)
Cash—short and long-term incentive plans$1,385 $963 
Equity-based compensation—restricted common units949 1,285 
Equity-based compensation—restricted performance units1
2,161 (4,657)
Board of Directors incentive plan352 478 
 Total incentive compensation expense
$4,847 $(1,931)
1 Compensation expense related to the restricted performance awards is determined using the measurement-date (i.e., the last day of each reporting period date) fair value of the Partnership's common units. Downward cost revisions recognized in the three months ended March 31, 2020 are due to the decrease in the Partnership's common unit price period over period.
NOTE 9 - PREFERRED UNITS
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 for a cash purchase price of $20.3926 per Series B cumulative convertible preferred unit, resulting in total proceeds of approximately $300.0 million.
The Series B cumulative convertible preferred units are entitled to an annual distribution of 7%, payable on a quarterly basis in arrears. 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
13


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

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 $10.0 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 March 31, 2021 and December 31, 2020. The Series B cumulative convertible preferred units are classified as mezzanine equity on the consolidated balance sheets since certain provisions of redemption are outside the control of the Partnership.
NOTE 10 - 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 units have all the rights of a unitholder, including non-forfeitable distribution rights. As participating securities, the restricted common units are included in the calculation of basic earnings per unit. For the periods presented, the amount of earnings allocated to these participating units was not material.
Net income (loss) attributable to the Partnership is allocated to the Partnership’s general partner and the common unitholders in proportion to their pro rata ownership after giving effect to distributions, if any, declared during the period.
The Partnership assesses the Series B cumulative convertible preferred units on an as-converted basis for the purpose of calculating diluted 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.
The following table sets forth the computation of basic and diluted earnings per common unit:
 Three Months Ended March 31,
 20212020
 (in thousands, except per unit amounts)
NET INCOME (LOSS)$16,186 $76,112 
Distributions on Series B cumulative convertible preferred units(5,250)(5,250)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS10,936 70,862 
ALLOCATION OF NET INCOME (LOSS):  
General partner interest$ $ 
Common units10,936 70,862 
 $10,936 $70,862 
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:  
Per common unit (basic)$0.05 $0.34 
Per common unit (diluted)0.05 0.34 
WEIGHTED AVERAGE COMMON UNITS OUTSTANDING:
Weighted average common units outstanding (basic)207,442 206,631 
Effect of dilutive securities
  
Weighted average common units outstanding (diluted)207,442 206,631 

14


BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
NOTES TO UNAUDITED 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:
 Three Months Ended March 31,
20212020
(in thousands)
Potentially dilutive securities (common units):
Series B cumulative convertible preferred units on an
as-converted basis
14,969 14,969 

NOTE 11 - COMMON UNITS

Common Units

The common units represent limited partner interests in the Partnership. The holders of common units are entitled to participate in distributions and exercise the rights and privileges provided to limited partners holding common units under the partnership agreement. 

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, their transferees, persons who acquired such units with the prior approval of the board of directors of the Partnership's general partner (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 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.

The following table provides information about the Partnership's per unit distributions to common unitholders:
Three Months Ended March 31,
20212020
Distributions declared and paid per common unit$0.1750 $0.3000 

Common Unit Repurchase Program
On November 5, 2018, the Board authorized the repurchase of up to $75.0 million in common units. The repurchase program authorizes the Partnership to make repurchases on a discretionary basis as determined by management, subject to market conditions, applicable legal requirements, available liquidity, and other appropriate factors. The Partnership made no repurchases under this program for the three months ended March 31, 2021. As of March 31, 2021, the Partnership has repurchased $4.2 million in common units under the repurchase program since inception. The repurchase program is funded from the Partnership's cash on hand or availability on the Credit Facility. Any repurchased units are canceled.
NOTE 12 - SUBSEQUENT EVENTS    
On April 21, 2021, the Board approved a distribution for the three months ended March 31, 2021 of $0.175 per common unit. Distributions will be payable on May 21, 2021 to unitholders of record at the close of business on May 14, 2021.
On April 30, 2021, the Partnership amended its Credit Facility. Please see Item 5 of Part II of this quarterly report for a description of the amendment.
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In April 2021, the Partnership entered into an agreement with several operators to test and develop areas of the Austin Chalk in East Texas where the Partnership has significant acreage positions. Under the terms of the agreement, the operators will participate in three test wells targeting the Austin Chalk formation.
In April 2021, the Partnership entered into an agreement with a large, private independent operator ("Operator") to drill and complete multiple Austin Chalk wells on the Partnership's acreage within East Texas in 2021. If the initial wells are successful, the Operator has the option to expand the Austin Chalk development program on additional acreage owned by the Partnership.
In May 2021, the Partnership entered into an agreement with Aethon to develop certain of the Partnership's undeveloped acreage in San Augustine County. The agreement provides for minimum well commitments by Aethon in exchange for reduced royalty rates and exclusive access to the Partnership's mineral and leasehold acreage in the contract area. The agreement calls for a minimum of five wells to be drilled in the initial program year, which begins in the third quarter of 2021, increasing to a minimum of 12 wells per year beginning with the fourth program year. The Partnership's development agreement with Aethon and related drilling commitments covering its San Augustine County acreage is independent of the development agreement and associated commitments covering Angelina County.
In May 2021, the Partnership entered into an agreement to acquire mineral and royalty acreage in the northern Midland Basin for total consideration of $20.7 million. The purchase price will consist of $10.0 million in cash and $10.7 million in common units of the Partnership.

16


Item 2. 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 unaudited consolidated financial statements and notes thereto presented in this Quarterly Report on Form 10-Q, as well as our audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2020 ("2020 Annual Report on Form 10-K"). 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 II, Item 1A. Risk Factors.”
Cautionary Note Regarding Forward-Looking Statements
Certain statements and information in this Quarterly Report on Form 10-Q 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 scope and duration of the COVID-19 pandemic and actions taken by governmental authorities and other parties in response to the pandemic;

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, 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, including slowdowns, domestically and internationally and volatility in the securities, capital or credit markets;

competition in the oil and natural gas industry;

the level of drilling activity by our operators particularly in areas such as the Shelby Trough where we have concentrated acreage positions;

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

title defects in the properties in which we invest;

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

restrictions on the use of water for hydraulic fracturing;

the availability of pipeline capacity and transportation facilities;

17


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 filing.
For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see “Risk Factors” in our 2020 Annual Report on Form 10-K and in this Quarterly Report on Form 10-Q.
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.
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 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. We believe our large, diversified asset base and long-lived, non-cost-bearing mineral and royalty interests provide for stable production and reserves over time, allowing the majority of generated cash flow to be distributed to unitholders.
As of March 31, 2021, our mineral and royalty interests were located in 41 states in the continental United States, including all of the major onshore producing basins. These non-cost-bearing interests include ownership in over 70,000 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 produced is transferred to the customer and collectability of the sales price is 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
Shelby Trough Update
Angelina County
Aethon has successfully drilled the initial two wells under the development agreement covering Angelina County and expects to turn those wells to sales in the second quarter of 2021. Under the terms of that agreement, Aethon will drill a minimum of four wells on our acreage in the first program year ending in September 2021, escalating to a minimum of 15 wells per program year starting with the third program year.
San Augustine County
In March 2021, we reached an agreement with XTO Energy, Inc. (“XTO”) to partition jointly owned working interests in the Brent Miller development area in San Augustine County. Under the partition agreement, we exchanged working interests with XTO in certain existing and proposed drilling units, resulting in each company holding 100% of the working interests in their respective partitioned units.
18


In May 2021, we entered into an agreement with Aethon to develop certain of our undeveloped acreage in San Augustine County, including the working interests resulting from the partition agreement discussed above. The agreement provides for minimum well commitments by Aethon in exchange for reduced royalty rates and exclusive access to our mineral and leasehold acreage in the contract area. The agreement calls for a minimum of five wells to be drilled in the initial program year, which begins in the third quarter of 2021, increasing to a minimum of 12 wells per year beginning with the fourth program year. Our development agreement with Aethon and related drilling commitments covering its San Augustine County acreage is independent of the development agreement and associated commitments covering Angelina County.
Austin Chalk Update
In April 2021, we entered into an agreement with several operators to test and develop areas of the Austin Chalk in East Texas where we have significant acreage positions. Recent drilling results have shown that advances in fracturing and other completion techniques can dramatically improve well performance in existing Austin Chalk fields. Under the terms of the agreement, the operators will participate in three test wells targeting the Austin Chalk formation. Assuming the test well program is successful, we anticipate entering into separate agreements with each operator to further develop the acreage.
In April 2021, we also entered into an agreement with a large, private independent operator ("Operator") to drill and complete multiple Austin Chalk wells on our acreage within East Texas in 2021. If the initial wells are successful, the Operator has the option to expand the Austin Chalk development program on additional acreage owned by us.
Acquisition Update
In May 2021, we entered into an agreement to acquire mineral and royalty acreage in the northern Midland Basin for total consideration of $20.7 million. The purchase price will consist of $10.0 million in cash and $10.7 million in our common units. The acquisition is expected to close in the second quarter of 2021.
Business Environment
The information below is designed to give a broad overview of the oil and natural gas business environment as it affects us.
COVID-19 Pandemic and Market Conditions
The COVID-19 pandemic has adversely affected the global economy, disrupted global supply chains and created significant volatility in the financial markets. In addition, the pandemic has resulted in travel restrictions, business closures and the institution of quarantining and other restrictions on movement in many communities. To protect the health and well-being of our workforce in the wake of COVID-19, we have implemented remote work arrangements for all employees. We do not expect these arrangements to impact our ability to maintain operations. We will continue to prioritize the health and safety of our workforce when employees return to the office through frequent cleaning of common spaces, appropriate social distancing measures, and other best practices as recommended by state and local officials.
Commodity Prices and Demand
Oil and natural gas prices have been historically volatile based upon the dynamics of supply and demand. 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 impact of the COVID-19 pandemic has negatively affected the oil and natural gas business environment, primarily by causing a reduction in commercial activity and travel worldwide thereby lowering energy demand. This, in turn, resulted in periods of significantly lower market prices for oil, natural gas, and natural gas liquids ("NGLs"). The price environment in 2020 caused many of our operators to reduce their drilling and completion activity on our acreage, which negatively impacts our production volumes. Commodity prices have recovered in late 2020 and into 2021, reflecting expectations of rising demand as both COVID-19 vaccination rates and global economic activity increased, combined with ongoing crude oil production limits from members of the Organization of the Petroleum Exporting Countries and its broader partners. However, the current price environment remains uncertain as responses to the COVID-19 pandemic continue to evolve. Given the dynamic nature of these events, we cannot reasonably estimate the period of time that the COVID-19 pandemic and related market conditions will persist. While we use derivative instruments to partially mitigate the impact of commodity price volatility, our revenues and operating results depend significantly upon the prevailing prices for oil and natural gas.
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The current price environment, including the sharp decline in oil prices that began in March 2020, also caused us to determine that certain depletable units consisting of mature oil producing properties were impaired as of March 31, 2020. Therefore, we recognized impairment of oil and natural gas properties of $51.0 million in the first quarter of 2020. Additionally, the borrowing base under the Credit Facility takes into consideration the estimated loan value of our oil and natural gas properties. Effective November 3, 2020, the borrowing base redetermination reduced the borrowing base from $430.0 million to $400.0 million, and effective April 30, 2021, the borrowing base was reaffirmed at $400.0 million. The next borrowing base redetermination is expected in the fall of 2021. In a prolonged period of low commodity prices, we may be required to impair additional properties and the borrowing base under our Credit Facility could be further reduced. In light of the challenging business environment and uncertainty caused by the pandemic, the board of directors of our general partner (the "Board") also approved a reduction in the quarterly distribution for the first quarter of 2020 to increase the amount of retained free cash flow for debt reduction and balance sheet protection. The Board approved an increase in the quarterly distribution for the second and fourth quarters of 2020, but the distribution remains below 2019 levels.
The following table reflects commodity prices as of the last day of each quarter presented:
20212020
Benchmark Prices1
First QuarterFirst Quarter
WTI spot oil price ($/Bbl)$59.19 $20.51 
Henry Hub spot natural gas ($/MMBtu)2.52 1.71 
1 Source: EIA

Rig Count
As we are not the 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.
The following table shows the rig count as of the last day of each quarter presented:
20212020
U.S. Rotary Rig Count1
First QuarterFirst Quarter
Oil324 624 
Natural gas92 102 
Other
Total417 728 
1 Source: Baker Hughes Incorporated
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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. The EIA estimates that natural gas inventories concluded the withdrawal season in March 2021 at almost 1.8 Tcf, or 2% lower than the previous five-year average.
The following table shows natural gas storage volumes by region as of the last day of each quarter presented:
20212020
Region1
First QuarterFirst Quarter
East307 382 
Midwest401 476 
Mountain112 92 
Pacific194 197 
South Central749 840 
Total1,763 1,987 
1 Source: EIA
How We Evaluate Our Operations
We use a variety of operational and financial measures to assess our performance. Among the measures considered by management are the following:
volumes of oil and natural gas produced;
commodity prices including the effect of derivative instruments; and
Adjusted EBITDA and Distributable cash flow.
Volumes of Oil and Natural Gas Produced
In order to track and assess the performance of our assets, we monitor and analyze our production volumes from the various basins and plays that constitute our extensive asset base. We also regularly compare projected volumes to actual reported volumes and investigate unexpected variances.
Commodity Prices
Factors Affecting the Sales Price of Oil and Natural Gas
The prices we receive for oil, natural gas, and NGLs vary by geographical area. The relative prices of these products are determined by the factors affecting global and regional supply and demand dynamics, such as economic conditions, production levels, availability of transportation, weather cycles, and other factors. In addition, realized prices are influenced by product quality and proximity to consuming and refining markets. Any differences between realized prices and New York Mercantile Exchange ("NYMEX") prices are referred to as differentials. All our production is derived from properties located in the United States.
Oil. The substantial majority of our oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of our control. NYMEX light sweet crude oil, commonly referred to as West Texas Intermediate ("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.
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The chemical composition of 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 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”) gravity, and the presence and concentration of impurities, such as sulfur.
Location differentials generally result from transportation costs based on the produced oil’s proximity to consuming and refining markets and major trading points.
Natural Gas. The NYMEX price quoted at Henry Hub is a widely used benchmark for the pricing of natural gas in the United States. The actual volumetric prices realized from the sale of natural gas differ from the quoted NYMEX price as a result of quality and location differentials. 
Quality differentials result from the heating value of natural gas measured in Btus and the presence of impurities, such as hydrogen sulfide, carbon dioxide, and nitrogen. Natural gas containing ethane and heavier hydrocarbons has a higher Btu value and will realize a higher volumetric price than natural gas which is predominantly methane, which has a lower Btu value. Natural gas with a higher concentration of impurities will realize a lower volumetric price due to the presence of the impurities in the natural gas when sold or the cost of treating the natural gas to meet pipeline quality specifications.
Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply and demand conditions and the cost to transport natural gas to end user markets.
Hedging
We enter into derivative instruments to partially mitigate the impact of commodity price volatility on our cash generated from operations. From time to time, such instruments may include variable-to-fixed-price swaps, fixed-price contracts, costless collars, and other contractual arrangements. The impact of these derivative instruments could affect the amount of revenue we ultimately realize.
Our open derivative contracts consist of fixed-price swap contracts. Under fixed-price swap contracts, a counterparty is required to make a payment to us if the settlement price is less than the swap strike price. Conversely, we are required to make a payment to the counterparty if the settlement price is greater than the swap strike price. 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 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 March 31, 2021 are detailed in Note 4 - Commodity Derivative Financial Instruments to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.
Pursuant to the terms of our Credit Facility, we are allowed to hedge certain percentages of expected future monthly production volumes equal to the lesser of (i) internally forecasted production and (ii) the average of reported production for the most recent three months.
We are allowed to hedge up to 90% of such volumes for the first 24 months, 70% for months 25 through 36, and 50% for months 37 through 48. As of March 31, 2021, we have hedged 100% of our available oil and condensate hedge volumes and 81% of our available natural gas hedge volumes for 2021. As of March 31, 2021, we have also hedged 22% of our available oil and condensate hedge volumes for 2022.
We intend to continuously monitor the production from our assets and the commodity price environment, and will, from time to time, add additional hedges within the percentages described above related to such production for the following 12 to 30 months. We do not enter into derivative instruments for speculative purposes.
Non-GAAP Financial Measures
Adjusted EBITDA and Distributable cash flow 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
22


performance of our assets and our ability to sustain distributions over the long term without regard to financing methods, capital structure, or historical cost basis.
We define Adjusted EBITDA as net income (loss) before interest expense, income taxes, and depreciation, depletion, and amortization adjusted for impairment of oil and natural gas properties, accretion of asset retirement obligations, unrealized gains and losses on commodity derivative instruments, non-cash equity-based compensation, and gains and losses on sales of assets. We define Distributable cash flow as Adjusted EBITDA plus or minus amounts for certain non-cash operating activities, cash interest expense, distributions to preferred unitholders, and restructuring charges.
Adjusted EBITDA and Distributable cash flow should not be considered an alternative to, or more meaningful than, net income (loss), income (loss) from operations, cash flows from operating activities, or any other measure of financial performance presented in accordance with generally accepted accounting principles ("GAAP") in the United States as measures of our financial performance.
Adjusted EBITDA and Distributable cash flow have important limitations as analytical tools because they exclude some but not all items that affect net income (loss), the most directly comparable GAAP financial measure. Our computation of Adjusted EBITDA and Distributable cash flow may differ from computations of similarly titled measures of other companies.
The following table presents a reconciliation of net income (loss), the most directly comparable GAAP financial measure, to Adjusted EBITDA and Distributable cash flow for the periods indicated:
Three Months Ended March 31,
20212020
(in thousands)
Net income (loss)$16,186 $76,112 
Adjustments to reconcile to Adjusted EBITDA:
Depreciation, depletion, and amortization15,632 23,182 
Impairment of oil and natural gas properties— 51,031 
Interest expense1,210 4,427 
Income tax expense (benefit)(157)36 
Accretion of asset retirement obligations292 272 
Equity–based compensation3,462 (2,894)
Unrealized (gain) loss on commodity derivative instruments23,359 (81,057)
Adjusted EBITDA59,984 71,109 
Adjustments to reconcile to Distributable cash flow:
Change in deferred revenue(9)(302)
Cash interest expense(953)(4,168)
Preferred unit distributions(5,250)(5,250)
Restructuring charges1
— 4,815 
Distributable cash flow$53,772 $66,204 

1 Restructuring charges include non-recurring costs associated with broad workforce reductions in the first quarter of 2020.
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Results of Operations
Three Months Ended March 31, 2021 Compared to Three Months Ended March 31, 2020
The following table shows our production, revenues, pricing, and expenses for the periods presented:
 Three Months Ended March 31,
 20212020Variance
(Dollars in thousands, except for realized prices)
Production:    
Oil and condensate (MBbls)
829 1,163 (334)(28.7)%
Natural gas (MMcf)1
14,911 18,612 (3,701)(19.9)%
Equivalents (MBoe)3,314 4,265 (951)(22.3)%
Equivalents/day (MBoe)36.8 46.9 (10.1)(21.5)%
Realized prices, without derivatives:
Oil and condensate ($/Bbl)$53.29 $44.79 $8.50 19.0 %
Natural gas ($/Mcf)1
2.88 1.97 0.91 46.2 %
Equivalents ($/Boe)$26.27 $20.81 $5.46 26.2 %
Revenue:
Oil and condensate sales$44,176 $52,093 $(7,917)(15.2)%
Natural gas and natural gas liquids sales1
42,889 36,642 6,247 17.0 %
Lease bonus and other income2,385 4,308 (1,923)(44.6)%
Revenue from contracts with customers89,450 93,043 (3,593)(3.9)%
Gain (loss) on commodity derivative instruments(27,882)90,011 (117,893)
NM2
Total revenue$61,568 $183,054 $(121,486)(66.4)%
Operating expenses:  
Lease operating expense$2,664 $3,827 $(1,163)(30.4)%
Production costs and ad valorem taxes11,842 12,376 (534)(4.3)%
Exploration expense1,073 1,072 100.0 %
Depreciation, depletion, and amortization15,632 23,182 (7,550)(32.6)%
Impairment of oil and natural gas properties— 51,031 (51,031)
NM2
General and administrative12,852 11,856 996 8.4 %
Other expense:
Interest expense1,210 4,427 (3,217)(72.7)%
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.
2 Not meaningful.
Revenue
Total revenue for the quarter ended March 31, 2021 decreased compared to the quarter ended March 31, 2020. The decrease in total revenue from the corresponding period is due to a loss on our commodity derivative instruments in the first quarter of 2021 compared to a gain in the first quarter of 2020, a decrease in oil and condensate sales, and a decrease in lease bonus and other income. The overall decrease in total revenue was partially offset by an increase in natural gas and NGL sales.
Oil and condensate sales. Oil and condensate sales decreased for the quarter ended March 31, 2021 as compared to the corresponding period in 2020 due to lower production volumes partially offset by higher realized commodity prices. The decrease in oil and condensate production was primarily driven by production volume decreases in the Permian Basin. Our
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mineral and royalty interest oil and condensate volumes accounted for 92% of total oil and condensate volumes for both quarters ended March 31, 2021 and 2020.
Natural gas and natural gas liquids sales. Natural gas and NGL sales increased for the quarter ended March 31, 2021 as compared to the corresponding prior period due to higher realized commodity prices partially offset by lower production volumes. The decrease in natural gas and NGL production was driven by decreases in working interest production volumes, primarily within the Haynesville/Bossier play. Mineral and royalty interest production accounted for 82% and 73% of our natural gas volumes for the quarters ended March 31, 2021 and 2020, respectively.
Gain (loss) on commodity derivative instruments. During the first quarter of 2021, we recognized a loss from our commodity derivative instruments compared to a gain in the same period in 2020. 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 new positions and settlements that may occur during each reporting period, as well as the relationships between contract prices and the associated forward curves. For the three months ended March 31, 2021, we recognized $4.5 million of realized losses and $23.4 million of unrealized losses from our oil and natural gas commodity contracts, compared to $9.0 million of realized gains and $81.1 million of unrealized gains in the same period in 2020. The unrealized losses on our commodity contracts during the first quarter of 2021 and the unrealized gains for the same period in 2020 were primarily driven by changes in the forward commodity price curves for oil.
Lease bonus and other income. When we lease our mineral interests, we generally receive an upfront cash payment, or a lease bonus. Lease bonus revenue can vary substantively between periods because it is derived from individual transactions with operators, some of which may be significant. Lease bonus and other income for the first quarter of 2021 was lower than the same period in 2020. Leasing activity in the Austin Chalk play made up the majority of lease bonus revenue in the first quarter of 2021, while a substantial portion of first quarter 2020 activity came from the Permian Basin, Green River Basin, and Bakken/Three Forks.
Operating Expenses
Lease operating expense. Lease operating expense includes recurring expenses associated with our non-operated working interests necessary to produce hydrocarbons from our oil and natural gas wells, as well as certain nonrecurring expenses, such as well repairs. Lease operating expense decreased for the quarter ended March 31, 2021 as compared to the same period in 2020, primarily due to lower nonrecurring service-related expenses, including workovers, as well as a decrease in variable costs as a result of lower production from our non-operating working interest properties.
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 quarter ended March 31, 2021, production costs and ad valorem taxes decreased as compared to the quarter ended March 31, 2020, primarily due to lower ad valorem tax estimates for the 2021 tax year partially offset by higher production costs attributable to our natural gas and NGL revenues due to higher commodity prices.
Exploration expense. Exploration expense typically consists of dry-hole expenses, delay rentals, and geological and geophysical costs, including seismic costs, and is expensed as incurred under the successful efforts method of accounting. Exploration expense for the three months ended March 31, 2021 primarily related to a dry hole drilled during the period. Exploration expense was minimal in the corresponding prior period in 2020.
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 a 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 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 decreased for the quarter ended March 31, 2021 as compared to the same period in 2020, primarily due to lower production volumes and a reduction in cost basis with a lower corresponding reduction in proved developed producing reserve quantities. The reduction in cost basis is primarily due to depreciation, depletion, and amortization recorded during the prior twelve months.
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General and administrative. General and administrative expenses are costs not directly associated with the production of oil and natural gas and include expenses such as the cost of employee salaries and related benefits, office expenses, and fees for professional services. For the quarter ended March 31, 2021, general and administrative expenses increased as compared to the same period in