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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 June 30, 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 July 30, 2021, there were 208,642,990 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)
 June 30, 2021December 31, 2020
ASSETS  
CURRENT ASSETS  
Cash and cash equivalents$1,043 $1,796 
Accounts receivable68,381 61,908 
Commodity derivative assets 1,149 
Prepaid expenses and other current assets2,116 1,668 
TOTAL CURRENT ASSETS71,540 66,521 
PROPERTY AND EQUIPMENT  
Oil and natural gas properties, at cost, using the successful efforts method of accounting, includes unproved properties of $947,509 and $937,464 at June 30, 2021 and December 31, 2020, respectively
3,187,176 3,157,818 
Accumulated depreciation, depletion, amortization, and impairment(2,025,503)(1,987,332)
Oil and natural gas properties, net1,161,673 1,170,486 
Other property and equipment, net of accumulated depreciation of $12,613 and $12,292 at June 30, 2021 and December 31, 2020, respectively
1,393 1,650 
NET PROPERTY AND EQUIPMENT1,163,066 1,172,136 
DEFERRED CHARGES AND OTHER LONG-TERM ASSETS7,641 5,321 
TOTAL ASSETS$1,242,247 $1,243,978 
LIABILITIES, MEZZANINE EQUITY, AND EQUITY 
CURRENT LIABILITIES 
Accounts payable$3,320 $3,407 
Accrued liabilities9,925 15,568 
Commodity derivative liabilities80,047 19,318 
Other current liabilities1,792 1,654 
TOTAL CURRENT LIABILITIES95,084 39,947 
LONG–TERM LIABILITIES 
Credit facility96,000 121,000 
Accrued incentive compensation371 766 
Commodity derivative liabilities5,464 1,848 
Asset retirement obligations17,741 17,377 
Other long-term liabilities3,533 4,073 
TOTAL LIABILITIES218,193 185,011 
COMMITMENTS AND CONTINGENCIES (Note 7)
MEZZANINE EQUITY  
Partners' equity – Series B cumulative convertible preferred units, 14,711 units outstanding at June 30, 2021 and December 31, 2020
298,361 298,361 
EQUITY 
Partners' equity – general partner interest  
Partners' equity – common units, 208,637 and 206,749 units outstanding at June 30, 2021 and December 31, 2020, respectively
725,693 760,606 
TOTAL EQUITY725,693 760,606 
TOTAL LIABILITIES, MEZZANINE EQUITY, AND EQUITY$1,242,247 $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 June 30,Six Months Ended June 30,
 2021202020212020
REVENUE  
Oil and condensate sales$53,936 $25,417 $98,112 $77,510 
Natural gas and natural gas liquids sales56,481 30,311 99,370 66,953 
Lease bonus and other income7,505 1,975 9,890 6,283 
Revenue from contracts with customers117,922 57,703 207,372 150,746 
Gain (loss) on commodity derivative instruments(59,480)(19,174)(87,362)70,837 
TOTAL REVENUE58,442 38,529 120,010 221,583 
OPERATING (INCOME) EXPENSE  
Lease operating expense3,837 3,293 6,501 7,120 
Production costs and ad valorem taxes9,296 9,555 21,138 21,931 
Exploration expense2 23 1,075 24 
Depreciation, depletion, and amortization15,796 19,193 31,428 42,375 
Impairment of oil and natural gas properties   51,031 
General and administrative12,187 11,501 25,039 23,357 
Accretion of asset retirement obligations298 278 590 550 
TOTAL OPERATING EXPENSE41,416 43,843 85,771 146,388 
INCOME (LOSS) FROM OPERATIONS17,026 (5,314)34,239 75,195 
OTHER INCOME (EXPENSE) 
Interest and investment income 3  34 
Interest expense(1,628)(2,964)(2,838)(7,391)
Other income (expense)31 (96)214 (97)
TOTAL OTHER EXPENSE(1,597)(3,057)(2,624)(7,454)
NET INCOME (LOSS)15,429 (8,371)31,615 67,741 
Distributions on Series B cumulative convertible preferred units(5,250)(5,250)(10,500)(10,500)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS$10,179 $(13,621)$21,115 $57,241 
ALLOCATION OF NET INCOME (LOSS):   
General partner interest$ $ $ $ 
Common units10,179 (13,621)21,115 57,241 
 $10,179 $(13,621)$21,115 $57,241 
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:  
Per common unit (basic)$0.05 $(0.07)$0.10 $0.28 
Per common unit (diluted)$0.05 $(0.07)$0.10 $0.28 
WEIGHTED AVERAGE COMMON UNITS OUTSTANDING:
Weighted average common units outstanding (basic)207,945 206,707 207,695 206,669 
Weighted average common units outstanding (diluted)207,945 206,707 207,695 206,669 
 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 
Issuance of common units for property acquisitions1,088 10,766 10,766 
Restricted units granted, net of forfeitures7 — — 
Equity–based compensation— 2,820 2,820 
Distributions— (36,321)(36,321)
Charges to partners' equity for accrued distribution equivalent rights— (180)(180)
Distributions on Series B cumulative convertible preferred units— (5,250)(5,250)
Net income (loss)— 15,429 15,429 
BALANCE AT JUNE 30, 2021208,637 $725,693 $725,693 
The accompanying notes are an integral part of these unaudited consolidated financial statements.
3



BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
(Unaudited)
(In thousands)
 
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 
Repurchases of common units (6)(6)
Restricted units granted, net of forfeitures14 — — 
Equity–based compensation— 2,292 2,292 
Distributions— (16,679)(16,679)
Charges to partners' equity for accrued distribution equivalent rights— (31)(31)
Distributions on Series B cumulative convertible preferred units— (5,250)(5,250)
Net income (loss)— (8,371)(8,371)
BALANCE AT JUNE 30, 2020206,709 $775,681 $775,681 
The accompanying notes are an integral part of these unaudited consolidated financial statements.
4



BLACK STONE MINERALS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In thousands)
Six Months Ended June 30,
 20212020
CASH FLOWS FROM OPERATING ACTIVITIES  
Net income (loss)$31,615 $67,741 
Adjustments to reconcile net income (loss) to net cash provided by operating activities: 
Depreciation, depletion, and amortization31,428 42,375 
Impairment of oil and natural gas properties 51,031 
Accretion of asset retirement obligations590 550 
Amortization of deferred charges884 519 
(Gain) loss on commodity derivative instruments87,362 (70,837)
Net cash (paid) received on settlement of commodity derivative instruments(21,868)45,506 
Equity-based compensation6,533 (420)
Exploratory dry hole expense1,049  
Changes in operating assets and liabilities:
Accounts receivable(6,159)33,544 
Prepaid expenses and other current assets(448)(1,163)
Accounts payable, accrued liabilities, and other(5,247)(10,790)
Settlement of asset retirement obligations(160)(87)
NET CASH PROVIDED BY OPERATING ACTIVITIES125,579 157,969 
CASH FLOWS FROM INVESTING ACTIVITIES  
Acquisitions of oil and natural gas properties(10,064)(28)
Additions to oil and natural gas properties(2,606)(4,146)
Additions to oil and natural gas properties leasehold costs(21)(782)
Purchases of other property and equipment(63)(10)
Proceeds from the sale of oil and natural gas properties 1,266 
Proceeds from farmouts of oil and natural gas properties 4,067 
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES(12,754)367 
CASH FLOWS FROM FINANCING ACTIVITIES  
Distributions to common unitholders(72,593)(78,320)
Distributions to Series B cumulative convertible preferred unitholders(10,500)(10,500)
Repurchases of common units(1,957)(5,035)
Borrowings under credit facility84,000 89,000 
Repayments under credit facility(109,000)(160,000)
Debt issuance costs and other(3,528) 
NET CASH USED IN FINANCING ACTIVITIES(113,578)(164,855)
NET CHANGE IN CASH AND CASH EQUIVALENTS(753)(6,519)
CASH AND CASH EQUIVALENTS – beginning of the period1,796 8,119 
CASH AND CASH EQUIVALENTS – end of the period$1,043 $1,600 
SUPPLEMENTAL DISCLOSURE  
Interest paid$1,944 $6,934 
 The accompanying notes are an integral part of these unaudited consolidated financial statements.
5


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 six months ended June 30, 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.
6


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 six months ended June 30, 2021.
Accounts Receivable

The following table presents information about the Partnership's accounts receivable:
June 30, 2021December 31, 2020
(in thousands)
Accounts receivable:
Revenues from contracts with customers$63,706 $58,181 
Other4,675 3,727 
Total accounts receivable$68,381 $61,908 

NOTE 3 - OIL AND NATURAL GAS PROPERTIES    
Acquisitions
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.
In the second quarter of 2021, the Partnership closed an acquisition of mineral and royalty acreage in the northern Midland Basin for total consideration of $20.8 million. The purchase price consisted of $10.0 million in cash and $10.8 million in common units of the Partnership. The cash consideration was funded with borrowings under the Credit Facility (as defined in Note 6 - Credit Facility) and funds from operating activities. The transaction was accounted for as a business combination with the assets acquired recorded at their estimated fair values as of the acquisition date. The assets acquired consisted of $4.9 million of proved oil and natural gas properties, $15.6 million of unproved oil and natural gas properties, and $0.3 million of net working capital. Acquisition related costs of $0.3 million were expensed and included in the General and administrative line of the consolidated statement of operations for the three and six months ended June 30, 2021.
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.
7


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

Canaan Farmout
In February 2017, the Partnership entered into a farmout agreement (the "First Canaan Farmout") with Canaan Resource Partners ("Canaan") covering certain Haynesville and Bossier shale acreage in San Augustine County, Texas jointly owned with and operated by XTO Energy Inc. ("XTO"), a subsidiary of Exxon Mobil Corporation. The Partnership had an approximate 50% working interest in the acreage. Under the terms of the First Canaan Farmout, Canaan funded 80% of the Partnership's drilling and completion costs and was assigned 80% of the Partnership's working interests in covered wells (40% working interest on an 8/8ths basis) as the wells were drilled. The Partnership received an ORRI before payout and an increased ORRI after payout on all wells drilled under the First Canaan Farmout.
Canaan's rights and obligations to participate in future wells in the contract area were terminated in the second quarter of 2021 in conjunction with Canaan and the Partnership entering into a new farmout agreement as discussed below. Canaan participated in a total of 37 wells under the First Canaan Farmout.
In 2019, XTO Energy Inc. suspended its development activities in the area due to low natural gas prices. In March 2021, BSM and XTO reached an agreement to partition the jointly owned working interests in the San Augustine County development area. Under the partition agreement, BSM and XTO exchanged working interests in certain existing and proposed drilling units, resulting in each company holding 100% of the working interests in their respective partitioned units.
In May 2021, BSM and Aethon Energy ("Aethon") entered into an agreement to develop certain of the Partnership's 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 BSM'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 discussed below.
On May 25, 2021, the Partnership and Canaan entered into a new farmout agreement (the "Second Canaan Farmout"). The Second Canaan Farmout supersedes and replaces the First Canaan Farmout with respect to the area in San Augustine County covered by the Aethon development agreement. The Second Canaan Farmout covers part of the Partnership's share of working interests under active development by Aethon in San Augustine County, Texas and continues until May 2031, unless earlier terminated in accordance to the terms of the agreement. Canaan will earn 80% of the Partnership's working interest in the partitioned acreage from XTO (up to a maximum of 40% on an 8/8ths basis) and 50% of the Partnership's working interest in other areas (up to a maximum of 12.5% on an 8/8ths basis) in wells drilled and operated by Aethon in accordance with the development agreement. Canaan is obligated to fund the development of all wells drilled by Aethon in the initial program year and thereafter, Canaan has certain rights and options to continue funding the Partnership's working interest for the duration of the Second Canaan Farmout. As of June 30, 2021, no wells had been drilled under the Second Canaan Farmout. The Partnership will receive an ORRI before payout and an increased ORRI after payout on all wells drilled under the Second Canaan Farmout.
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 June 30, 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 to develop certain portions of the area forfeited by BPX Energy in Angelina County, Texas. The agreement provides for minimum well
8


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

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 June 30, 2021, a total of five wells have been spud in the contract area subject to the Second Pivotal Farmout.
From the inception of the farmout agreements through June 30, 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 June 30, 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.
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 and six months ended June 30, 2021 and the three months ended June 30, 2020. The Partnership recognized $51.0 million of impairment of oil and natural gas properties for the six months ended June 30, 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 June 30, 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 June 30, 2021 and December 31, 2020. See Note 5 - Fair Value Measurements for further discussion.    
9


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

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 June 30, 2021, the Partnership had seven counterparties, all of which are rated Baa1 or better by Moody’s and six are lenders under the Credit Facility.
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:
June 30, 2021
ClassificationBalance Sheet LocationGross
Fair Value
Effect of Counterparty NettingNet Carrying Value on Balance Sheet
  (in thousands)
Assets:
    
Current asset
Commodity derivative assets$ $ $ 
Long-term asset
Deferred charges and other long-term assets977 (977) 
 Total assets
 $977 $(977)$ 
Liabilities:
    
Current liability
Commodity derivative liabilities$80,047 $ $80,047 
Long-term liability
Commodity derivative liabilities6,441 (977)5,464 
Total liabilities
 $86,488 $(977)$85,511 
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 
10


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

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 June 30,Six Months Ended June 30,
Derivatives not designated as hedging instruments2021202020212020
(in thousands)
Beginning fair value of commodity derivative instruments$(43,376)$96,278 $(20,017)$15,221 
Gain (loss) on oil derivative instruments(34,215)(21,647)(59,069)56,164 
Gain (loss) on natural gas derivative instruments(25,265)2,473 (28,293)14,673 
Net cash paid (received) on settlements of oil derivative instruments15,910 (26,776)20,412 (28,317)
Net cash paid (received) on settlements of natural gas derivative instruments1,435 (9,776)1,456 (17,189)
Net change in fair value of commodity derivative instruments(42,135)(55,726)(65,494)25,331 
Ending fair value of commodity derivative instruments$(85,511)$40,552 $(85,511)$40,552 
The Partnership had the following open derivative contracts for oil as of June 30, 2021:
 Weighted Average Price (Per Bbl)Range (Per Bbl)
Period and Type of ContractVolume (Bbl)LowHigh
Oil Swap Contracts:    
2021    
Second Quarter220,000 $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 Quarter480,000 $60.14 $55.29 $65.50 
Second Quarter480,000 60.14 55.29 65.50 
Third Quarter480,000 60.14 55.29 65.50 
Fourth Quarter480,000 60.14 55.29 65.50 

The Partnership had the following open derivative contracts for natural gas as of June 30, 2021:
 Weighted Average Price (Per MMBtu)Range (Per MMBtu)
Period and Type of ContractVolume (MMBtu)LowHigh
Natural Gas Swap Contracts:    
2021    
Third Quarter10,120,000 $2.69 $2.52 $3.08 
Fourth Quarter10,120,000 2.69 2.52 3.08 
2022
First Quarter7,920,000 $2.98 $2.80 $3.15 
Second Quarter8,000,000 2.99 2.80 3.15 
Third Quarter8,080,000 2.99 2.80 3.15 
Fourth Quarter8,080,000 2.99 2.80 3.15 

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NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

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.
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 June 30, 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.
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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 June 30, 2021     
Financial Assets     
Commodity derivative instruments$ $977 $ $(977)$ 
Financial Liabilities     
Commodity derivative instruments$ $86,488 $ $(977)$85,511 
As of December 31, 2020     
Financial Assets     
Commodity derivative instruments$ $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%.
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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 June 30, 2021
Impaired oil and natural gas properties$ $ $ $ 
Three Months Ended June 30, 2020
Impaired oil and natural gas properties$ $ $ $ 
Six Months Ended June 30, 2021
Impaired oil and natural gas properties$ $ $ $ 
Six Months Ended June 30, 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 June 30, 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 and terminates on November 1, 2024. 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. 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 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. As of June 30, 2021, the alternative base rate margin ranged from 1.50% to 2.50% and the LIBOR margin ranged from 2.50% to 3.50%.
The weighted-average interest rate of the Credit Facility was 2.60% and 2.40% as of June 30, 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. Distributions are not permitted if there is a default under the Credit Facility (including the failure to satisfy one of the financial covenants), if the availability under the Credit Facility is less than 10% of the lenders' commitments, or if total debt to EBITDAX is greater than 3.0. As of June 30, 2021, the Partnership was in compliance with all financial covenants in the Credit Facility.
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NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

The aggregate principal balance outstanding was $96.0 million and $121.0 million at June 30, 2021 and December 31, 2020, respectively. The unused portion of the available borrowings under the Credit Facility were $304.0 million and $279.0 million at June 30, 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 June 30, 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 June 30,Six Months Ended June 30,
2021202020212020
 (in thousands)
Cash—short and long-term incentive plans$1,729 $506 $3,114 $1,469 
Equity-based compensation—restricted common units1,037 1,126 1,986 2,411 
Equity-based compensation—restricted performance units1
1,697 1,098 3,858 (3,559)
Board of Directors incentive plan337 250 689 728 
 Total incentive compensation expense
$4,800 $2,980 $9,647 $1,049 
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 six months ended June 30, 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
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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 June 30, 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 June 30,Six Months Ended June 30,
 2021202020212020
 (in thousands, except per unit amounts)
NET INCOME (LOSS)$15,429 $(8,371)$31,615 $67,741 
Distributions on Series B cumulative convertible preferred units(5,250)(5,250)(10,500)(10,500)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS10,179 (13,621)21,115 57,241 
ALLOCATION OF NET INCOME (LOSS):  
General partner interest$ $ $ $ 
Common units10,179 (13,621)21,115 57,241 
 $10,179 $(13,621)$21,115 $57,241 
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:  
Per common unit (basic)$0.05 $(0.07)$0.10 $0.28 
Per common unit (diluted)0.05 (0.07)