Black Stone Minerals, L.P. 10-Q

Item 1. Financial Statements BLACK STONE MINERALS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Unaudited) (In thousands) September 30, 2021 December 31, 2020 ASSETS CURRENT ASSETS Cash and cash equivalents $ 3,264 $ 1,796 Accounts receivable 88,301 61,908 Commodity derivative assets — 1,149 Prepaid expenses and other current assets 1,503 1,668 TOTAL CURRENT ASSETS 93,068 66,521 PROPERTY AND EQUIPMENT Oil and natural gas properties, at cost, using the successful efforts method of accounting, includes unproved properties of $ 947,538 and $ 937,464 at September 30, 2021 and December 31, 2020, respectively 3,000,406 3,157,818 Accumulated depreciation, depletion, amortization, and impairment ( 1,855,218 ) ( 1,987,332 ) Oil and natural gas properties, net 1,145,188 1,170,486 Other property and equipment, net of accumulated depreciation of $ 12,778 and $ 12,292 at September 30, 2021 and December 31, 2020, respectively 1,238 1,650 NET PROPERTY AND EQUIPMENT 1,146,426 1,172,136 DEFERRED CHARGES AND OTHER LONG-TERM ASSETS 7,170 5,321 TOTAL ASSETS $ 1,246,664 $ 1,243,978 LIABILITIES, MEZZANINE EQUITY, AND EQUITY CURRENT LIABILITIES Accounts payable $ 2,206 $ 3,407 Accrued liabilities 13,246 15,568 Commodity derivative liabilities 114,451 19,318 Other current liabilities 1,635 1,654 TOTAL CURRENT LIABILITIES 131,538 39,947 LONG–TERM LIABILITIES Credit facility 99,000 121,000 Accrued incentive compensation 565 766 Commodity derivative liabilities 14,481 1,848 Asset retirement obligations 12,412 17,377 Other long-term liabilities 3,223 4,073 TOTAL LIABILITIES 261,219 185,011 COMMITMENTS AND CONTINGENCIES (Note 7) MEZZANINE EQUITY Partners' equity – Series B cumulative convertible preferred units, 14,711 units outstanding at September 30, 2021 and December 31, 2020 298,361 298,361 EQUITY Partners' equity – general partner interest — — Partners' equity – common units, 208,660 and 206,749 units outstanding at September 30, 2021 and December 31, 2020, respectively 687,084 760,606 TOTAL EQUITY 687,084 760,606 TOTAL LIABILITIES, MEZZANINE EQUITY, AND EQUITY $ 1,246,664 $ 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 September 30, Nine Months Ended September 30, 2021 2020 2021 2020 REVENUE Oil and condensate sales $ 61,916 $ 34,335 $ 160,028 $ 111,845 Natural gas and natural gas liquids sales 73,167 29,107 172,537 96,060 Lease bonus and other income 2,305 1,386 12,195 7,669 Revenue from contracts with customers 137,388 64,828 344,760 215,574 Gain (loss) on commodity derivative instruments ( 77,561 ) ( 21,086 ) ( 164,923 ) 49,751 TOTAL REVENUE 59,827 43,742 179,837 265,325 OPERATING (INCOME) EXPENSE Lease operating expense 3,303 3,160 9,804 10,280 Production costs and ad valorem taxes 14,331 9,905 35,469 31,836 Exploration expense 5 4 1,080 28 Depreciation, depletion, and amortization 14,925 19,823 46,353 62,198 Impairment of oil and natural gas properties — — — 51,031 General and administrative 12,320 9,381 37,359 32,738 Accretion of asset retirement obligations 273 286 863 836 (Gain) loss on sale of assets, net ( 2,850 ) ( 24,045 ) ( 2,850 ) ( 24,045 ) TOTAL OPERATING EXPENSE 42,307 18,514 128,078 164,902 INCOME (LOSS) FROM OPERATIONS 17,520 25,228 51,759 100,423 OTHER INCOME (EXPENSE) Interest and investment income — 1 — 35 Interest expense ( 1,359 ) ( 1,664 ) ( 4,197 ) ( 9,055 ) Other income (expense) 17 168 231 71 TOTAL OTHER EXPENSE ( 1,342 ) ( 1,495 ) ( 3,966 ) ( 8,949 ) NET INCOME (LOSS) 16,178 23,733 47,793 91,474 Distributions on Series B cumulative convertible preferred units ( 5,250 ) ( 5,250 ) ( 15,750 ) ( 15,750 ) NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS $ 10,928 $ 18,483 $ 32,043 $ 75,724 ALLOCATION OF NET INCOME (LOSS): General partner interest $ — $ — $ — $ — Common units 10,928 18,483 32,043 75,724 $ 10,928 $ 18,483 $ 32,043 $ 75,724 NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT: Per common unit (basic) $ 0.05 $ 0.09 $ 0.15 $ 0.37 Per common unit (diluted) $ 0.05 $ 0.09 $ 0.15 $ 0.37 WEIGHTED AVERAGE COMMON UNITS OUTSTANDING: Weighted average common units outstanding (basic) 208,653 206,732 208,018 206,690 Weighted average common units outstanding (diluted) 208,653 206,732 208,018 206,690 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 units Partners' equity — common units Total equity BALANCE AT DECEMBER 31, 2020 206,749 $ 760,606 $ 760,606 Repurchases of common units ( 223 ) ( 1,957 ) ( 1,957 ) Restricted units granted, net of forfeitures 1,016 — — 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, 2021 207,542 $ 738,429 $ 738,429 Issuance of common units for property acquisitions 1,088 10,766 10,766 Restricted units granted, net of forfeitures 7 — — 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, 2021 208,637 $ 725,693 $ 725,693 Restricted units granted, net of forfeitures 23 — — Equity–based compensation — 2,903 2,903 Distributions — ( 52,165 ) ( 52,165 ) Charges to partners' equity for accrued distribution equivalent rights — ( 275 ) ( 275 ) Distributions on Series B cumulative convertible preferred units — ( 5,250 ) ( 5,250 ) Net income (loss) — 16,178 16,178 BALANCE AT SEPTEMBER 30, 2021 208,660 $ 687,084 $ 687,084 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 units Partners' equity — common units Total equity BALANCE AT DECEMBER 31, 2019 205,960 $ 798,443 $ 798,443 Repurchases of common units ( 503 ) ( 5,029 ) ( 5,029 ) Restricted units granted, net of forfeitures 1,238 — — 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, 2020 206,695 $ 803,726 $ 803,726 Repurchases of common units — ( 6 ) ( 6 ) Restricted units granted, net of forfeitures 14 — — 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, 2020 206,709 $ 775,681 $ 775,681 Restricted units granted, net of forfeitures 29 — — Equity–based compensation — 1,613 1,613 Distributions — ( 31,011 ) ( 31,011 ) Charges to partners' equity for accrued distribution equivalent rights — ( 133 ) ( 133 ) Distributions on Series B cumulative convertible preferred units — ( 5,250 ) ( 5,250 ) Net income (loss) — 23,733 23,733 BALANCE AT SEPTEMBER 30, 2020 206,738 $ 764,633 $ 764,633 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) Nine Months Ended September 30, 2021 2020 CASH FLOWS FROM OPERATING ACTIVITIES Net income (loss) $ 47,793 $ 91,474 Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation, depletion, and amortization 46,353 62,198 Impairment of oil and natural gas properties — 51,031 Accretion of asset retirement obligations 863 836 Amortization of deferred charges 1,232 781 (Gain) loss on commodity derivative instruments 164,923 ( 49,751 ) Net cash (paid) received on settlement of commodity derivative instruments ( 56,008 ) 66,794 Equity-based compensation 9,705 1,405 Exploratory dry hole expense 1,049 — (Gain) loss on sale of assets, net ( 2,850 ) ( 24,045 ) Changes in operating assets and liabilities: Accounts receivable ( 26,066 ) 29,844 Prepaid expenses and other current assets 165 ( 630 ) Accounts payable, accrued liabilities, and other ( 3,546 ) ( 8,353 ) Settlement of asset retirement obligations ( 187 ) ( 170 ) NET CASH PROVIDED BY OPERATING ACTIVITIES 183,426 221,414 CASH FLOWS FROM INVESTING ACTIVITIES Acquisitions of oil and natural gas properties ( 10,064 ) ( 28 ) Additions to oil and natural gas properties ( 3,972 ) ( 4,223 ) Additions to oil and natural gas properties leasehold costs ( 98 ) ( 782 ) Purchases of other property and equipment ( 74 ) ( 15 ) Proceeds from the sale of oil and natural gas properties 317 151,513 Proceeds from farmouts of oil and natural gas properties — 4,175 NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES ( 13,891 ) 150,640 CASH FLOWS FROM FINANCING ACTIVITIES Distributions to common unitholders ( 124,758 ) ( 109,331 ) Distributions to Series B cumulative convertible preferred unitholders ( 15,750 ) ( 15,750 ) Repurchases of common units ( 1,957 ) ( 5,035 ) Borrowings under credit facility 144,000 124,000 Repayments under credit facility ( 166,000 ) ( 371,000 ) Debt issuance costs and other ( 3,602 ) — NET CASH USED IN FINANCING ACTIVITIES ( 168,067 ) ( 377,116 ) NET CHANGE IN CASH AND CASH EQUIVALENTS 1,468 ( 5,062 ) CASH AND CASH EQUIVALENTS – beginning of the period 1,796 8,119 CASH AND CASH EQUIVALENTS – end of the period $ 3,264 $ 3,057 SUPPLEMENTAL DISCLOSURE Interest paid $ 2,941 $ 8,371 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 nine months ended September 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 nine months ended September 30, 2021. Accounts Receivable The following table presents information about the Partnership's accounts receivable: September 30, 2021 December 31, 2020 (in thousands) Accounts receivable: Revenues from contracts with customers $ 83,861 $ 58,181 Other 4,440 3,727 Total accounts receivable $ 88,301 $ 61,908 7 BLACK STONE MINERALS, L.P. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS 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 nine months ended September 30, 2021. Divestitures In the third quarter of 2021, the Partnership closed on the divestiture of its wholly owned subsidiary, TLW Investments, L.L.C. ("TLW"), effective September 1, 2021 for total proceeds of $ 0.2 million. TLW holds non-operating working interests and overriding royalty interests primarily located in Oklahoma and Texas. TLW's assets and liabilities consisted of oil and natural gas properties with a net book value of $ 3.0 million and asset retirement obligations with a book value of $ 5.7 million at the time of sale. The Partnership recognized a $ 2.9 million gain associated with the divestiture included in the (Gain) loss on sale of assets, net line item of the consolidated statement of operations for the three and nine months ended September 30, 2021. 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 included in the (Gain) loss on sale of assets, net line item of the consolidated statement of operations for the three and nine months ended September 30, 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 (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. 8 BLACK STONE MINERALS, L.P. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS In 2019, XTO 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 began 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 September 30, 2021, no wells have been spud in the contract area subject to 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 covered substantially all of the Partnership's remaining working interests in wells operated by XTO 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. Under the terms of the First Pivotal Farmout, Pivotal was obligated to fund the development of up to 80 wells, in designated well groups, across several development areas and then had options to continue funding the Partnership's working interest across those areas for the duration of the farmout agreement. Once Pivotal achieved a specified payout for a designated well group, the Partnership would obtain a majority of the original working interest in such well group. Pivotal’s rights and obligations to participate in future wells in the contract area were terminated in the fourth quarter of 2020 in conjunction with Pivotal and the Partnership entering into a new farmout agreement as discussed below. Pivotal participated in a total of 68 wells under 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 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 9 BLACK STONE MINERALS, L.P. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS a designated well group, the Partnership will obtain a majority of the original working interest in such well group. As of September 30, 2021, a total of six wells have been spud in the contract area subject to the Second Pivotal Farmout. From the inception of the farmout agreements through September 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 September 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 nine months ended September 30, 2021 and the three months ended September 30, 2020. The Partnership recognized $ 51.0 million of impairment of oil and natural gas properties for the nine months ended September 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 September 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 September 30, 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 September 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. 10 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: September 30, 2021 Classification Balance Sheet Location Gross Fair Value Effect of Counterparty Netting Net Carrying Value on Balance Sheet (in thousands) Assets: Current asset Commodity derivative assets $ — $ — $ — Long-term asset Deferred charges and other long-term assets — — — Total assets $ — $ — $ — Liabilities: Current liability Commodity derivative liabilities $ 114,451 $ — $ 114,451 Long-term liability Commodity derivative liabilities 14,481 — 14,481 Total liabilities $ 128,932 $ — $ 128,932 December 31, 2020 Classification Balance Sheet Location Gross Fair Value Effect of Counterparty Netting Net Carrying Value on Balance Sheet (in thousands) Assets: Current asset Commodity derivative assets $ 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 liabilities 1,848 — 1,848 Total liabilities $ 26,379 $ ( 5,213 ) $ 21,166 11 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 September 30, Nine Months Ended September 30, Derivatives not designated as hedging instruments 2021 2020 2021 2020 (in thousands) Beginning fair value of commodity derivative instruments $ ( 85,511 ) $ 40,552 $ ( 20,017 ) $ 15,221 Gain (loss) on oil derivative instruments ( 10,227 ) ( 5,864 ) ( 69,296 ) 50,300 Gain (loss) on natural gas derivative instruments ( 67,334 ) ( 15,222 ) ( 95,627 ) ( 549 ) Net cash paid (received) on settlements of oil derivative instruments 20,811 ( 13,954 ) 41,223 ( 42,270 ) Net cash paid (received) on settlements of natural gas derivative instruments 13,329 ( 7,334 ) 14,785 ( 24,524 ) Net change in fair value of commodity derivative instruments ( 43,421 ) ( 42,374 ) ( 108,915 ) ( 17,043 ) Ending fair value of commodity derivative instruments $ ( 128,932 ) $ ( 1,822 ) $ ( 128,932 ) $ ( 1,822 ) The Partnership had the following open derivative contracts for oil as of September 30, 2021: Weighted Average Price (Per Bbl) Range (Per Bbl) Period and Type of Contract Volume (Bbl) Low High Oil Swap Contracts: 2021 Third Quarter 220,000 $ 38.97 $ 32.64 $ 46.50 Fourth Quarter 660,000 38.97 32.64 46.50 2022 First Quarter 480,000 $ 60.14 $ 55.29 $ 65.50 Second Quarter 480,000 60.14 55.29 65.50 Third Quarter 480,000 60.14 55.29 65.50 Fourth Quarter 480,000 60.14 55.29 65.50 12 BLACK STONE MINERALS, L.P. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS The Partnership had the following open derivative contracts for natural gas as of September 30, 2021: Weighted Average Price (Per MMBtu) Range (Per MMBtu) Period and Type of Contract Volume (MMBtu) Low High Natural Gas Swap Contracts: 2021 Fourth Quarter 10,120,000 $ 2.69 $ 2.52 $ 3.08 2022 First Quarter 7,920,000 $ 2.98 $ 2.80 $ 3.15 Second Quarter 8,000,000 2.99 2.80 3.15 Third Quarter 8,080,000 2.99 2.80 3.15 Fourth Quarter 8,080,000 2.99 2.80 3.15 2023 First Quarter 1,800,000 $ 3.28 $ 3.28 $ 3.29 Second Quarter 1,820,000 3.28 3.28 3.29 Third Quarter 1,840,000 3.28 3.28 3.29 Fourth Quarter 1,840,000 3.28 3.28 3.29 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 September 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. 13 BLACK STONE MINERALS, L.P. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS 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 Using Effect of Counterparty Netting Total Level 1 Level 2 Level 3 (in thousands) As of September 30, 2021 Financial Assets Commodity derivative instruments $ — $ — $ — $ — $ — Financial Liabilities Commodity derivative instruments $ — $ 128,932 $ — $ — $ 128,932 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 %. 14 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 Using Impairment Level 1 Level 2 Level 3 (in thousands) Three Months Ended September 30, 2021 Impaired oil and natural gas properties $ — $ — $ — $ — Three Months Ended September 30, 2020 Impaired oil and natural gas properties $ — $ — $ — $ — Nine Months Ended September 30, 2021 Impaired oil and natural gas properties $ — $ — $ — $ — Nine Months Ended September 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 September 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. The April and October 2021 borrowing base redeterminations reaffirmed the borrowing base at $ 400.0 million. The next semi-annual redetermination is scheduled for April 2022. 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 September 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 2.59 % and 2.40 % as of September 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 September 30, 2021, the Partnership was in compliance with all financial covenants in the Credit Facility. 15 BLACK STONE MINERALS, L.P. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS The aggregate principal balance outstanding was $ 99.0 million and $ 121.0 million at September 30, 2021 and December 31, 2020, respectively. The unused portion of the available borrowings under the Credit Facility were $ 301.0 million and $ 279.0 million at September 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 September 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 September 30, Nine Months Ended September 30, 2021 2020 2021 2020 (in thousands) Cash—short and long-term incentive plans $ 2,118 $ 634 $ 5,232 $ 2,103 Equity-based compensation—restricted common units 1,073 1,138 3,059 3,549 Equity-based compensation—restricted performance units 1 1,762 295 5,620 ( 3,264 ) Board of Directors incentive plan 337 392 1,026 1,120 Total incentive compensation expense $ 5,290 $ 2,459 $ 14,937 $ 3,508 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 nine months ended September 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 16 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 September 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 September 30, Nine Months Ended September 30, 2021 2020 2021 2020 (in thousands, except per unit amounts) NET INCOME (LOSS) $ 16,178 $ 23,733 $ 47,793 $ 91,474 Distributions on Series B cumulative convertible preferred units ( 5,250 ) ( 5,250 ) ( 15,750 ) ( 15,750 ) NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS $ 10,928 $ 18,483 $ 32,043 $ 75,724 ALLOCATION OF NET INCOME (LOSS): General partner interest $ — $ — $ — $ — Common units 10,928 18,483 32,043 75,724 $ 10,928 $ 18,483 $ 32,043 $ 75,724 NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT: Per common unit (basic) $ 0.05 $ 0.09 $ 0.15 $ 0.37 Per common unit (diluted) $ 0.05 $ 0.09 $ 0.15 $ 0.37 WEIGHTED AVERAGE COMMON UNITS OUTSTANDING: Weighted average common units outstanding (basic) 208,653 206,732 208,018 206,690 Effect of dilutive securities — — — — Weighted average common units outstanding (diluted) 208,653 206,732 208,018 206,690 17 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 September 30, Nine Months Ended September 30, 2021 2020 2021 2020 (in thousands) Potentially dilutive securities (common units): Series B cumulative convertible preferred units on an as-converted basis 14,969 14,969 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 September 30, Nine Months Ended September 30, 2021 2020 2021 2020 Distributions declared and paid per common unit $ 0.2500 $ 0.1500 $ 0.6000 $ 0.5300 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 nine months ended September 30, 2021. As of September 30, 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 October 27, 2021, the Board approved a distribution for the three months ended September 30, 2021 of $ 0.25 per common unit. Distributions will be payable on November 19, 2021 to unitholders of record at the close of business on November 12, 2021. 18