Exhibit 99.4



BPP ENERGY PARTNERS LLC
AND SUBSIDIARIES


CONDENSED CONSOLIDATED
FINANCIAL STATEMENTS


As of and for the nine-month periods ended

September 30, 2021 and 2020



CONTENTS


Page
UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Condensed Consolidated Balance Sheets
Condensed Consolidated Statements of Operations
Condensed Consolidated Statements of Changes in Members’ Equity
Condensed Consolidated Statements of Cash Flows
Notes to the Unaudited Condensed Consolidated Financial Statements




BPP ENERGY PARTNERS LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
UNAUDITED
(in thousands)

September 30, 2021December 31, 2020
Assets
Current Assets
Cash and cash equivalents$18,219 $3,116 
Revenue receivable14,962 6,752 
Derivative assets562 6,060 
Prepaid and other current assets100 19,520 
Total current assets33,843 35,448 
Property, plant and equipment, net:
Oil and gas properties, full cost method of accounting108,505 87,383 
Derivative assets1,549 2,809 
Loan origination cost, net200 232 
Investment in SFS21,000 20,339 
Total Assets$165,097 $146,211 
Liabilities and Members’ Equity
Current Liabilities
Accounts payable$1,464 $— 
Accounts payable - affiliate6,810 972 
Accrued liabilities7,280 12,329 
Derivative liabilities12,799 76 
Other current liabilities61 — 
Total current liabilities28,414 13,377 
Line of credit7,500 — 
Term loan, net73,800 73,537 
Derivative liabilities8,578 1,868 
Asset retirement obligations763 763 
Total Liabilities119,055 89,545 
Commitments and contingencies (Note 10)
Members’ Equity46,042 56,666 
Total Liabilities and Members’ Equity$165,097 $146,211 


The accompanying notes are an integral part of these condensed consolidated financial statements.
3



BPP ENERGY PARTNERS LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
UNAUDITED
(in thousands)

Nine-Months Ended September 30
20212020
Revenues
Oil sales$49,870 $33,825 
Natural gas sales7,565 300 
(Loss) gain on derivative instruments, net(34,751)39,608 
Total revenues22,684 73,733 
Costs and expenses
Lease operating expenses12,246 8,991 
Repairs2,299 726 
Production taxes2,760 1,659 
Depreciation, depletion and amortization12,040 21,915 
Impairment of oil and gas properties— 114,011 
General and administrative2,116 2,571 
Total operating expenses31,461 149,873 
(Loss) from operations(8,777)(76,140)
Other income (expense)
Other income39 — 
Interest expense(6,582)(6,048)
Equity in earnings (loss) of SFS4,485 (959)
Net (loss)($10,835)($83,147)


The accompanying notes are an integral part of these condensed consolidated financial statements.
4



BPP ENERGY PARTNERS LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF
CHANGES IN MEMBERS’ EQUITY
UNAUDITED
(in thousands)

Total
Equity
Balance, December 31, 2020$56,666 
Transfer of property by SFS211 
Net (loss)(10,835)
Balance, September 30, 2021$46,042 
Balance, December 31, 2019$198,780 
Purchase of interest from related party by SFS(211)
Net (loss)(83,147)
Balance, September 30, 2020$115,422 


The accompanying notes are an integral part of these condensed consolidated financial statements.
5



BPP ENERGY PARTNERS LLC AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
UNAUDITED
(in thousands)

Nine-Months Ended September 30
Cash flows from operating activities20212020
Net (loss)($10,835)($83,147)
Adjustments to reconcile net (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization12,040 21,915 
Impairment of oil and gas properties— 114,011 
Deferred loan cost amortization333 327 
Unrealized loss (gain) on derivative instruments26,190 (21,815)
Equity in (earnings) loss of SFS(4,485)959 
Distributed equity in earnings of SFS3,258 — 
Deferred revenue amortization(39)— 
Changes in operating assets and liabilities:
Accounts receivable(8,210)5,473 
Accounts payable1,464 (47)
Accounts payable - affiliate(2,353)(10,149)
Prepaid and other current assets19,420 (1,639)
Other liabilities(6,094)(3,892)
Net cash provided by operating activities30,689 21,996 
Cash flows from investing activities
Additions to oil and gas properties(24,600)(23,346)
Proceeds from sale of oil and gas properties775 — 
Return of capital from SFS, an equity method investment777 — 
Net cash (used in) investing activities(23,048)(23,346)
Cash flows from financing activities
Proceeds from line of credit7,500 — 
Capitalized loan cost(38)(57)
Net cash provided by (used in) financing activities7,462 (57)
Net change in cash and cash equivalents15,103 (1,407)
Cash and cash equivalents, beginning of period3,116 14,758 
Cash and cash equivalents, end of period$18,219 $13,351 
Supplemental cash disclosures:
Property additions included in accrued liabilities$9,337 $446 
Cash paid for interest$5,442 $5,748 


The accompanying notes are an integral part of these condensed consolidated financial statements.
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BPP ENERGY PARTNERS LLC AND SUBSIDARIES
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED
FINANCIAL STATEMENTS
NOTE 1. ORGANIZATION
BPP Energy Partners LLC (“BPP” or the “Company”), a Delaware limited liability company, was formed on October 16, 2018 to indirectly hold the operations of BPP Acquisition LLC (“BPP Acquisition”).
On November 27, 2018, BPP Energy Finance LLC (“BPP EF”) was formed as a wholly owned subsidiary of BPP for the purpose of obtaining term loan financing for use in the operations of BPP. BPP EF is the borrower of the term loan and owns all of the interest in BPP Acquisition.
BPP Acquisition was formed on May 4, 2017, and is engaged in the acquisition, development, production, and exploration of crude oil and natural gas properties located in Texas. As the formation of BPP and BPP EF were created as a reorganization of entities under common control, all prior period balances included in these financials are those of BPP Acquisition.
Principles of Consolidation
These financial statements include the accounts of BPP Energy Partners, LLC and its subsidiaries: (i) BPP Energy Finance LLC (“BPP EF”), and (ii) BPP Acquisition LLC (collectively referred to as the Company). Intercompany transactions and balances have been eliminated upon consolidation.
On July 11, 2018, the Company purchased approximately 22% of its interest in Saragosa Field Services, LLC (“SFS”) from Primexx Energy Partners, Ltd. (“PEP”) an affiliated entity. During 2019, the Company purchased an additional 8% of its interest in SFS from PEP. Total purchased through the balance sheet date is 30%. Given that the Company does not have control over SFS, but has significant influence, it is treated as an equity method investment (see Note 4).
NOTE 2. SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
The accompanying condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America. In preparing the accompanying condensed consolidated financial statements, management has made certain estimates and assumptions that affect reported amounts in the condensed consolidated financial statements and disclosures of contingencies. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results.
In the opinion of management, the accompanying unaudited condensed consolidated balance sheets and related unaudited consolidated statements of operations, cash flows and members equity include all adjustments, consisting only of normal recurring items necessary for the fair presentation in conformity with U.S. GAAP. Certain disclosures have been condensed or omitted from these condensed consolidated financial statements. Accordingly, these condensed notes to the condensed consolidated financial statements should be read in conjunction with the audited financial statements.
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NOTE 2. SIGNIFICANT ACCOUNTING POLICIES - CONTINUED
Use of Estimates
The preparation of the financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates, and changes in these estimates are recorded when known.
Significant items subject to such estimates include proved reserves and related present value of future net revenues, the carrying value of oil and gas properties, asset retirement obligations, and legal and environmental risks and exposures.
Oil and Gas Properties
The Company applies the full cost method of accounting for oil and gas properties. Accordingly, all costs incurred in the acquisition, exploration and development of oil and gas properties are capitalized. Those costs include any internal costs that are directly related to development and exploration activities and capitalized interest associated with certain unproved oil and gas properties with ongoing development activities.
The Company assesses its oil and gas properties whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Costs associated with proved oil and gas properties are subject to the full cost ceiling limitation which generally limits unamortized capitalized costs to the discounted future net revenues from proved reserves, based on the average of the first day prices and operating cost of the previous twelve months. As a result of the Company’s proved property impairment assessment as of September 30, 2020, the Company recorded a $114.0 million non-cash impairment charge to reduce the carrying value of its proved oil and gas properties, which is included in impairments of oil and gas properties in the statements of operations. There were no impairments of proved oil and gas properties for the nine-month period ended September 30, 2021.
Costs associated with unproved properties that have not been impaired and costs associated with uncompleted capital projects are excluded from the depletion base. As proved reserves are established, costs associated with unproved properties become part of our depletion base. Costs associated with uncompleted capital projects are included in our depletion base upon completion of the related projects.
Unproved properties are assessed annually to ascertain whether impairment has occurred. During any period in which impairment is indicated, the accumulated costs associated with the impaired property are transferred to proved properties, become part of our depletion base, and become subject to the full cost ceiling limitation.
Depreciation, depletion and amortization of proved oil and gas properties are computed on the units–of–production method, using estimates of the underlying proved reserves and costs expected to be incurred to develop our proved undeveloped reserves.
Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in income.
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NOTE 2. SIGNIFICANT ACCOUNTING POLICIES - CONTINUED
Derivative Activity
The Company uses derivative financial instruments to reduce exposure to fluctuations in commodity prices. These transactions are in the form of crude oil and natural gas options and swaps.
The Company reports the fair value of derivatives on the consolidated balance sheet in commodity derivative assets or liabilities as either current or noncurrent determined based on the timing of expected future cash flows of the individual trades. The Company reports these on a gross basis by counter party.
The Company’s derivative instruments were not designated as hedges for accounting purposes. Accordingly, the changes in fair value are recognized along with realized gains and losses in (Loss) gain on derivative instruments, net, in the condensed consolidated statements of operations in the period of change.
Fair Value of Financial Instruments
Certain of our assets and liabilities are measured at fair value as of the reporting period. Fair value represents the price that would be received to sell the asset or paid to transfer the liability in an orderly transaction between market participants. Fair value measurements are classified according to the following hierarchy that consists of three broad levels:
Level 1 inputs: Unadjusted quoted prices in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date.
Level 2 inputs: Inputs other than quoted prices included in Level 1 that are observable for the asset or liability, either directly or indirectly. These include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability or inputs that are derived principally from or corroborated by observable market data by correlation or other means.
Level 3 inputs: Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities.
Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. Reclassifications of fair value between level 1, level 2, and level 3 of the fair value hierarchy, if applicable, are made at the end of each reporting period.
Equity Method Investment
The Company accounts for its interest in SFS under the equity method of accounting because BPP Acquisition does not have a controlling interest in SFS but has significant influence. BPP Acquisition recognizes it share of earnings and losses in SFS in accordance with its ownership percentage.
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NOTE 2. SIGNIFICANT ACCOUNTING POLICIES - CONTINUED
Revenue Recognition
The Company’s production is sold through its operated partner who enters into contracts with customers to sell its oil and natural gas production on the Company’s behalf with all related expenses being passed through to the Company. Revenue on these contracts is recognized in accordance with the five-step revenue recognition model. Specifically, revenue is recognized when the Company’s performance obligations under these contracts are satisfied, which generally occurs with the transfer of control of the oil and natural gas to the purchaser. Control is generally considered transferred when the following criteria are met: (i) transfer of physical custody, (ii) transfer of title, (iii) transfer of risk of loss and (iv) relinquishment of any repurchase rights or other similar rights.
Given the nature of the products sold, revenue is recognized at a point in time based on the amount of consideration the Company expects to receive in accordance with the price specified in the contract. Consideration under the oil and natural gas marketing contracts is typically received from the purchaser one to two months after production by the operator and remitted to the Company as a non-operating interest owner. At September 30, 2021 and December 31, 2020, the Company had receivables related to contracts with customers of $15.0 million and $6.0 million, respectively.
For non-operated crude oil and natural gas revenues, the Company’s proportionate share of production is generally marketed at the discretion of the operator. For non-operated properties, the Company receives a net payment from the operator representing its proportionate share of sales proceeds which is net of costs incurred by the operator, if any. Such non-operated revenues are recognized at the net amount of proceeds to be received by the Company during the month in which production occurs and it is probable the Company will collect the consideration it is entitled to receive. Proceeds are generally received by the Company within two months after the month in which production occurs.
Oil Contracts - The majority of the Company’s oil marketing contracts transfer physical custody and title at or near the wellhead, which is generally when control of the oil has been transferred to the purchaser. Most of the oil produced is sold under contracts using market-based pricing which is then adjusted for differentials based upon delivery location and oil quality. To the extent the differentials are incurred after the transfer of control of the oil, the differentials are included in oil sales on the statements of operations as they represent part of the transaction price of the contract. If the differentials, or other related costs, are incurred prior to the transfer of control of the oil, those costs are included in transportation and marketing on the Company’s consolidated statements of operations as they represent payment for services performed outside of the contract with the customer.
Natural Gas Contracts - Most of the Company’s natural gas is sold at the lease location or at the outlet of the compressor station owned by SFS, which is generally when control of the natural gas has been transferred to the purchaser. To the extent control of the natural gas transfers upstream of transportation and processing activities, revenue is recognized as the net amount received from the purchaser. To the extent that control transfers downstream of those activities, revenue is recognized on a gross basis, and the related costs are classified in transportation and marketing on the Company’s consolidated statements of operations.
The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical expedient allowed for in GAAP. The expedient applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.
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NOTE 3. PROPERTY
Property consisted of the following as of (in thousands):
September 30, 2021December 31, 2020
Oil and gas properties:
Proved oil and gas properties$338,253 $305,091 
Accumulated depreciation, depletion and amortization and impairment(229,748)(217,708)
Total net oil and gas properties$108,505 $87,383 
Grey Rock Joint Development Agreement
On January 8, 2021, the Company and Primexx Resource Development, LLC (“PRD”), a wholly owned subsidiary of PEP, an affiliated entity (see Note 9), entered into an agreement with a third party to contribute oil and gas leases and certain properties to a joint development area comprising 960 gross acres effective February 26, 2021. At closing, the Company received total consideration of $0.9 million, which was recorded in oil and gas properties as a reduction in the basis of the full cost pool.
As part of the agreement, management agreed to provide technical consulting services to the third party over the 18-month development period. Accordingly, proceeds related to the technical consulting services of approximately $0.1 million are deferred and recorded in accrued liabilities and amortized over the agreement period as other income.
Callon Divestiture
On August 3, 2021, the Company and PEP (together “the Primexx Entities”) entered into an agreement with Callon Petroleum Company (“Callon”) to sell all of the Primexx Entities’ oil and gas leasehold interests and infrastructure assets. See Note 11 for additional information.
NOTE 4. INVESTMENT IN SARAGOSA FIELD SERVICES
On July 11, 2018, the Company completed the purchase of 22% of SFS from PRD with an effective date of January 1, 2018. The purchase was completed for an initial purchase price of $17.8 million. An additional $6.6 million was contributed through year-end to fund additional infrastructure expansion for a total investment of $24.4 million. The Company has the option to purchase additional interest in SFS not to exceed its pro rata portion acreage held when considering the combined acreage of both PRD and BPP up to 30%.
On April 2, 2019, SFS closed on the sale of certain oil gathering assets to Oryx for a net gain of $31.5 million on May 22, 2019. Primexx Operating Corporation (“POC”), a wholly owned subsidiary of PEP and the operator of the oil and gas assets, will remain the primary customer of the gathering system and, due to this continued involvement, the gain on this transaction is deferred as a liability and amortized over the life of the gathering agreement as other income.
On May 1 and July 2, 2019, the Company completed an additional purchase of 6.23% and 1.75%, respectively, of SFS from PRD to bring its total ownership to 30%. The additional purchased amount was completed for a combined purchase price of $8.7 million.


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NOTE 4. INVESTMENT IN SARAGOSA FIELD SERVICES - CONTINUED
On December 16, 2019, SFS closed on the sale of its saltwater disposal handling assets to WaterBridge Texas Midstream, LLC (“WaterBridge”) for a total price of $185 million in cash at the time of closing with additional incentives of up to $40 million over the subsequent four-year period based on annual water volumes produced by POC operated wells under a Water Management Services Agreement (“WMSA”). The agreement also gives WaterBridge the first right of refusal to purchase SFS’s water recycling facilities at a future time. Simultaneous with closing this sale, POC entered into a WMSA with a term of twenty years for POC’s operating area. Upon the closing of this transaction, a distribution of $173.7 million was made to BPP and PRD based on their respective ownership.
On September 9, 2020, SFS exercised its option to complete the purchase of an office building and land in Pecos, Texas (the “Pecos Property”) from the Chairman of the Board of Directors (a common unit holder and previously the Company’s Chief Executive Officer) for a total payment of $2.1 million. Prior to the purchase, POC had a lease in place with the owner and utilized the office for field operations. Given the related party nature of the transaction, there is no adjustment to the basis of the Pecos Property and the excess cash paid over the book value is recorded as a reduction in the equity of SFS.
SFS made distributions totaling $4.0 million to BPP during the nine-month period ended September 30, 2021. There were no distributions made to BPP by SFS during the nine-month period ended September 30, 2020.
SFS is accounted for on the equity method basis of accounting. The following details the condensed financial statements (in thousands):
Condensed Balance Sheet
September 30, 2021December 31, 2020
Current assets$16,029 $7,290 
Property, plant and equipment, net81,517 89,996 
Total assets$97,545 $97,286 
Current liabilities5,006 4,990 
Total liabilities27,545 29,490 
Members’ equity70,000 67,796 
Total Liabilities and Members’ Equity$97,545 $97,286 
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NOTE 4. INVESTMENT IN SARAGOSA FIELD SERVICES - CONTINUED
Condensed Income StatementNine-Months Ended September 30
20212020
Sales$36,380 $18,425 
Cost of sales4,059 2,149 
Field service expense6,487 8,863 
Production Taxes293 146 
Depreciation, depletion and amortization12,380 12,133 
General and administrative276 496 
Total operating expenses23,494 23,787 
Other income2,063 2,164 
Net income (loss)14,950 (3,198)
Net income (loss) attributable to BPP4,485 (959)
Net income (loss) attributable to controlling owner$10,465 ($2,239)
NOTE 5. DERIVATIVE INSTRUMENTS
The Company engages in price risk management activities. These activities are intended to manage the Company’s exposure to fluctuations in commodity prices for crude oil and natural gas. The Company utilizes financial commodity derivative instruments, primarily price swaps and options.
Commodity derivatives are classified as Level 2 within the fair value hierarchy. The fair value of these instruments is estimated using forward-looking price curves and discounted cash flows that are observable or that can be corroborated by observable market data.
Crude oil derivatives settle against the average of the prompt month NYMEX future prices for West Texas Intermediate.
The fair values of commodity derivatives were as follows (in thousands):
September 30, 2021December 31, 2020
Commodity derivative assets
Current portion$562 $6,060 
Long-term portion1,549 2,809 
2,111 8,869 
Commodity derivative liabilities
Current portion12,799 76 
Long-term portion8,578 1,868 
21,377 1,944 
Net commodity derivatives($19,266)$6,925 
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NOTE 5. DERIVATIVE INSTRUMENTS - CONTINUED
The following presents the results of the Company’s oil and gas derivative activity included in revenue in the statements of operations during the periods ended September 30, 2021 and 2020:
Nine-Months Ended
September 30, 2021September 30, 2020
Realized (loss) gain
Oil derivatives($8,453)$17,793 
Natural gas derivatives(108)— 
Total realized (loss) gain($8,561)$17,793 
Unrealized (loss) gain
Oil derivatives($23,859)$21,942 
Natural gas derivatives(2,331)(127)
Total unrealized (loss) gain($26,190)$21,815 
(Loss) gain on derivative instruments, net($34,751)$39,608 
The Company had the following outstanding open crude oil and natural gas positions as of September 30, 2021:
Expirations
2021202220232024
Oil Swaps:
Notional volume (bbl)236,500 279,300 — — 
Weighted average swap price$53.13 $53.44 $51.06 $— $— 
Mid-Cush Differential (Basis) Swap:
Notional volume (bbl)236,500 426,800 150,100 75,600 
Weighted average swap price$1.01 $0.93 $0.39 $0.55 
Oil Collars:
Notional volume (bbl)— 178,400 248,600 75,600 
Weighted average put purchased$— $50.33 $41.30 $48.44 
Weighted average call sold$— $59.00 $49.76 $56.07 
Natural Gas Swaps:
Notional volume (MMBTU)132,900 702,600 151,800 — 
Weighted average swap price$3.06 $2.49 $2.59 $— 
Waha Differential (Basis) Swap:
Notional volume (MMBTU)270,400 727,800 151,800 — 
Weighted average swap price($0.21)($0.29)($0.31)$— 
Natural Gas Collars:
Notional volume (MMBTU)45,400 25,200 — — 
Weighted average put purchased$2.80 $2.80 $— $— 
Weighted average call sold$3.49 $3.49 $— $— 
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NOTE 5. DERIVATIVE INSTRUMENTS - CONTINUED
The Company had the following outstanding open crude oil and natural gas positions as of December 31, 2020:
Expirations
202120222023
Oil Swaps:
Notional volume (bbl)1,042,700 279,300 — 
Weighted average swap price$53.54 $53.44 $51.06 $— 
Mid-Cush Differential (Basis) Swap:
Notional volume (bbl)1,042,700 279,300 117,700 
Weighted average swap price$1.00 $1.00 $0.30 
Oil Collars:
Notional volume (bbl)— 30,900 216,200 
Weighted average put purchased$— $40.00 $40.00 
Weighted average call sold$— $45.15 $48.36 
Natural Gas Swaps:
Notional volume (MMBTU)858,200 702,600 151,800 
Weighted average swap price$3.06 $2.49 $2.59 
Waha Differential (Basis) Swap:
Notional volume (MMBTU)954,300 702,600 151,800 
Weighted average swap price($0.27)($0.30)($0.31)
Proceeds from the Callon Divestiture were used to unwind the Company’s outstanding derivative contracts in conjunction with the closing of the transaction. See Note 11 for additional information.
NOTE 6. LINE OF CREDIT AND TERM LOAN FACILITIES
Debt outstanding is as follows (in thousands):
September 30, 2021December 31, 2020
Reserves-based line of credit$7,500 $— 
Term loan - HPS75,000 75,000 
Deferred loan cost - HPS, net(1,200)(1,463)
Total debt outstanding$81,300 $73,537 
Reserves-based Lines of Credit
On November 29, 2018, the Company entered into a senior, first lien credit agreement with J.P. Morgan expiring November 28, 2023. Substantially all of the Company’s oil and gas assets are pledged as collateral to be considered as a part of the borrowing base which is set by J.P. Morgan as administrative agent and is redetermined semi-annually. In addition, we may request a borrowing base redetermination up to two times per year based on certain factors. As of December 31, 2020, the borrowing base is $60 million.
On April 16, 2021, the borrowing base was reaffirmed at $60 million.

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NOTE 6. LINE OF CREDIT AND TERM LOAN FACILITIES - CONTINUED
Reserves-based Lines of Credit - continued
The Credit Facility contains certain financial covenants that must be met by BPP. A current ratio of 1.0 times or greater must be maintained at each quarter end. The calculation of the current ratio under the Credit Agreement dictates that the available, undrawn balance on the Credit Facility be added to current assets for debt compliance calculation purposes among other adjustments. Further, the secured debt to EBITDA ratio for the trailing four-fiscal quarters must be no greater than 3.5 times. The covenants also include certain customary restrictions on sales or encumbrances of assets, other advances, indebtedness, distributions and mergers or consolidations.
The applicable base rate is equal to the London Interbank Offered Rate (“LIBOR”) plus a margin ranging from 3% to 4% based on the percentage of the borrowing base utilized. The Credit Facility carries a commitment fee of 50 basis points on the unused portion of the borrowing base. Interest expense related to the Credit Facility of $0.9 million and $0.3 million was recorded during the nine-month periods ended September 30, 2021 and 2020, respectively.
Amortization of deferred loan costs related to the Credit Facility of $0.1 million was recorded during the nine-month periods ended September 30, 2021 and 2020, respectively.
Proceeds from the Callon Divestiture were used to pay down the outstanding balance and accrued interest in conjunction with the closing of the transaction. See Note 11 for additional information.
Term Loan Agreement
On December 10, 2018, the Company entered into a $75 million delayed draw term loan with HPS Investment Partners (“HPS”). An amount of $25 million was funded (less discounts on issuance and related bank fees) upon closing with the remaining balance to be drawn within twelve months of the closing date with a maturity of December 10, 2024.
The remaining amount of $50 million was drawn during 2019.
Interest on this term loan is payable quarterly and is at a rate equal to the LIBOR plus 8.0%. Interest expense related to the HPS term loan of $5.4 million was recorded during the nine-month periods ended September 30, 2021 and 2020, respectively.
Amortization of deferred loan costs related to the HPS term loan of $0.3 million was recorded during the nine-month periods ended September 30, 2021 and 2020, respectively.
The term loan agreement contains various covenants pertaining to the financial condition of the Company. The covenants include an Asset Coverage Ratio with respect to the relationship between total debt and proved reserves of no less than 1.50 times. For purposes of this covenant, total debt is the debt at BPP EF of $75 million plus any outstanding amounts drawn on the revolving credit facility. The covenants also include certain restrictions on sales or encumbrances of assets, other advances, indebtedness, distributions and mergers or consolidations.
As part of this credit facility, the Company created BPP EF as a subsidiary of BPP.
Proceeds from the Callon Divestiture were used to pay down the outstanding principal and accrued interest in conjunction with the closing of the transaction. See Note 11 for additional information.
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NOTE 7. MEMBERS’ INTEREST
The Company has two classes of Member Interest consisting of Common Interest and Profits Interest. These interests include the Series A Profits Interest, and two series of Common Interest, the Series B Common Interest and Series C Common Interest. Series A Profits Interest were issued to legacy unit holders of PEP. Additionally, A Profits Interest have been authorized for issuance to management of the Company as incentive compensation.
Series A Profits Interest represent equity interest in the Company and its holders participate in profits of the Company once certain payout thresholds are met for the Series B and C Common Interest holders. Accordingly, the value of the Series A Profits Interest at issuance was de minimis.
The Company’s distribution of profit and loss will be applied as follows:
First, to the Common Interest Holders based on their pro-rata invested capital until all invested capital is recovered and a cumulative amount of distributions are received to achieve a 13.5% rate of return.
Second, the vested Series A Profits Interest will receive 12.5% of the distributions with the remainder going to Common Interest Holders until the Common Interest Holders achieve a 20% rate of return and a multiple of 2.05 times their invested capital.
Third, the vested Series A Profits Interest will receive 22.5% of the distributions with the remainder going to the Common Interest Holders until the Common Interest Holders achieve a 30% rate of return and a multiple of 3.05 times their invested capital.
Lastly, the vested Series A Profits Interest will receive 32.5% of the distributions with the remainder going to the Common Interest Holders.
NOTE 8. MID-TERM INCENTIVE PLAN
In 2020, the Board of Directors established the Mid Term Incentive Plan (“MTIP”) as an incentive program for the Company’s directors, executives, and key employees. The program designates a pool of up to $15.0 million to be granted to employees and provide a cash award when the affiliated Primexx entities (Primexx Energy Partners, Ltd., BPP Energy Partners LLC, and Rock Ridge Royalty Company LLC) have a Liquidity Event. The award is to be split proportionately amongst the affiliated entities based on the cash amount received for each entity. The award vests in two tranches with 65% of the award vesting over a three-year period and 35% of the award is based on personal performance of the grantee as determined by the Board of Directors. The portion that is time vested will fully accelerate and vest upon the change of control of the entities subject to the grantee’s continuous service and remaining in good standing with the Company through the date of the change in control.
Because the MTIP award is not considered a substantive class of equity, and only pays grantees upon a liquidity event of the entity, there is no expense recorded in the financial statements related to these awards. As of December 31, 2020, the total pool granted to employees under the MTIP was completely distributed.
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NOTE 9. RELATED PARTY TRANSACTIONS
Primexx Energy Partners Ltd.
The Company has shareholders and management in common with PEP. In connection with the formation of the Company, the board approved a shared service agreement between the two companies so that all operations of the Company are conducted by a subsidiary of PEP and the cost of shared resources (including technology, office space and personnel) are reimbursed to PEP by the Company at a rate of cost plus 2%. Additionally, the Company holds non-operated working interest in wells currently being drilled by PEP. Accordingly, PEP is responsible for distributing the Company’s share of revenue and invoicing for the related share of capital and lease operating expenses in accordance with the ownership held by the Company.
SFS, an equity method investment of BPP, is a controlled subsidiary of PEP that owns the company’s field services assets in Reeves County, which include gas gathering, water management, and other oil field service assets. See Note 4 for additional information.
The following represents the balances and activity between BPP and PEP (in thousands):
September 30, 2021September 30, 2020
Affiliate payable to PEP$6,810 $111 
Revenue paid from PEP$45,723 $34,124 
Capital and lease operating expenses paid via joint interest billings to PEP$53,427 $37,548 
General and administrative expenses reimbursed$3,794 $2,238 
BPP had $19.4 million of unapplied prepaid capital expenditures deposited with PRD and recorded in other current liabilities as of December 31, 2020, respectively. As of September 30, 2021, PRD refunded the remaining $11.1 million of unapplied prepaid capital expenditures to BPP.
NOTE 10. COMMITMENTS AND CONTINGENCIES
The Company’s operations are subject to all the operational and environmental risks normally associated with the crude oil and natural gas industry. Additionally, the Company may become involved from time to time in litigation on various matters which are routine to the conduct of its business. Management is not currently a party to any material litigation and is not aware of any litigation threatened against the Company that could have a material adverse effect on the Company.
Changes to current economic conditions may adversely affect the results of operations in future periods. The novel coronavirus (“COVID-19”) pandemic significantly affected the global economy and created significant volatility in commodity prices during 2020. Commodity prices have recovered in 2021 based on rising demand as global economic activity increased in addition to sustained production cuts by the Organization of the Petroleum Exporting Countries (“OPEC”). However, uncertainty continues to exist regarding the recovery of global oil demand in future periods due to various factors and circumstances beyond the Company’s control, such as the duration of the pandemic and variant strains of COVID-19, OPEC and other oil producing nations managing the global oil supply, government actions in response to the pandemic, global supply chain constraints, and cost inflation. The financial statements have been prepared using values and information currently available to the Company.
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NOTE 11. SUBSEQUENT EVENTS
On October 1, 2021, the Primexx Entities closed the divestiture transaction with a subsidiary of Callon. The fair value of consideration received by the Company totaled $212.3 million and was comprised of $90.4 million of cash consideration and 2.42 million shares of Callon stock issued to the Company in exchange for its oil and gas leasehold interests and ownership interest in infrastructure assets, subject to the finalization of purchase price adjustments within 120 days of closing.
Upon closing, the Company used cash proceeds from the Callon Divestiture and cash on hand to unwind its outstanding derivative contracts for $21.5 million and pay down the outstanding principal balances and accrued interest related to the HPS term loan and the Credit Facility of $76.4 million and $7.6 million, respectively.
Subsequent events were evaluated through November 19, 2021, the date the condensed consolidated financial statements were available for issuance.
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