cpe-20211001
0000928022true00009280222021-10-012021-10-01

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K/A

CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): October 1, 2021
https://cdn.kscope.io/da292b2786bbd9275e621934bcdf735b-cpe-20211001_g1.jpg
Callon Petroleum Company
(Exact name of registrant as specified in its charter)
DE001-1403964-0844345
(State or other jurisdiction of incorporation)(Commission File Number)(I.R.S. Employer Identification Number)

One Briarlake Plaza
2000 W. Sam Houston Parkway S., Suite 2000
Houston, TX 77042
(Address of principal executive offices, including zip code)

(281) 589-5200
(Registrant’s telephone number, including area code)
(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

    Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
    Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
    Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
    Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common Stock, $0.01 par valueCPENYSE

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (17 CFR §240.12b-2).
    Emerging growth company     
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.




EXPLANATORY NOTE
As previously disclosed in its Current Report on Form 8-K, filed with the U.S. Securities and Exchange Commission on October 5, 2021 (the “Original Form 8-K”), Callon Petroleum Company (“Callon” or the “Company”) and Callon Petroleum Operating Company (“CPOC”), Callon’s wholly owned subsidiary, entered into purchase and sale agreements with Primexx Resource Development, LLC (“Primexx”) and BPP Acquisition, LLC (“BPP”), for the purchase of certain producing oil and gas properties, undeveloped acreage and associated infrastructure assets in the Delaware Basin (collectively, the “Peak Acquisition”).
On October 1, 2021, the Company and CPOC completed the Peak Acquisition for a preliminary purchase price of approximately (i) $362.2 million in cash and 6.42 million shares of Company common stock as total consideration for assets acquired from Primexx and (ii) $91.5 million in cash and 2.42 million shares of Company common stock as total consideration for assets acquired from BPP. The purchase and sale agreements with Primexx and BPP provide for customary adjustments to the purchase price based on an effective date of July 1, 2021.
This Current Report on Form 8-K/A amends and supplements the Original Form 8-K to provide the financial statements and information set forth in Item 9.01 hereto.
Item 9.01. Financial Statements and Exhibits
(a) Financial statements of business to be acquired.
The audited annual consolidated financial statements of Primexx Energy Partners, Ltd. and its subsidiaries, which comprise the consolidated balance sheets as of December 31, 2020 and 2019, and the related consolidated statements of operations, changes in partners’ equity (deficit), and cash flows for the years then ended, and the related notes to the consolidated financial statements, are filed as Exhibit 99.1 hereto and incorporated by reference herein.
The unaudited quarterly consolidated financial statements of Primexx Energy Partners, Ltd. and its subsidiaries, which comprise the balance sheet as of September 30, 2021, the related consolidated statements of operations, changes in partners’ equity (deficit), and cash flows for the nine-month periods ended September 30, 2021 and 2020, and the related notes to the consolidated financial statements, are filed as Exhibit 99.2 hereto and incorporated by reference herein.
The audited annual consolidated financial statements of BPP Energy Partners LLC and its subsidiaries, which comprise the consolidated balance sheets as of December 31, 2020 and 2019, and the related consolidated statements of operations, changes in members’ equity, and cash flows for the years then ended, and the related notes to the consolidated financial statements, are filed as Exhibit 99.3 hereto and incorporated by reference herein.
The unaudited quarterly consolidated financial statements of BPP Energy Partners LLC and its subsidiaries, which comprise the balance sheet as of September 30, 2021, the related consolidated statements of operations, changes in partners’ equity (deficit), and cash flows for the nine-month periods ended September 30, 2021 and 2020, and the related notes to the consolidated financial statements, are filed as Exhibit 99.4 hereto and incorporated by reference herein.
(b) Pro forma financial information.
The unaudited pro forma condensed combined financial information of the Company, which comprise the balance sheet as of September 30, 2021, the related statements of operations for the year ended December 31, 2020 and nine-month period ended September 30, 2021, and the related notes to the pro forma condensed combined financial information, is filed as Exhibit 99.5 hereto and incorporated by reference herein.



(d) Exhibits.
Exhibit NumberDescription
23.1
23.2
23.3
99.1
99.2
99.3
99.4
99.5
99.6
99.7
99.8
99.9
104Cover Page Interactive Data File - the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.



SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.


Callon Petroleum Company
(Registrant)
November 19, 2021/s/ Joseph C. Gatto, Jr.
Joseph C. Gatto, Jr.
President and Chief Executive Officer


Document

Exhibit 23.1
CONSENT OF INDEPENDENT AUDITORS
We consent to the incorporation by reference in Registration Statement Nos. 333-251490, 333-235634, and 333-230748 on Form S-3 and Registration Statement Nos. 333-239006 and 333-235635 on Form S-8 of Callon Petroleum Corporation of our report dated March 31, 2021, relating to the financial statements of Primexx Energy Partners, Ltd. included in this Current Report on Form 8-K dated November 19, 2021.
/s/ Deloitte & Touche LLP
Dallas, Texas
November 19, 2021



Document

Exhibit 23.2
CONSENT OF INDEPENDENT AUDITORS
We consent to the incorporation by reference in Registration Statement Nos. 333-251490, 333-235634, and 333-230748 on Form S-3 and Registration Statement Nos. 333-239006 and 333-235635 on Form S-8 of Callon Petroleum Corporation of our report dated March 31, 2021, relating to the financial statements of BPP Energy Partners LLC included in this Current Report on Form 8-K dated November 19, 2021.
/s/ Deloitte & Touche LLP
Dallas, Texas
November 19, 2021



Document

Exhibit 23.3
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
We hereby consent to the references to our firm, in the context in which they appear, and to the references to and the incorporation by reference of our reserves reports, dated October 26, 2021, and October 27, 2021, relating to the proved oil and gas reserves of Primexx Resource Development, LLC as of December 31, 2019, and December 31, 2020, respectively (the “Primexx Reports”), and of our reserves reports, dated October 26, 2021, and October 27, 2021, relating to the proved oil and gas reserves of BPP Acquisition LLC as of December 31, 2019, and December 31, 2020, respectively (the “BPP Reports” and, together with the Primexx Reports, our “Reports”), included in or made a part of this Current Report on Form 8-K/A of Callon Petroleum Company (the “Company”) dated November 19, 2021, in accordance with the requirements of the Securities Act of 1933, as amended. We further consent to the incorporation by reference of our Reports and references to our firm in the Company’s Registration Statements on Form S-3 (No. 333-251490, No. 333‑235634, and No. 333‑230748) and on Form S-8 (No. 333-239006 and No. 333-235635).


NETHERLAND, SEWELL & ASSOCIATES, INC.
By: /s/ C.H. (Scott) Rees III, P.E.
    C.H. (Scott) Rees III, P.E.
    Chairman and Chief Executive Officer
Dallas, Texas
November 19, 2021


Document
Exhibit 99.1



PRIMEXX ENERGY PARTNERS, LTD. AND
SUBSIDIARIES


CONSOLIDATED FINANCIAL STATEMENTS
AND INDEPENDENT AUDITORS’ REPORT



December 31, 2020 and 2019



CONTENTS


Page
INDEPENDENT AUDITORS’ REPORT
CONSOLIDATED FINANCIAL STATEMENTS
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Changes in Partners’ Equity (Deficit)
Consolidated Statements of Cash Flows
Notes to the Consolidated Financial Statements
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)





INDEPENDENT AUDITORS’ REPORT
To the Board of Directors of Primexx Energy Partners, Ltd.
Dallas, Texas
We have audited the accompanying consolidated financial statements of Primexx Energy Partners, Ltd. and its subsidiaries (the "Partnership"), which comprise the consolidated balance sheets as of December 31, 2020 and 2019, and the related consolidated statements of operations, changes in partners’ equity (deficit), and cash flows for the years then ended, and the related notes to the consolidated financial statements.
Management’s Responsibility for the Consolidated Financial Statements
Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.
Auditors’ Responsibility
Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the Partnership's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
Opinion
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Primexx Energy Partners, Ltd. and its subsidiaries as of December 31, 2020 and 2019, and the results of their operations and its cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.
Emphasis of Matter Regarding Going Concern
The accompanying consolidated financial statements have been prepared assuming that the Partnership will continue as a going concern. As discussed in Note 1 to the consolidated financial statements, the Partnership does not have sufficient liquidity to repay the term loan with BPP Holdco LLC, a related party, maturing on November 10, 2021, and as a result has stated that substantial doubt exists about its ability to continue as a going concern. Management's evaluation of the events and conditions and management’s plans regarding these matters are also described in Note 1. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty. Our opinion is not modified with respect to this matter.

/s/ Deloitte & Touche LLP
March 31, 2021




PRIMEXX ENERGY PARTNERS, LTD. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31
(in thousands)

20202019
Assets
Current Assets
Cash and cash equivalents$7,253 $22,501 
Trade accounts receivable17,028 37,126 
Accounts receivable - affiliate1,350 10,849 
Prepaids and other415 520 
Commodity derivatives14,263 638 
Total current assets40,309 71,634 
Property, plant and equipment, net:
Oil and gas properties, full cost method of accounting273,167 730,248 
Other property and equipment, net ($0 and $1,463 attributable to a consolidated VIE)90,953 97,259 
Commodity derivatives9,078 544 
Loan origination cost, net2,468 3,142 
Prepaids and other1,059 452 
Total Assets$417,034 $903,279 
Liabilities, Preferred Units and Partners’ Equity
Current Liabilities
Accounts payable$1,629 $17,780 
Oil and gas payable17,421 27,543 
Commodity derivatives974 11,761 
Other current liabilities54,319 29,511 
Current portion of deferred gain on oil gathering system2,625 2,625 
Current portion of long-term debt, net129,994 129,948 
Total current liabilities206,962 219,168 
Line of credit87,500 138,000 
Term loans, net147,933 147,436 
Deferred gain on oil gathering system24,500 27,125 
Commodity derivative4,775 3,815 
Other long-term liabilities295 — 
Asset retirement obligation5,327 3,664 
Deferred tax liability46 133 
Total Liabilities477,338 539,341 
Commitments and contingencies (Note 11)
Redeemable Series B Preferred Units, net518,562 451,003 
Equity
Partners’ Equity (deficit)(599,205)(110,234)
Noncontrolling interest20,339 23,169 
Total (Deficit)(578,866)(87,065)
Total Liabilities, Preferred Units and Partners’ Equity$417,034 $903,279 


The accompanying notes are an integral part of these consolidated financial statements.
2



PRIMEXX ENERGY PARTNERS, LTD. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31
(in thousands)

20202019
Revenues
Oil sales$139,776 $200,419 
Natural gas sales10,627 8,942 
Field service revenue8,450 20,777 
Gain (loss) on derivative instruments, net93,256 (30,148)
Total revenues252,109 199,990 
Costs and expenses
Lease operating expenses41,988 24,800 
Repairs4,820 6,061 
Production taxes6,994 9,516 
Transportation and marketing1,868 1,005 
Field service expenses11,677 26,521 
Depreciation, depletion and amortization106,047 96,783 
Impairment of oil and gas properties457,502 — 
General and administrative7,477 7,027 
Total operating expenses638,373 171,713 
(Loss) income from operations(386,264)28,277 
Other income (expense)
Gain on sale of saltwater disposal system— 136,342 
Other income2,882 1,308 
Interest expense(40,138)(46,500)
Total other income (expense)(37,256)91,150 
(Loss) income before income taxes(423,520)119,427 
Income tax (benefit) expense
Texas margin tax expense81 — 
Deferred tax (benefit) expense(87)32 
Total income tax (benefit) expense(6)32 
Net (loss) income(423,514)119,395 
Net loss (gain) attributable to noncontrolling interest550 (48,079)
Series B preferred unit distribution(66,148)(57,923)
Net (loss) income attributable to other partners($489,112)$13,393 


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



PRIMEXX ENERGY PARTNERS, LTD. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ EQUITY (DEFICIT)
(in thousands)

General PartnerSeries A
Preferred
Common
Units
Noncontrolling
Interest
Total
Equity
Balance, January 1, 2019($76)$37,344 ($160,895)$27,355 ($96,272)
Series A Preferred Deemed Distribution— 12,360 (12,360)— — 
Sale of interest in SFS— — — 8,759 8,759 
Net gain attributable to noncontrolling interest— — — 48,079 48,079 
Distribution to noncontrolling interest by SFS— — — (61,024)(61,024)
Net income attributable to other partners— 6,280 7,113 — 13,393 
Balance, December 31, 2019($76)$55,984 ($166,142)$23,169 ($87,065)
Series A Preferred Deemed Distribution— 12,360 (12,360)— — 
Purchase of Pecos Property by SFS from noncontrolling interest— 66 75 (2,280)(2,139)
Net loss attributable to noncontrolling interest— — — (550)(550)
Net loss attributable to other partners— (229,342)(259,770)— (489,112)
Balance, December 31, 2020($76)($160,932)($438,197)$20,339 ($578,866)


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


PRIMEXX ENERGY PARTNERS, LTD. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31
(in thousands)
Cash flow from operating activities20202019
Net (loss) income($423,514)$119,395 
Adjustments to reconcile net income to cash used in operating activities:
Depreciation, depletion, and amortization106,047 96,783 
Impairment of oil and gas properties457,502 — 
Deferred loan cost amortization1,826 2,471 
Amortization of deferred gain on oil gathering system(2,625)(1,750)
Gain on sale of property - net— (135,900)
Accretion of discount on preferred unit issuance1,411 1,409 
Unrealized (gain) loss on derivative instruments(31,985)28,907 
Deferred tax expense(87)32 
Changes in operating assets and liabilities:
Trade accounts receivable20,098 (20,166)
Accounts receivable - affiliate9,499 (5,240)
Prepaid and other assets(722)1,700 
Accounts payable(16,729)(25,013)
Oil and gas payable(10,122)15,059 
Accrued liabilities and other10,913 (13,751)
Net cash provided by operating activities121,512 63,936 
Cash flow from investing activities
Additions to oil and gas properties(73,920)(222,394)
Additions to other property(9,592)(49,529)
Proceeds from sale of property— 380 
Proceeds from sale of oil gathering system— 31,500 
Proceeds from sale of saltwater disposal system— 185,000 
Net cash used in investing activities(83,512)(55,043)
Cash flow from financing activities
Proceeds from sale of interest in SFS— 8,759 
Distribution to minority interest owners made by SFS— (61,024)
Purchase of Pecos Property by SFS from noncontrolling interest(2,139)— 
Proceeds from Term Loan— 50,000 
Proceeds from line of credit44,000 162,000 
Repayments of line of credit(94,500)(160,000)
Capitalized loan cost(609)(1,385)
Net cash used in financing activities(53,248)(1,650)
Net change in cash and cash equivalents(15,248)7,243 
Cash and cash equivalents, beginning of period22,501 15,258 
Cash and cash equivalents, end of period$7,253 $22,501 
Supplemental cash disclosures:
Property additions included in accrued liabilities$14,767 $24,466 
Cash paid for interest$37,685 $43,757 
Asset retirement obligations incurred, including revisions to estimates$1,357 $2,850 
Non cash settlement - capital lease liability$— $13,253 
Non cash financing - Redeemable Series B Preferred Units$66,148 $57,923 

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


PRIMEXX ENERGY PARTNERS AND SUBSIDARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. ORGANIZATION
Primexx Energy Partners, Ltd. (“PEP”), a Texas Limited Partnership, was formed on July 1, 2000, and is engaged in the acquisition, development, production, exploration and sale of crude oil and natural gas properties located primarily in Reeves County Texas.
On July 1, 2016, PEP reorganized and obtained additional investment in the form of Redeemable Series B Preferred units through funds controlled by The Blackstone Group (“Blackstone”). In addition to this investment, Blackstone also obtained a 55% controlling interest in Primexx Energy Corporation (“PEC”), a Texas corporation, and the sole general partner of PEP.
Going Concern, Liquidity, and Management’s Plan
The accompanying consolidated financial statements are prepared in accordance with generally accepted accounting principles applicable to a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business.
Management evaluates conditions and events that are relevant to the Partnership’s ability to meet its obligations as they become due within one year after the date that the consolidated financial statements are issued. The Partnership has an unsecured term loan payable to BPP Holdco, LLC (a related party, see Notes 6 and 10) with an outstanding principal balance of $130.0 million which matures on November 10, 2021. Management has considered existing cash, availability under the reserves-based line of credit, along with projected future cash flows, and concluded that the Partnership will not have sufficient liquidity to repay the term loan at maturity. These conditions and events raise substantial doubt about the Partnership’s ability to continue as a going concern.
In response to these conditions, management has been, and is currently, pursuing a refinancing of this loan through an amendment, extension or refinancing. However, because management’s plans have not been finalized and are not within the Partnership’s control, these plans cannot be considered probable of occurring as of March 31, 2021, the date the consolidated financial statements were available for issuance. As a result, the Partnership has concluded that management’s plans do not alleviate substantial doubt about the Partnership’s ability to continue as a going concern.
The consolidated financial statements do not include any adjustments relating to the recoverability and classification of recorded asset amounts and classification of liabilities that might result from the outcome of this uncertainty.
Principles of Consolidation
The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America. These financial statements include the accounts of Primexx Energy Partners, Ltd. and its subsidiaries: (i) Primexx Energy Finance, LLC (PEF), (ii) Primexx Resource Development, LLC (PRD), (iii) Primexx Operating Corporation (POC), (iv), and Saragosa Field Services, LLC (SFS) (collectively referred to as the Partnership). Intercompany transactions and balances have been eliminated in consolidation.

6


NOTE 1. ORGANIZATION - CONTINUED
Principles of Consolidation - continued
On July 11, 2018, the Partnership sold approximately 22% of its interest in SFS to a subsidiary of BPP Energy Partners LLC (“BPP”), an affiliated entity (see Note 3 and Note 10). On May 1, 2019 and July 2, 2019, the Partnership sold an additional 6.23% and 1.75%, respectively, of its interest in SFS to BPP. Total sold through the balance sheet date is 30%. Given the Partnership’s majority interest and its control of the entity, SFS remains a consolidated entity with the minority shareholder’s interest shown as noncontrolling interest in the consolidated financial statements.
NOTE 2. SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates
The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (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 consolidated 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, derivative financial instruments, asset retirement obligations, and legal and environmental risks and exposures.
Cash and Cash Equivalents
The Partnership considers all liquid investments with original maturities of three months or less to be cash equivalents. At December 31, 2020 and 2019, the Partnership did not have any cash equivalents.
Trade Accounts Receivable
Substantially all the Partnership’s receivables are within the oil and gas industry, primarily from purchasers of oil and gas and joint interest billings. Collectability is dependent upon the general economic conditions of the purchasers and the industry. The receivables are not collateralized.
The Partnership has had minimal bad debts; therefore, the Partnership has not recorded an allowance for doubtful accounts as of December 31, 2020 or 2019. Management considers the following factors when determining the collectability of specific accounts: credit worthiness, past transaction history, current economic industry trends, and changes in payment terms. If the financial condition of the Partnership’s purchasers or working interest partners were to deteriorate, adversely affecting their ability to make payments, allowances would be necessary.
Oil and Gas Properties
The Partnership 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.
7


NOTE 2. SIGNIFICANT ACCOUNTING POLICIES - CONTINUED
Oil and Gas Properties - continued
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 Partnership’s proved property impairment assessment as of December 31, 2020, the Partnership recorded a $457.5 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 year ended December 31, 2019.
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. We determine the amount of costs to transfer from unproved properties based on our estimate of the potential drilling locations and potential reserves associated with those properties. 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. The impairment assessment includes consideration of our intent to fully develop our unproved properties, remaining lease terms, geological and geophysical evaluations, our drilling results, potential drilling locations, availability of capital, assignment of proved reserves, expected divestitures, anticipated future capital expenditures and economic considerations, among others. During any period in which impairment is indicated, the accumulated cost 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. Unproved properties totaled $0 and $2.8 million were moved to the amortization base due to lease expiration during the years ended December 31, 2020 and 2019, respectively.
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.
Other Property and Equipment
Other property and equipment includes furniture and fixtures, computer equipment, software, transportation equipment, and field service equipment consisting of gas gathering, gas processing and water management facilities. Property and equipment are recorded at historical cost and depreciated using the straight-line method over their estimated useful lives ranging from 3 to 39 years.
The Partnership assesses the carrying amount of this equipment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If the carrying amount exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized. There was no such impairment for the periods presented.
8


NOTE 2. SIGNIFICANT ACCOUNTING POLICIES - CONTINUED
Prepaid and Other Assets
Prepaid and other assets at December 31 consist of the following:
20202019
Inventory$1,039 $212 
Other435 760 
Total prepaid and other assets$1,474 $972 
Derivative Activity
The Partnership 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 Partnership reports the fair value of derivatives on the consolidated balance sheets in commodity derivative assets or liabilities as either current or noncurrent. The Partnership determines the current and noncurrent classification based on the timing of expected future cash flows of the individual trades. The Partnership reports these on a gross basis by counterparty.
The Partnership’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 Gain (loss) on derivative instruments, net, in the 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.
9


NOTE 2. SIGNIFICANT ACCOUNTING POLICIES - CONTINUED
Loan Origination Costs
Loan origination costs are amortized over the term of the related obligation using the effective interest method. Origination cost associated with our reserves-based line of credit are presented net of amortization within long-term assets. Origination cost associated with our term loans are net of amortization cost and are reported as an offset to the outstanding balance within long-term liabilities.
Other Accrued Liabilities
Other accrued liabilities at December 31 consist of the following:
20202019
Accrued capital expenditures$14,215 $14,268 
Lease operating expenses payable12,042 10,029 
Liability for drilling costs prepaid by joint interest partners21,927 1,098 
Other6,430 4,116 
Total other accrued liabilities$54,614 $29,511 
Asset Retirement Obligations
The Partnership records a liability for asset retirement obligations and increases the carrying value of the related asset in the period in which the liability is incurred. Asset retirement obligations primarily relate to the abandonment of oil and natural gas producing facilities and include costs to dismantle and relocate or dispose of wells and related structures. Accretion expense associated with asset retirement obligations is recorded over time. Our asset retirement obligations are recorded in long- term liabilities within the consolidated balance sheets.
The following table shows the changes in the balances of the asset retirement as of December 31 (in thousands):
20202019
Asset retirement obligation, January 1$3,664 $575 
Liabilities incurred231 650 
Liabilities sold— (49)
Liabilities settled(281)(1,379)
Changes in estimates1,407 3,628 
Accretion expense306 239 
Asset retirement obligation, December 31$5,327 $3,664 
Comprehensive Income
During the years ended December 31, 2020 and 2019, the Partnership did not have comprehensive income or loss. Accordingly, net income (loss) equals comprehensive income (loss) for the periods presented.
10


NOTE 2. SIGNIFICANT ACCOUNTING POLICIES - CONTINUED
Revenue Recognition
The Partnership enters into contracts with customers to sell its oil and natural gas production. Revenue on these contracts is recognized in accordance with the five-step revenue recognition model. Specifically, revenue is recognized when the Partnership’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 Partnership 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. At December 31, 2020 and 2019, the Partnership had receivables related to contracts with customers of $12.8 million and $27.9 million, respectively.
Oil Contracts - The majority of the Partnership’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 Partnership’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 Partnership’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 Partnership’s consolidated statements of operations.
The Partnership 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.
Concentration
The Partnership sold approximately 90% and 91% of its oil and natural gas production to two purchasers during the years ended December 31, 2020 and 2019, respectively.
11


NOTE 2. SIGNIFICANT ACCOUNTING POLICIES - CONTINUED
Income Taxes
The Partnership is organized as limited partnerships except for POC, and federal income tax is assessed against the individual partners rather than against the partnerships. The Partnership evaluates the tax positions taken or expected to be taken in the course of preparing the Partnership’s tax returns and disallows the recognition of tax positions not deemed to meet a “more-likely-than- not” threshold of being sustained by the applicable tax authority. The Partnership’s management does not believe it has any tax positions taken within its consolidated financial statements that would not meet this threshold.
POC is a C-corporation for federal and state income tax purposes. As POC is wholly owned by the Partnership, the current and deferred income taxes related to POC are shown within the consolidated financial statements. We account for deferred tax assets and liabilities based on the difference between the financial book and tax basis of assets and liabilities using enacted rates expected to be in effect during the year in which the basis differences reverse.
The realizability of deferred tax assets are evaluated and a valuation allowance is established to reduce the deferred tax assets if it is more likely than not that the related tax benefits will not be realized and we are in a net deferred tax asset position related to each jurisdiction. All deferred items are classified in the long-term portion of assets or liabilities.
The Partnership’s policy is to reflect interest and penalties related to uncertain tax positions as part of its income tax expense, when and if they become applicable. Tax positions taken related to the Partnership’s pass-through status and those taken in determining their state income tax liability, including deductibility of expenses, have been reviewed and management is of the opinion that material positions taken by the Partnership would more likely than not be sustained by examination. Accordingly, the Partnerships has not recorded an income tax liability for uncertain tax positions. The Partnership’s uncertain tax positions are subject to examination under Internal Revenue Service’s general statutes for the year ended December 31, 2018 and thereafter.
New Accounting Pronouncements
In February 2016, FASB issued ASU 2016-02 – Leases (Topic 842), which requires the recognition of lease assets and lease liabilities by lessees for those leases currently classified as operating leases and makes certain changes to the accounting for lease expenses. This update is effective for fiscal years beginning after December 15, 2021, and for interim periods beginning the following year. ASC 842 should be applied using a modified retrospective approach. The Partnership is in the process of evaluating the impact of this new standard on its financial statements. The new guidance is expected to impact the Partnership’s balance sheets due to the recognition of right-of-use assets and lease liabilities that are not currently recognized under current accounting standards. The standard does not apply to leases to explore for or use minerals, oil or gas resources.



12


NOTE 2. SIGNIFICANT ACCOUNTING POLICIES - CONTINUED
New Accounting Pronouncements - continued
In June 2016, the FASB issued ASU 2016-13, "Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments" ("ASU 2016-13"). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, and requires entities to use a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. This update is effective for fiscal years beginning after December 15, 2022, including interim periods within those fiscal years, with early adoption permitted. Entities will use the modified retrospective approach to apply the standard's provisions and record a cumulative-effect adjustment to retained earnings for additional receivable loss allowances, if any, as of the beginning of the first reporting period in which the guidance is adopted. The Partnership is in the process of evaluating whether it will have a material impact on its consolidated financial statements.
NOTE 3. PROPERTY
Property consisted of the following as of December 31 (in thousands):
20202019
Oil and gas properties:
Proved oil and gas properties$1,362,631 $1,272,991 
Accumulated depreciation, depletion and amortization and impairment(1,089,464)(542,743)
Total net oil and gas properties273,167 730,248 
Other property and equipment:
Office building attributable to VIE— 1,472 
Land attributable to VIE— 123 
Accumulated depreciation attributable to VIE— (132)
Total net property attributable to VIE— 1,463 
Office and equipment4,013 3,942 
Field service assets131,872 120,032 
Accumulated depreciation(44,932)(28,178)
Total net other property and equipment90,953 95,796 
Total other property and equipment, net90,953 97,259 
Total net property, plant and equipment$364,120 $827,507 
Supplemental Property Information:
Depletion expense$88,900 $76,162 
Depreciation expense$16,621 $20,382 
Field Service Assets
SFS is a controlled subsidiary of the Partnership that owns the company’s field services assets in Reeves County which include gas gathering, water management and other oil field service assets.
13


NOTE 3. PROPERTY - CONTINUED
Acquisitions and Divestitures
On May 18, 2018, PRD and SFS entered into an agreement with Oryx Southern Delaware Holdings, LLC (“Oryx”). This agreement allowed for the construction of a gathering system to collect the Partnership’s produced oil and provide firm marketing and shipping arrangements for the product. Further as a part of this agreement, SFS had the first right and option to purchase on or before December 31, 2019 all of the gathering system and all rights and interest in the crude oil gathering agreement between the Partnership and Oryx for the net present value of the construction cost plus six percent. Additionally, if the call was exercised, the Partnership had the ability to put the asset to Oryx or participate through tag-along rights in the event Oryx completed a sale of its assets.
On April 2, 2019, SFS received notice that Oryx had entered into a Purchase and Sale Agreement (“PSA”) which constituted an exit event under the agreement. On April 18, 2019, SFS exercised both its call and put rights and settled the transaction with Oryx for a net amount of $31.5 million on May 22, 2019. The Partnership 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. The $31.5 million earned from this transaction was distributed to PRD and BPP in proportion to their equity ownership.
On May 1 and July 2, 2019, the Partnership completed the sale of an additional 6.23% and 1.75% of its equity interest in SFS to BPP for a total sales price of $7.2 million and $1.5 million respectively. These transactions gave BPP their maximum ownership of 30% allowed under the sales agreement reached in 2018.
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 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, the Partnership 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.
Pecos Office Building
On September 9, 2020, SFS exercised its option on behalf of the Partnership 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 Partnership’s Chief Executive Officer) for a total payment of $2.1 million. Prior to the purchase, the Partnership had a lease in place with the owner and utilized the office for field operations. The Pecos Property was previously accounted for as a variable interest entity (“VIE”) and consolidated within the Partnership’s financial statements because the property owner held the option to force a purchase of the property by the Partnership, and the Partnership had the option to force a sale of the property under certain circumstances. Given the related party nature of the transaction and the VIE guidance within GAAP, there is no step-up in basis of the Pecos Property and the excess cash paid over the book value is recorded as a reduction in the equity of SFS. As a result of the transaction, the entire purchase price is a reduction in equity and a financing cash outflow to acquire all of the equity interest in the previously consolidated VIE which is dissolved.
14


NOTE 4. DERIVATIVE INSTRUMENTS
The Partnership engages in price risk management activities. These activities are intended to manage the Partnership’s exposure to fluctuations in commodity prices for crude oil and natural gas. The Partnership 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.
Natural gas and crude oil derivatives settle against the average of the prompt month NYMEX future prices for natural gas and West Texas Intermediate crude oil.
The fair values of commodity derivatives at December 31 were as follows (in thousands):
20202019
Commodity derivative assets
Current portion$14,263 $638 
Long-term portion9,078 544 
23,341 1,182 
Commodity derivative liabilities
Current portion974 11,761 
Long-term portion4,775 3,815 
5,749 15,576 
Net commodity derivatives$17,592 ($14,394)
The following presents the results of the Partnership’s oil and gas derivative activity included in revenue in the statements of operations during the periods ended December 31, 2020 and 2019:
20202019
Realized gain (loss)
Oil derivatives$61,271 ($1,606)
Natural gas derivatives— 365 
Total realized gain (loss)$61,271 ($1,241)
Unrealized gain (loss)
Oil derivatives$32,784 ($28,541)
Natural gas derivatives(799)(366)
Total unrealized gain (loss)$31,985 ($28,907)
Gain (loss) on derivative instruments, net$93,256 ($30,148)
15


NOTE 4. DERIVATIVE INSTRUMENTS - CONTINUED
The Partnership had the following outstanding open crude oil and natural gas positions as of December 31, 2020:
Expirations
202120222023
Oil Swaps:
Notional volume (bbl)2,585,600 1,167,200 — 
Weighted average swap price$53.44 $53.44 $50.68 $— 
Oil Collars:
Notional volume (bbl)— — 627,000 
Weighted average put purchased$— $— $40.00 
Weighted average call sold$— $— $48.38 
Mid-Cush Differential (Basis) Swap:
Notional volume (bbl)2,585,600 1,167,200 353,700 
Weighted average swap price$0.93 $1.04 $0.30 
Natural Gas Swaps:
Notional volume (MMBTU)2,799,000 1,539,100 270,100 
Weighted average swap price$2.54 $2.43 $2.59 
Waha Differential (Basis) Swap:
Notional volume (MMBTU)3,072,600 1,539,100 270,100 
Weighted average swap price($0.26)($0.26)($0.26)
The Partnership had the following outstanding open crude oil and natural gas positions as of December 31, 2019:
Expirations
202020212022
Oil Swaps:
Notional volume (bbl)3,480,373 2,048,000 879,000 
Weighted average swap price$56.35 $53.44 $53.42 $51.12 
Mid-Cush Differential (Basis) Swap:
Notional volume (bbl)3,480,373 2,048,000 879,000 
Weighted average swap price($0.08)$0.91 $1.00 

NOTE 5. TAXES
POC is a C-corporation for federal and state tax purposes, as such, this entity files its own tax return under those requirements and the effect of its tax positions are reflected in the consolidated financial statements.
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NOTE 6. LINE OF CREDIT AND TERM LOAN FACILITIES
Debt as of December 31 (in thousands):
20202019
Reserves-based line of credit$87,500 $138,000 
Term loan - HPS150,000 150,000 
Term loan - Blackstone130,000 130,000 
Deferred loan cost - HPS, net(2,067)(2,564)
Deferred loan cost - Blackstone, net(6)(52)
$365,427 $415,384 
Reserves-based lines of credit
On July 7, 2015, PRD entered into a senior, first lien credit agreement with Société Générale (“SG”), as administrative agent for a syndicated group of participating banks (the “Bank Group”). The credit agreement provided for a $500 million senior secured revolving credit facility expiring July 7, 2019 (the “Credit Facility”).
On November 16, 2018, the Partnership entered into a second amended and restated credit agreement with J.P. Morgan as the administrative agent, replacing Société Générale as the previous administrative agent, for a syndicated group of participating banks. The credit agreement provides for a $750 million senior secured revolving credit facility expiring November 16, 2023. Substantially all the Partnerships oil and gas assets are pledged as collateral and are included in consideration of the borrowing base which is set by J.P. Morgan as administrative agent and is scheduled for redetermination on March 1 and September 1 of each year. In addition, we may request a borrowing base redetermination up to two times per year based on certain factors. The borrowing base at December 31, 2020 is $185 million.
The Credit Facility contains certain financial covenants that must be met by PRD. 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 of PRD for debt compliance calculation purposes, among other adjustments (which calculation does not include the current assets of, or any accrued interest or current maturities of debt held at PRD’s parent entities (PEF or PEP)). Further, the 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 Credit Facility also requires an annual audit certified by independent certified public accountants whose opinion shall not be materially qualified with a scope of audit or “going concern” explanatory paragraph or like qualification or exception unless such going concern exception is resulting from the occurrence of a pending maturity date of any indebtedness of PRD or its parent entities (PEF or PEP). As discussed in Note 1, the pending maturity of PEP’s term loan payable to BPP Holdco, LLC, due November 10, 2021, is indebtedness held by the parent holding company, and as stated in Note 1, resulted in management’s conclusion that substantial doubt exists regarding the Partnership’s ability to continue as a going concern. Given that the emphasis of matter regarding going concern within the independent auditors’ report associated with these financial statements is the result of this pending maturity, management concluded such matter does not result in an event of default.

17


NOTE 6. LINE OF CREDIT AND TERM LOAN FACILITIES - CONTINUED
Reserves-based lines of credit - continued
The applicable base rate is equal to the London Interbank Offered Rate (“LIBOR”) plus a margin ranging from 2.5% to 3.5% 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.
Deferred loan costs of $2.5 million and $3.1 million (net of $4.1 million and $3.2 million in amortization) is recorded in long-term assets for the period ended December 31, 2020 and 2019, respectively.
At December 31, 2020, PRD had $0.3 million in outstanding letters of credit which are deducted from borrowing base availability along with the $87.5 million outstanding under the Credit Facility. The availability under the Credit Facility at December 31, 2020 was $97.2 million.
Term loan agreements
HPS Investment Partners Term Loan
On May 4, 2018, PEF entered into a $150 million delayed draw term loan with HPS Investment Partners (“HPS”). An amount of $50 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 May 4, 2024.
PEF completed additional draws of $50 million on October 1, 2018 and March 1, 2019 under this term loan for a total amount outstanding of $150 million.
The Notes Purchase Agreement contains various covenants pertaining to the financial condition of PEF. The covenants include as Asset Coverage Ratio of no less than 1.0 times beginning with the quarter ending December 31, 2018. The Asset Coverage Ratio increased to 1.50 times at December 31, 2019. For purposes of the covenant test, total debt is the debt at PEF of $150 million and the outstanding amount drawn on the revolver at PRD. The covenants also include certain restrictions on sales or encumbrances of assets, other advances, indebtedness, distributions and mergers or consolidations.
The Notes Purchase Agreement also requires an annual financial statement audit accompanied by a report and opinion of an independent registered public accounting firm, which report and opinion shall not be subject to a “going concern” explanatory paragraph or like qualification or exception other than a “going concern” qualification resulting from the occurrence of a pending maturity date of indebtedness of PEF or its parent company (PEP). As discussed in Note 1, the pending maturity of PEP’s term loan payable to BPP Holdco, LLC, due November 10, 2021, is indebtedness held by the parent holding company, resulted in management’s conclusion that substantial doubt exists regarding the Partnership’s ability to continue as a going concern. Given that the emphasis of matter regarding going concern within the independent auditors’ report associated with these financial statements is the result of this pending maturity, management concluded such matter does not result in an event of default.
Interest on this term loan is payable quarterly and is at a rate equal to the LIBOR plus 7.5%.
Deferred loan cost of $2.0 million and $2.5 million (net of $1.4 million and $0.8 million in amortization) is recorded as an offset to long-term debt for the year ended December 31, 2020 and 2019, respectively.
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NOTE 6. LINE OF CREDIT AND TERM LOAN FACILITIES - CONTINUED
Term loan agreements - continued
HPS Investment Partners Term Loan - continued
As part of this credit facility, the Partnership created PEF as a subsidiary of PEP who is the borrower under this agreement.
Blackstone Term Loan
On July 16, 2016, in connection with the Blackstone recapitalization of the Partnership, the Partnership entered into an agreement with BPP Holdco LLC, the Series B Preferred Unit holder, for a term loan in the amount of $130 million, with an original maturity date of January 7, 2020. Proceeds from this second lien facility were used to retire a previous credit facility. Three limited partners of the Partnership have provided guarantees of collection totaling $52.5 million, including a limited partner of the Partnership controlled by the Partnership’s Chairman of the Board, which has provided a guarantee of collection totaling $47.9 million.
On March 21, 2019, this agreement was amended to extend the maturity date of April 7, 2020.
On March 25, 2020, this agreement was amended to extend the maturity date to July 7, 2020 and to amend the requirement of an audit opinion that does not contain a going concern emphasis of matter paragraph to allow for any “going concern” qualification resulting from the occurrence of pending maturity date of the Partnership’s indebtedness. Given that the emphasis of matter regarding going concern within the independent auditors’ report associated with these financial statements is the result of this pending maturity, management concluded such matter does not result in an event of default.
On September 23, 2020, the agreement was amended to extend the maturity date to November 10, 2021.
Interest on this term loan is payable quarterly at an interest rate equal to LIBOR plus 12.0%, subject to a 1% floor.
The term loan agreement contains various covenants pertaining to the financial condition of the Partnership. 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 at December 31, 2019. For purposes of the covenant test, total debt is the debt at PEP of $130 million and PEF of $150 million as well as the outstanding amount drawn on the revolver at PRD.
Capitalized loan cost of $0 and $0.1 million (net of $4.3 million and $3.9 million in amortization) are presented as an offset to long-term debt for the year ended December 31, 2020 and 2019, respectively.
NOTE 7. REDEEMABLE SERIES B PREFERRED UNITS
On July 1, 2016, the Limited Partnership Agreement (“LPA”) was amended and restated to allow for the issuance of up to 300,000 Series B Preferred Units with a par value of $1,000 each. The Series B Preferred Unitholders are entitled to receive a distribution of 13.5% compounded interest and payable quarterly on April 1, July 1, October 1, and December 31. The distribution is prior and in preference to any declaration or payment of distributions to Series A Preferred Unit holders and any other classes of equity in the Partnership. The distribution is generally to be paid in additional Series B Preferred Units. At the discretion of the Managing General Partner, however, the distribution may be paid in cash for up to 50% of the amount to be distributed.
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NOTE 7. REDEEMABLE SERIES B PREFERRED UNITS - CONTINUED
The activity and balance of the Redeemable Series B Preferred Units are as follows (in thousands):
Balance as of January 1, 2019$391,671 
Accretion of discount on issuance1,409 
Interest earned57,923 
Balance as of December 31, 2019$451,003 
Accretion of discount on issuance1,411 
Interest earned66,148 
Balance as of December 31, 2020$518,562 
NOTE 8. PARTNERS’ EQUITY
The limited partners’ equity consists of two general classes: (1) Series A Preferred Units, and “Common Units,” which are composed of several sub-classes described below.
The Common Units include the initial Class B founding limited partners and Class A limited partners admitted to the Partnership in 2001. In 2013, the Partnership amended and restated its LPA to provide for additional limited partner interests, including the Series A Preferred Units issued to Whittier, and three new sub-classes of Common Units (Class C, Class D, and Class E), made available for issuance as management incentive units. All issued Class C Units were redeemed or converted to Class B Units in February 2016. The Board issued and granted Class D Units to certain outside Board members, which remain issued and outstanding. There are no outstanding Class E Units.
In July 2016, in connection with the Blackstone financing, the Partnership amended and restated its LPA to provide for the Redeemable Series B Preferred Units (discussed in note 7) and their associated warrants (Class F Common Units), as well as a new class of management incentive units (Class G Common Units).
Under the Third Amended and Restated LPA Agreement, the following order of distributions will occur upon a liquidation event:
First, to the Redeemable Series B Preferred Units until satisfied.
Second, $100 million to the Legacy Unitholders, which consist of the Series A Preferred, Class A and Class B Common Unit holders in order of preference.
Lastly, proceeds will be split 55% to the Series F Common Units (and Series G Common Units once certain thresholds are met) and 45% to the Legacy Unitholders.
The Series A Preferred Units are non-voting, perpetual limited partnership units, convertible to Class A-1 Common Units, and are entitled to a priority distribution of 8% per annum, cumulative and non- compounding with no current payment requirement. This payment is reflected as a reclass within the statement of changes in partners’ equity as a deemed distribution. Series A Preferred Units were purchased on November 1, 2013, November 15, 2014, and July 1, 2015.
The amount of cumulative deemed distributions to Series A Preferred Units that have not been paid as of December 31, 2020, was $72.7 million; as a result, the Series A Preferred Unit holder’s total investment in the Partnership, plus its deemed distribution, equals $227.2 million as of December 31, 2020.

20


NOTE 8. PARTNERS’ EQUITY - CONTINUED
As previously noted, the Class F and Class G Common Units represent equity interests in the Partnership created in connection with the 2016 recapitalization. The Class F Common Units were issued to the holder of the Series B Preferred Unit holders and participate in profits once the Series B Preferred distributions have been satisfied and $100.0 million of distributions have been made to legacy unitholders. Accordingly, the value of these Class F Common Units at issuance was de minimis.
Class G Common Units are issued as management incentive units and are considered “profits interests” for tax purposes. The Class Common G Units receive distributions of partnership profits after certain hurdles are met with respect to the other Preferred and Common Units. Accordingly, the value of these Class G Common Units at issuance was also de minimis. The following table details the activity and number of Class G Common Units outstanding:
Units outstanding as of January 1, 201979,559 
Units granted during 20197,621 
Forfeitures— 
Units outstanding as of December 31, 201987,180 
Units granted during 2020— 
Forfeitures— 
Units outstanding as of December 31, 202087,180 
The following summarizes the limited partner units issued and outstanding as of December 31, 2020:
Partnership ClassDescription
Units
Outstanding
Preferred Limited Partners
Series A PreferredNon-voting, perpetual, 8% priority distribution, convertible to A-1 Common.65,999 
Series B PreferredNon-voting, 13.5% cumulative and compounding quarterly. Distribution paid in additional Series B preferred units.518,562 
Common Limited Partners
Class AVoting, 9% compounded preferred return, subject to 25% reversion to Class B after an 19% internal rate of return (IRR).6,667 
Class A-1Issued upon conversion by Series a preferred holder, voting, subject to 30% reversion to Class E after a 20% IRR.— 
Class BFounders and management units, voting108,929 
Class CManagement profit participation units, voting. 10,000 units are authorized with 0 outstanding.— 
Class DDirector units, profit participation units contingent upon Series A Preferred conversion to Class A-1 Common2,570 
Class EManagement incentive profit participation units, holders of the 30% reversionary interest from Class A-1 Common. 10,000 units are authorized with 0 outstanding.— 
Class F
Participates in profits of the partnership once Series
B Preferred Units are retired and certain other hurdles are met.
518,562 
Class GManagement incentive profit participation units.87,180 
21


NOTE 9. MID-TERM INCENTIVE PLAN
In 2020, the Board of Directors established the Mid Term Incentive Plan (“MTIP”) as an incentive program for the Partnership’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 Partnership 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.
NOTE 10. RELATED PARTY TRANSACTIONS
As stated in Note 3, the Partnership, through SFS purchased the Pecos Property from the Chairman of the Board for $2.1 million. Prior to the closing of that transaction, the Partnership had a triple net lease agreement for the use of the property as a field office. Lease payments totaling $0.1 million and $0.2 million were paid to the owner in 2020 and 2019, respectively.
The Partnership has an affiliate receivable balance due from PEC in the amount of $0.1 million and $0.1 million as of December 31, 2020 and 2019, respectively.
The Partnership’s Blackstone Term Loan is payable to BPP Holdco LLC and the Whittier Trust, both Series B Preferred Unit holders. Additionally, as stated in Note 6, there is a personal guarantee of this note by an entity controlled by the Chairman of the Board. Interest paid related to this debt instrument was $17.6 million ($16.4 million to BPP Holdco and $1.2 million to the Whittier Trust) and $19.1 million ($17.8 million to BPP Holdco and $1.3 million to the Whittier Trust) for the years ended December 31, 2020 and 2019, respectively.
The Partnership entered into an agreement with EagleClaw Midstream (“EagleClaw”) on October 1, 2017 to gather and market gas produced pursuant to a gathering and acreage dedication agreement. The Partnership received $15.8 million and $13.9 million in gross sales during the periods ending December 31, 2020 and 2019, respectively. The Partnership and EagleClaw have the same controlling shareholder, however, there is no common management or shared operations between the two entities outside of the gathering agreement described above.
22


NOTE 10. RELATED PARTY TRANSACTIONS - CONTINUED
BPP Energy Partners LLC
The Partnership has shareholders and management in common with BPP Energy Partners LLC (“BPP”), a company formed to acquire oil-and-gas leases and assets within PEP’s operating area. In connection with the formation of BPP, the board approved a shared service agreement between the two companies so that all operations of BPP are conducted by POC and the cost of shared resources (including technology, office space and personnel) are reimbursed to POC by BPP at a rate of cost plus 2%. Additionally, BPP holds non-operated working interest in wells currently being drilled by PEP. Accordingly, PEP is responsible for distributing BPP’s share of revenue and invoicing for the related share of capital and lease operating expenses in accordance with the ownership held by BPP.
On July 11, 2018, BPP purchased approximately 22% of SFS from PRD. An incremental 6.23% and 1.75% was purchased on May 1, 2019 and July 2, 2019, respectively. As of the balance sheet date, BPP has purchased 30% equity ownership in SFS (see details of this purchase in Note 3).
Below represents the balances and activity between BPP and POC (in thousands):
20202019
BPP payable to POC$1,610 $9,906 
Revenue paid to BPP by POC$50,240 $41,723 
Capital and lease operating expenses paid to POC for joint interest billings$43,241 $115,845 
General and administrative expenses reimbursement to POC$4,172 $3,239 
BPP had $19.4 million and $0 of unapplied prepaid capital expenditures deposited with PRD and recorded in other current liabilities as of December 31, 2020 and 2019, respectively.
During the year ended December 31, 2019, the Partnership acquired a lease for 203 acres in the amount of $2.0 million (BPP cost basis) from BPP.
Rock Ridge Royalty Company LLC
The Partnership has shareholders and management in common with Rock Ridge Royalty Company LLC (“Rock Ridge”), a Delaware limited liability company formed in late 2016 to acquire and hold mineral and royalty interests in the Delaware Basin. Resources of the Partnership will be utilized in the management and operations of Rock Ridge. These resources include technology, office space and personnel employed by POC. The cost of these resources will be reimbursed by Rock Ridge based on the time allocated by employees to their work on Rock Ridge as well as actual costs incurred by POC and the Partnership. Further, PRD leases certain acreage blocks for future development from Rock Ridge. Lease bonuses are made based on a market analysis and at a price agreed to by the respective boards. As a result, PRD is an operator of certain Rock Ridge properties and pays Rock Ridge its respective royalty for hydrocarbons produced.
Below represents the balances and activity during the respective periods (in thousands):
20202019
Rock Ridge payable to POC$158 $345 
Cash lease bonuses paid by PRD$47 $— 
Revenue paid to Rock Ridge by POC$5,930 $3,738 
General and administrative expenses reimbursement to POC$2,487 $3,010 
23


NOTE 10. RELATED PARTY TRANSACTIONS - CONTINUED
Jetta Permian L.P.
On May 8, 2020, POC entered into a comprehensive management services agreement (“MSA”) with an effective date of June 1, 2020 to manage Jetta Permian, L.P. (“Jetta”), which has shareholders in common with the Partnership. Under this MSA, certain POC officers will serve as officers of Jetta and POC employees will operate and maintain all of Jetta’s oil and gas properties, provide back office support and reporting requested by the board and required by Jetta’s bank agreements. For these services, POC will receive a monthly fee of $30,000 plus an amount of $900 per operated well and a drilling overhead fee of $9,000 per well per month prorated for drilling days to be paid in the month when wells are drilled. All out-of-pocket expenses paid by POC will be reimbursed by Jetta.
As of December 31, 2020, Jetta has a payable due to POC in the amount of $0.1 million.
NOTE 11. COMMITMENTS AND CONTINGENCIES
The Partnership leases office facilities for its corporate office and field operations under non- cancellable operating leases. Expenses associated with these operating leases were approximately $0.8 million and $1.0 million for the years ended December 31, 2020 and 2019, respectively. Future minimum lease commitments under non-cancellable operating leases are as follows (in thousands):
2021$1,738 
2022$1,018 
2023$845 
2024$600 
Thereafter$1,550 
The Partnership’s operations are subject to all the operational and environmental risks normally associated with the crude oil and natural gas industry. Additionally, the Partnership may become involved from time to time in litigation on various matters which are routine to the conduct of its business.
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 the financial markets. These events, in addition to disruptions in the demand for oil combined with pressures on the global supply-demand balance for oil, resulted in significant volatility in oil prices during 2020. The effects of the COVID-19 pandemic negatively impacted the Partnership’s results of operations and led to a reduction in capital activities. The impact of these events on the financial performance of the Partnership’s long-term operations is uncertain, including the duration of the COVID-19 pandemic and long-term effects on global oil demand. The financial statements have been prepared using values and information currently available to the Partnership.
NOTE 12. SUBSEQUENT EVENTS
On January 8, 2021, the Partnership and BPP Acquisition LLC, a subsidiary of BPP Energy Partners LLC, 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 Partnership received total consideration of $2.5 million in exchange for interests in certain properties and future technical consulting services in the joint development area.
24


NOTE 12. SUBSEQUENT EVENTS - CONTINUED
Subsequent events have been evaluated through March 31, 2021, the date on which the consolidated financial statements were available to be issued.
25

















SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

26


Geographic Area of Operation
The Partnership’s oil and natural gas reserves are located within the continental United States and concentrated in the Delaware Basin of Texas.
Capitalized Oil and Natural Gas Costs
Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion and amortization are as follows (in thousands):
December 31, 2020December 31, 2019
Oil and gas properties
Proved oil and gas properties$1,362,631 $1,272,991 
Accumulated depletion and impairment(1,089,464)(542,743)
Net oil and gas properties capitalized$273,167 $730,248 
Costs Incurred in Oil and Natural Gas Activities
Costs incurred in oil and natural gas property acquisition, exploration and development activities are as follows (in thousands):
December 31, 2020December 31, 2019
Acquisition costs
Proved oil and gas properties$14 $7 
Unproved oil and gas properties3,237 3,135 
Development costs88,801 249,001 
Exploration costs— 789 
Total costs incurred$92,052 $252,932 
Results of Operations from Oil and Natural Gas Producing Activities
The following sets forth the revenues and expenses related to the production and sale of oil and natural gas (in thousands). It does not include any realized hedges, interest costs or general and administrative costs and, therefore, is not necessarily indicative of the net operating results of the Partnership’s oil and natural gas operations.
December 31, 2020December 31, 2019
Oil and natural gas sales$150,403 $213,106 
Production costs(55,670)(41,382)
Depletion(88,900)(76,162)
Impairment of oil and gas properties(457,502)— 
Results of operations from oil and natural gas producing activities($451,669)$95,562 
The reserves as of December 31, 2020 and 2019 presented below were prepared by independent petroleum engineers. The calculation and analysis of interim changes in proved reserves were prepared by the Partnership. Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. The reserves are located in the Delaware Basin of Texas.
The following tables set forth estimated net quantities of the Partnership’s estimated proved reserves, projected future cash inflows, and future production and development costs and are prepared in accordance with guidelines established by the SEC. Accordingly, the reserve estimates are based upon existing economic and operating conditions. For estimates of proved reserves, the average spot prices are determined based upon the 12-month unweighted average of the first day of the month prices adjusted by applying price and cost basis differentials, including transportation and
27


quality, and are then applied to the period-end estimated quantities of oil, natural gas and natural gas liquids (“NGL”) to be produced in the future. Future net cash flows are reduced to present value amounts by applying a ten percent annual discount factor.
The assumptions used to compute the standardized measure are those prescribed by GAAP. These assumptions do not necessarily reflect management’s expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these reserve quantity estimates are the basis for the valuation process. Reserve estimates are inherently imprecise and estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available.
Analysis of Changes in Proved Reserves
The following table sets forth information regarding the Partnership’s net ownership interest in estimated quantities of proved developed and undeveloped oil and natural gas quantities and the changes therein for each of the periods presented:
OilNatural GasNGLsTotal
(MBbls)(MMcf)(MBbls)(MBOE)
Balance, January 1, 201953,691 61,649 13,160 77,126 
Revisions(11,462)(2,374)(1,972)(13,830)
Extensions32,720 41,956 7,622 47,335 
Divestitures of reserves(29)(33)(8)(42)
Production(3,771)(4,015)(738)(5,178)
Balance, December 31, 201971,149 97,183 18,064 105,411 
Revisions(26,722)(26,490)(5,010)(36,147)
Extensions14,225 23,402 4,324 22,449 
Divestitures of reserves(53)(97)(21)(90)
Production(3,789)(5,669)(1,019)(5,753)
Balance, December 31, 202054,810 88,329 16,338 85,870 
OilNatural GasNGLsTotal
Proved developed and undeveloped reserves:(MBbls)(MMcf)(MBbls)(MBOE)
Developed as of December 31, 201810,818 14,166 3,177 16,356 
Undeveloped as of December 31, 201842,873 47,483 9,983 60,770 
Balance at December 31, 201853,691 61,649 13,160 77,126 
Developed as of December 31, 201916,616 24,717 4,529 25,265 
Undeveloped as of December 31, 201954,533 72,466 13,535 80,146 
Balance at December 31, 201971,149 97,183 18,064 105,411 
Developed as of December 31, 202012,958 24,419 4,509 21,537 
Undeveloped as of December 31, 202041,852 63,910 11,829 64,333 
Balance at December 31, 202054,810 88,329 16,338 85,870 
Revisions to previous estimates of proved reserves, either upward or downward, are a result of updated information obtained in the reporting period, including operator drilling activity and production history or changes in economic factors such as commodity prices, operating and development costs.
28


During the year ended December 31, 2020, the Partnership’s extensions and discoveries of 22,449 MBOE resulted primarily from conversions of non-proved and contingent resources to proved due to drilling activity. The Partnership divested 2.3 net producing wells in Reeves County, Texas resulting in negative revisions of 90 MBOE. In addition, the Partnership negatively revised previous estimates by 36,147 MBOE due to the following:
Downgrade of 25,280 MBOE of proved reserves to non-proved due to the decrease in drilling activity in 2020 resulting in development moving outside of the five-year development window,
Negative revision of 6,252 MBOE due to downward movement in SEC pricing,
Increase of 4,098 MBOE due to decreases in gas and NGL processing and basis differentials, and
Negative revision of 8,713 MBOE attributed to downward revisions of estimated ultimate recovery, changes in operating and development costs, and adjustments to well spacing and development timing.
During the year ended December 31, 2019, the Partnership’s extensions and discoveries of 47,335 MBOE resulted primarily from conversions of non-proved and contingent resources to proved due to drilling activity. The Partnership divested 2.0 net producing wells in Reeves County, Texas resulting in negative revisions of 42 MBOE. In addition, the Partnership negatively revised previous estimates by 13,830 MBOE due to the following:
Removal of 91 MBOE due to plugging and abandonment of 6 wells,
Negative revision of 1,826 MBOE due to downward movement in SEC pricing,
Decrease of 4,008 MBOE due to increases in gas and NGL processing and basis differentials, and
Negative revision of 7,905 MBOE attributed downward revisions of estimated ultimate recovery, changes in operating and development costs, and adjustments to well spacing and development timing.
Standardized Measure of Oil and Gas
The standardized measure and projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to the Partnership. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary. Our calculations of the standardized measure of discounted future net cash flows and the related changes therein do not include the effect of estimated federal income tax expenses because federal income taxes associated with POC, a C-corporation for federal and state tax purposes and a subsidiary of the Partnership, are not material. All other subsidiaries of the Partnership are pass-through entities. The Partnership is subject to certain state-based taxes; however, these amounts are not material.
As of December 31, 2020, the reserves are comprised of 64% crude oil, 17% natural gas and 19% NGL on an energy equivalent basis.
The values for the December 31, 2020 and 2019 proved reserves were derived based on prices presented in the table below. Crude oil pricing was based on the West Texas Intermediate (“WTI”) price; NGL pricing was 21% of WTI for 2020 and 33% of WTI for 2019; natural gas pricing was based on the Henry Hub price. All prices have been adjusted for transportation, quality and basis differentials.
OilNatural GasNGLs
($/Bbl)($/Mcf)($/Bbl)
December 31, 2020 (Average)36.18-0.0058.34
December 31, 2019 (Average)46.51-0.15418.14
29


The following summary sets forth the future net cash flows related to proved oil and natural gas reserves based on the standardized measure prescribed in ASC Topic 932 (in thousands):
December 31, 2020December 31, 2019
Future oil and natural gas sales$2,118,782 $3,621,804 
Future production costs(881,455)(1,156,192)
Future development costs(619,403)(808,903)
Future net cash flows617,924 1,656,709 
10% annual discount(329,785)(823,308)
Standardized measure of discounted future net cash flows$288,139 $833,401 
The principal sources of change in the standardized measure of discounted future net cash flows are (in thousands):
Year Ended December 31,
20202019
Standardized measure, beginning of year$833,401 $794,839 
Net change in prices and production costs(179,308)59,012 
Changes in future development costs382,499 262,594 
Oil and gas sales, net of production costs(94,733)(171,724)
Extensions and discoveries61,236 378,088 
Divestitures of reserves(222)(431)
Revisions of previous quantity estimates(226,579)(154,147)
Development costs incurred during the period35,167 127,944 
Accretion of discount83,340 79,484 
Changes in timing and other(606,662)(542,258)
Standardized measure, end of year$288,139 $833,401 
30
Document
Exhibit 99.2



PRIMEXX ENERGY PARTNERS, LTD.
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 Partners’ Equity (Deficit)
Condensed Consolidated Statements of Cash Flows
Notes to the Unaudited Condensed Consolidated Financial Statements




PRIMEXX ENERGY PARTNERS, LTD. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
UNAUDITED
(in thousands)
September 30, 2021December 31, 2020
Assets
Current Assets
Cash and cash equivalents$11,724 $7,253 
Trade accounts receivable33,661 17,028 
Accounts receivable - affiliate6,993 1,350 
Prepaids and other1,442 415 
Commodity derivatives1,712 14,263 
Total current assets55,532 40,309 
Property, plant and equipment, net:
Oil and gas properties, full cost method of accounting361,000 273,167 
Other property and equipment, net83,510 90,953 
Commodity derivatives6,161 9,078 
Loan origination cost, net1,870 2,468 
Prepaids and other1,136 1,059 
Total Assets$509,209 $417,034 
Liabilities, Preferred Units and Partners’ Equity
Current Liabilities
Accounts payable$19,801 $1,629 
Oil and gas payable34,976 17,421 
Commodity derivatives39,477 974 
Other current liabilities40,632 54,319 
Current portion of deferred revenue2,797 2,625 
Current portion of long-term debt, net129,999 129,994 
Total current liabilities267,682 206,962 
Line of credit148,500 87,500 
Term loans, net148,389 147,933 
Deferred revenue22,531 24,500 
Commodity derivatives29,707 4,775 
Other long-term liabilities308 295 
Asset retirement obligation5,327 5,327 
Deferred tax liability46 46 
Total Liabilities622,490 477,338 
Commitments and contingencies (Note 10)
Redeemable Series B Preferred Units, net575,325 518,562 
Equity
Partners’ Equity (deficit)(709,606)(599,205)
Noncontrolling interest21,000 20,339 
Total (Deficit)(688,606)(578,866)
Total Liabilities, Preferred Units and Partners’ Equity$509,209 $417,034 

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



PRIMEXX ENERGY PARTNERS, LTD. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
UNAUDITED
(in thousands)

Nine-Months Ended September 30
20212020
Revenues
Oil sales$154,309 $109,594 
Natural gas sales28,858 5,878 
Field service revenue9,985 6,319 
(Loss) gain on derivative instruments, net(101,218)111,877 
Total revenues91,934 233,668 
Costs and expenses
Lease operating expenses35,709 33,255 
Repairs7,121 3,347 
Production taxes8,642 5,371 
Transportation and marketing739 897 
Field service expenses9,474 10,878 
Depreciation, depletion and amortization51,073 79,771 
Impairment of oil and gas properties— 325,683 
General and administrative3,964 5,870 
Total operating expenses116,722 465,072 
(Loss) from operations(24,788)(231,404)
Other income (expense)
Other income2,174 2,210 
Interest expense(27,346)(30,600)
Total other income (expense)(25,172)(28,390)
(Loss) before income taxes(49,960)(259,794)
Income tax expense
Texas margin tax expense40 — 
Total income tax expense40 — 
Net (loss)(50,000)(259,794)
Net (gain) loss attributable to noncontrolling interest(4,485)959 
Series B preferred unit distribution(55,705)(48,780)
Net (loss) attributable to other partners($110,190)($307,615)


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



PRIMEXX ENERGY PARTNERS, LTD. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ EQUITY (DEFICIT)
UNAUDITED
(in thousands)

General PartnerSeries A
Preferred
Common
Units
Noncontrolling
Interest
Total
Equity
Balance, December 31, 2020($76)($160,932)($438,197)$20,339 ($578,866)
Series A Preferred Deemed Distribution— 9,270 (9,270)— — 
Net gain attributable to noncontrolling interest— — — 4,485 4,485 
Distribution to minority interest owners made by SFS— — — (4,035)(4,035)
Transfer of property by SFS— (99)(112)211 — 
Net (loss) attributable to other partners— (51,667)(58,523)— (110,190)
Balance, September 30, 2021($76)($203,428)($506,102)$21,000 ($688,606)
General PartnerSeries A
Preferred
Common
Units
Noncontrolling
Interest
Total
Equity
Balance, December 31, 2019($76)$55,984 ($166,142)$23,169 ($87,065)
Series A Preferred Deemed Distribution— 9,270 (9,270)— — 
Net (loss) attributable to noncontrolling interest— — — (959)(959)
Purchase of noncontrolling interest by SFS— 67 75 (2,281)(2,139)
Net (loss) attributable to other partners— (144,239)(163,376)— (307,615)
Balance, September 30, 2020($76)($78,918)($338,713)$19,929 ($397,778)


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


PRIMEXX ENERGY PARTNERS, LTD. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
UNAUDITED
(in thousands)

Nine-Months Ended September 30
Cash flows from operating activities20212020
Net (loss)($50,000)($259,794)
Adjustments to reconcile net (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization51,073 79,771 
Impairment of oil and gas properties— 325,683 
Deferred loan cost amortization1,138 1,464 
Deferred revenue amortization(2,078)(1,969)
Gain on sale of property - net— 
Accretion of discount on preferred unit issuance1,058 1,058 
Unrealized loss (gain) on derivative instruments78,904 (62,933)
Changes in operating assets and liabilities:
Trade accounts receivable(16,633)18,064 
Accounts receivable - affiliate(5,643)10,629 
Prepaid and other assets(1,085)(762)
Accounts payable7,899 (15,697)
Oil and gas payable17,556 (8,911)
Accrued liabilities and other(34,832)(12,280)
Deferred revenue282 — 
Net cash provided by operating activities47,640 74,323 
Cash flows from investing activities
Additions to oil and gas properties(97,220)(67,139)
Proceeds from sale of oil and gas properties2,188 — 
Additions to other property(5,001)(8,109)
Net cash (used in) investing activities(100,033)(75,248)
Cash flows from financing activities
Distribution to minority interest owners made by SFS(4,035)— 
Purchase of Pecos Property by SFS from noncontrolling interest— (2,139)
Proceeds from line of credit109,000 40,500 
Repayments of line of credit(48,000)(53,500)
Capitalized loan cost(101)(507)
Net cash provided by (used in) financing activities56,864 (15,646)
Net change in cash and cash equivalents4,471 (16,571)
Cash and cash equivalents, beginning of period7,253 22,501 
Cash and cash equivalents, end of period$11,724 $5,930 
Supplemental cash disclosures:
Property additions included in accrued liabilities$31,431 $2,063 
Cash paid for interest$25,546 $28,668 
Non cash financing - Redeemable Series B Preferred Units$55,705 $48,780 

The accompanying notes are an integral part of these condensed consolidated financial statements.
6


PRIMEXX ENERGY PARTNERS AND SUBSIDARIES
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED
FINANCIAL STATEMENTS
NOTE 1. ORGANIZATION
Primexx Energy Partners, Ltd. (“PEP”), a Texas Limited Partnership, was formed on July 1, 2000, and is engaged in the acquisition, development, production, exploration and sale of crude oil and natural gas properties located primarily in Reeves County Texas.
On July 1, 2016, PEP reorganized and obtained additional investment in the form of Redeemable Series B Preferred units through funds controlled by The Blackstone Group (“Blackstone”). In addition to this investment, Blackstone also obtained a 55% controlling interest in Primexx Energy Corporation (“PEC”), a Texas corporation, and the sole general partner of PEP.
Principles of Consolidation
These condensed consolidated financial statements include the accounts of Primexx Energy Partners, Ltd. and its subsidiaries: (i) Primexx Energy Finance (“PEF”), (ii) Primexx Resource Development (“PRD”), (iii) Primexx Operating Corporation (“POC”), (iv), and Saragosa Field Services (“SFS”) (collectively referred to as “the Partnership”). Intercompany transactions and balances have been eliminated in consolidation.
On July 11, 2018, the Partnership sold approximately 22% of its interest in SFS to a subsidiary of BPP Energy Partners LLC (“BPP”), an affiliated entity (see Note 3 and Note 9). On May 1, 2019 and July 2, 2019, the Partnership sold an additional 6.23% and 1.75%, respectively, of its interest in SFS to BPP. Total interest sold through the balance sheet date is 30%. Given the Partnership’s majority interest and its control of the entity, SFS remains a consolidated entity with the minority shareholder’s interest shown as noncontrolling interest in the condensed consolidated financial statements.
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. All dollar amounts in the financial statements and tables in the notes are stated in thousands of U.S. dollars unless otherwise indicated. 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 partners’ 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 consolidated financial statements.
7


NOTE 2. SIGNIFICANT ACCOUNTING POLICIES - CONTINUED
Going Concern
The accompanying condensed consolidated financial statements are prepared in accordance with generally accepted accounting principles applicable to a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business.
Management evaluates conditions and events that are relevant to the Partnership’s ability to meet its obligations as they become due within one year after the date that the condensed consolidated financial statements are issued. The Partnership has an unsecured term loan payable to BPP Holdco LLC, a related party, with an outstanding principal balance of $130 million which was set to mature on November 10, 2021. As a result of the Callon Divestiture (see Note 11), the maturity date of the term loan was extended to November 30, 2021. If this note is found to be in default, the newly issued note by BPP Holdco LLC for $25 million (see Note 11) will have an accelerated maturity. Management has considered existing cash on hand and available liquidity, and concluded that the Partnership will not have sufficient liquidity to repay the term loan at maturity. This condition raises substantial doubt about the Partnership’s ability to continue as a going concern.
In response to these conditions, management’s plan includes selling Callon shares to repay the term loan and its remaining obligations as they become due. However, the shares received as consideration are restricted until after the extended maturity date. As management’s plans are not within the Partnership’s control, these plans cannot be considered probable of occurring as of the date the condensed consolidated financial statements are available for issuance. As a result, the Partnership has concluded that management’s plans do not alleviate substantial doubt about the Partnership’s ability to continue as a going concern.
The condensed consolidated financial statements do not include any adjustments relating to the recoverability and classification of recorded asset amounts or the amounts and classification of liabilities that might result from the outcome of this uncertainty.
Use of Estimates
The preparation of the condensed consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (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 condensed consolidated 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, derivative financial instruments, asset retirement obligations, and legal and environmental risks and exposures.
Oil and Gas Properties
The Partnership 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.

8


NOTE 2. SIGNIFICANT ACCOUNTING POLICIES - CONTINUED
Oil and Gas Properties - continued
The Partnership 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 Partnership’s proved property impairment assessment as of September 30, 2020, the Partnership recorded a $325.7 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. We determine the amount of costs to transfer from unproved properties based on our estimate of the potential drilling locations and potential reserves associated with those properties. 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 cost 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.
Other Property and Equipment
Other property and equipment includes furniture and fixtures, computer equipment, software, transportation equipment, and field service equipment consisting of gas gathering, gas processing and water management facilities. Property and equipment are recorded at historical cost and depreciated using the straight-line method over their estimated useful lives ranging from 3 to 39 years.
The Partnership assesses the carrying amount of this equipment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If the carrying amount exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset is recognized. There was no such impairment for the periods presented.
Derivative Activity
The Partnership 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.
9


NOTE 2. SIGNIFICANT ACCOUNTING POLICIES - CONTINUED
Derivative Activity - continued
The Partnership reports the fair value of derivatives on the consolidated balance sheets in commodity derivative assets or liabilities as either current or noncurrent. The Partnership determines the current and noncurrent classification based on the timing of expected future cash flows of the individual trades. The Partnership reports these on a gross basis by counterparty.
The Partnership’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.
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.
Revenue Recognition
The Partnership enters into contracts with customers to sell its oil and natural gas production. Revenue on these contracts is recognized in accordance with the five-step revenue recognition model. Specifically, revenue is recognized when the Partnership’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 Partnership 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. At September 30, 2021 and December 31, 2020, the Partnership had receivables related to contracts with customers of $30.1 million and $12.8 million, respectively.
10


NOTE 2. SIGNIFICANT ACCOUNTING POLICIES - CONTINUED
Revenue Recognition - continued
Oil Contracts - The majority of the Partnership’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 Partnership’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 Partnership’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 Partnership’s consolidated statements of operations.
The Partnership 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.
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$1,488,968 $1,362,631 
Accumulated depreciation, depletion and amortization and impairment(1,127,968)(1,089,464)
Total net oil and gas properties361,000 273,167 

Other property and equipment:
Other property and equipment:
Office and equipment5,261 4,013 
Field service assets135,595 131,872 
Accumulated depreciation(57,346)(44,932)
Total net other property and equipment83,510 90,953 
Total net property, plant and equipment$444,510 $364,120 
Field Service Assets
SFS is a controlled subsidiary of the Partnership that owns the company’s field services assets in Reeves County which include gas gathering, water management and other oil field service assets. Financial information for this entity can be found in the Supplemental Consolidating Schedules.
11


NOTE 3. PROPERTY - CONTINUED
Acquisitions and Divestitures
On May 18, 2018, PRD and SFS entered into an agreement with Oryx Southern Delaware Holdings, LLC (“Oryx”). This agreement allowed for the construction of a gathering system to collect the Partnership’s produced oil and provide firm marketing and shipping arrangements for the product. Further as a part of this agreement, SFS had the first right and option to purchase on or before December 31, 2019 all of the gathering system and all rights and interest in the crude oil gathering agreement between the Partnership and Oryx for the net present value of the construction cost plus six percent. Additionally, if the call was exercised, the Partnership had the ability to put the asset to Oryx or participate through tag-along rights in the event Oryx completed a sale of its assets.
On April 2, 2019, SFS received notice that Oryx had entered into a Purchase and Sale Agreement (“PSA”) which constituted an exit event under the agreement. On April 18, 2019, SFS exercised both its call and put rights and settled the transaction with Oryx for a net amount of $31.5 million on May 22, 2019. The Partnership 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. The $31.5 million earned from this transaction was distributed to PRD and BPP in proportion to their equity ownership.
On May 1 and July 2, 2019, the Partnership completed the sale of an additional 6.23% and 1.75% of its equity interest in SFS to BPP for a total sales price of $7.2 million and $1.5 million, respectively. These transactions gave BPP their maximum ownership of 30% allowed under the sales agreement reached in 2018.
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 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, the Partnership 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.
Pecos Office Building
On September 9, 2020, SFS exercised its option on behalf of the Partnership 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 Partnership’s Chief Executive Officer) for a total payment of $2.1 million. Prior to the purchase, the Partnership had a lease in place with the owner and utilized the office for field operations. The Pecos Property was previously accounted for as a variable interest entity (“VIE”) and consolidated within the Partnership’s financial statements because the property owner held the option to force a purchase of the property by the Partnership, and the Partnership had the option to force a sale of the property under certain circumstances. Given the related party nature of the transaction and the VIE guidance within GAAP, there is no step-up in basis of the Pecos Property and the excess cash paid over the book value is recorded as a reduction in the equity of SFS. As a result of the transaction, the entire purchase price is a reduction in equity and a financing cash outflow to acquire all of the equity interest in the previously consolidated VIE which is dissolved.
12


NOTE 3. PROPERTY - CONTINUED
Grey Rock Joint Development Agreement
On January 8, 2021, the Partnership and BPP Acquisition LLC, a subsidiary of BPP Energy Partners LLC, 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 Partnership received total consideration of $2.2 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, the Partnership 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 $0.3 million were deferred as a liability and amortized over the agreement period as other income.
Callon Divestiture
On August 3, 2021, the Partnership and BPP (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. DERIVATIVE INSTRUMENTS
The Partnership engages in price risk management activities. These activities are intended to manage the Partnership’s exposure to fluctuations in commodity prices for crude oil and natural gas. The Partnership 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.
Natural gas and crude oil derivatives settle against the average of the prompt month NYMEX future prices for natural gas and West Texas Intermediate crude oil.
The fair values of commodity derivatives were as follows (in thousands):
September 30, 2021December 31, 2020
Commodity derivative assets
Current portion$1,712 $14,263 
Long-term portion6,161 9,078 
7,873 23,341 
Commodity derivative liabilities
Current portion39,477 974 
Long-term portion29,707 4,775 
69,184 5,749 
Net commodity derivatives($61,311)$17,592 
13


NOTE 4. DERIVATIVE INSTRUMENTS - CONTINUED
The following presents the results of the Partnership’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($20,693)$48,944 
Natural gas derivatives(1,621)— 
Total realized (loss) gain($22,314)$48,944 
Unrealized (loss) gain
Oil derivatives($74,088)$64,723 
Natural gas derivatives(4,816)(1,790)
Total unrealized (loss) gain($78,904)$62,933 
(Loss) gain on derivative instruments, net($101,218)$111,877 
The Partnership had the following outstanding open crude oil and natural gas positions as of September 30, 2021:
Expirations
2021202220232024
Oil Swaps:
Notional volume (bbl)642,000 1,167,200 — — 
Weighted average swap price$53.01 $53.44 $50.68 $— $— 
Mid-Cush Differential (Basis) Swap:
Notional volume (bbl)642,000 1,606,300 633,400 317,400 
Weighted average swap price$1.01 $0.93 $0.46 $0.55 
Oil Collars:
Notional volume (bbl)— 439,100 906,700 317,400 
Weighted average put purchased$— $52.50 $43.08 $48.86 
Weighted average call sold$— $62.75 $51.63 $56.01 
Natural Gas Swaps:
Notional volume (MMBTU)444,100 1,539,100 270,100 — 
Weighted average swap price$2.54 $2.43 $2.59 $— 
Waha Differential (Basis) Swap:
Notional volume (MMBTU)829,500 1,568,500 270,100 — 
Weighted average swap price($0.22)($0.26)($0.26)$— 
Natural Gas Collars:
Notional volume (MMBTU)99,900 29,400 — — 
Weighted average put purchased$2.80 $2.80 $— $— 
Weighted average call sold$3.49 $3.49 $— $— 
14


NOTE 4. DERIVATIVE INSTRUMENTS - CONTINUED
The Partnership had the following outstanding open crude oil and natural gas positions as of December 31, 2020:
Expirations
202120222023
Oil Swaps:
Notional volume (bbl)2,585,600 1,167,200 — 
Weighted average swap price$53.44 $53.44 $50.68 $— 
Mid-Cush Differential (Basis) Swap:
Notional volume (bbl)2,585,600 1,167,200 353,700 
Weighted average swap price$0.93 $1.04 $0.30 
Oil Collars:
Notional volume (bbl)— — 627,000 
Weighted average put purchased$— $53.44 $— $40.00 
Weighted average call sold$— $— $48.38 
Natural Gas Swaps:
Notional volume (MMBTU)2,799,000 1,539,100 270,100 
Weighted average swap price$2.54 $2.43 $2.59 
Waha Differential (Basis) Swap:
Notional volume (MMBTU)3,072,600 1,539,100 270,100 
Weighted average swap price($0.26)($0.26)($0.26)
Proceeds from the Callon Divestiture were used to unwind the Partnership’s outstanding derivative contracts in conjunction with the closing of the transaction. See Note 11 for additional information.
NOTE 5. LINE OF CREDIT AND TERM LOAN FACILITIES
Debt outstanding is as follows (in thousands):
September 30, 2021December 31, 2020
Reserves-based line of credit$148,500 $87,500 
Term loan - HPS150,000 150,000 
Term loan - Blackstone130,000 130,000 
Deferred loan cost - HPS, net(1,611)(2,067)
Deferred loan cost - Blackstone, net(1)(6)
$426,888 $365,427 
Reserves-based Lines of Credit
On July 7, 2015, PRD entered into a senior, first lien credit agreement with Société Générale (“SG”), as administrative agent for a syndicated group of participating banks (the “Bank Group”). The credit agreement provided for a $500 million senior secured revolving credit facility expiring July 7, 2019 (the “Credit Facility”).

15


NOTE 5. LINE OF CREDIT AND TERM LOAN FACILITIES - CONTINUED
Reserves-based Lines of Credit - continued
On November 16, 2018, the Partnership entered into a second amended and restated credit agreement with J.P. Morgan as the administrative agent, replacing Société Générale as the previous administrative agent, for a syndicated group of participating banks. The credit agreement provides for a $750 million senior secured revolving credit facility expiring November 16, 2023. Substantially all the Partnerships oil and gas assets are pledged as collateral and are included in consideration of the borrowing base which is set by J.P. Morgan as administrative agent and is scheduled for redetermination on March 1 and September 1 of each year. In addition, we may request a borrowing base redetermination up to two times per year based on certain factors. The borrowing base at December 31, 2020 was $185 million.
On April 16, 2021, the borrowing based was reaffirmed at $185 million.
The Credit Facility contains certain financial covenants that must be met by PRD. 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 of PRD for debt compliance calculation purposes, among other adjustments (which calculation does not include the current assets of, or any accrued interest or current maturities of debt held at PRD’s parent entities (PEF or PEP)). Further, the 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 2.5% to 3.5% 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 $3.7 million and $4.4 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 $0.7 million and $0.6 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.
HPS Investment Partners Term Loan
On May 4, 2018, PEF entered into a $150 million delayed draw term loan with HPS Investment Partners (“HPS”). An amount of $50 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 May 4, 2024.
PEF completed additional draws of $50 million on October 1, 2018 and March 1, 2019 under this term loan for a total amount outstanding of $150 million.
The Notes Purchase Agreement contains various covenants pertaining to the financial condition of PEF. The covenants include as Asset Coverage Ratio of no less than 1.0 times beginning with the quarter ending December 31, 2018. The Asset Coverage Ratio increased to 1.50 times at December 31, 2019. For purposes of the covenant test, total debt is the debt at PEF of $150 million and the outstanding amount drawn on the revolver at PRD. The covenants also include certain restrictions on sales or encumbrances of assets, other advances, indebtedness, distributions and mergers or consolidations.

16


NOTE 5. LINE OF CREDIT AND TERM LOAN FACILITIES - CONTINUED
HPS Investment Partners Term Loan - continued
Interest on this term loan is payable quarterly and is at a rate equal to LIBOR plus 7.5%. Interest expense related to the HPS term loan of $8.7 million and $10.3 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 $0.5 million and $0.4 million was recorded during the nine-month periods ended September 30, 2021 and 2020, respectively.
As part of this credit facility, the Partnership created PEF as a subsidiary of PEP who is the borrower under this agreement.
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.
Blackstone Term Loan
On July 16, 2016, in connection with the Blackstone recapitalization of the Partnership, the Partnership entered into an agreement with BPP Holdco LLC, the Series B Preferred Unit holder, for a term loan in the amount of $130 million, with an original maturity date of January 7, 2020. Proceeds from this second lien facility were used to retire a previous credit facility. Three limited partners of the Partnership have provided guarantees of collection totaling $52.5 million, including a limited partner of the Partnership controlled by the Partnership’s Chairman of the Board, which has provided a guarantee of collection totaling $47.9 million.
On March 21, 2019, this agreement was amended to extend the maturity date to April 7, 2020.
On March 25, 2020, this agreement was amended to extend the maturity date to July 7, 2020 and to amend the requirement of an audit opinion that does not contain a going concern emphasis of matter paragraph to allow for any “going concern” qualification resulting from the occurrence of pending maturity date of the Partnership’s indebtedness.
On September 23, 2020, the agreement was amended to extend the maturity date to November 10, 2021.
On November 9, 2021, the agreement was amended to extend the maturity date to November 30, 2021.
Interest on this term loan is payable quarterly at an interest rate equal to LIBOR plus 12.0%, subject to a 1% floor. Interest expense related to the Blackstone term loan of $12.8 million and $13.3 million was recorded during the nine-month periods ended September 30, 2021 and 2020, respectively, excluding $1.1 million of accretion expense related to the discount on issuance of the Series B Preferred Units (see Note 6) for both respective periods.
Amortization of deferred loan costs related to the Blackstone term loan of $0.1 million and $0.4 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 Partnership. 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 at December 31, 2019. For purposes of the covenant test, total debt is the debt at PEP of $130 million and PEF of $150 million as well as the outstanding amount drawn on the revolver at PRD.
The Partnership amended the Blackstone Term Loan in conjunction with the closing of the Callon Divestiture. See Note 11 for additional information.
17


NOTE 6. REDEEMABLE SERIES B PREFERRED UNITS
On July 1, 2016, the Limited Partnership Agreement (“LPA”) was amended and restated to allow for the issuance of up to 300,000 Series B Preferred Units with a par value of $1,000 each. The Series B Preferred Unitholders are entitled to receive a distribution of 13.5% compounded interest and payable quarterly on April 1, July 1, October 1, and December 31. The distribution is prior and in preference to any declaration or payment of distributions to Series A Preferred Unit holders and any other classes of equity in the Partnership. The distribution is generally to be paid in additional Series B Preferred Units. At the discretion of the Managing General Partner, however, the distribution may be paid in cash for up to 50% of the amount to be distributed.
The activity and balance of the Redeemable Series B Preferred Units are as follows (in thousands):
Balance as of December 31, 2020$518,562 
Accretion of discount on issuance1,058 
Interest earned55,705 
Balance as of September 30, 2021$575,325 
NOTE 7. PARTNERS’ EQUITY
The limited partners’ equity consists of two general classes: (1) Series A Preferred Units, and “Common Units,” which are composed of several sub-classes described below.
The Common Units include the initial Class B founding limited partners and Class A limited partners admitted to the Partnership in 2001. In 2013, the Partnership amended and restated its LPA to provide for additional limited partner interests, including the Series A Preferred Units issued to Whittier, and three new sub-classes of Common Units (Class C, Class D, and Class E), made available for issuance as management incentive units. All issued Class C Units were redeemed or converted to Class B Units in February 2016. The Board issued and granted Class D Units to certain outside Board members, which remain issued and outstanding. There are no outstanding Class E Units.
In July 2016, in connection with the Blackstone financing, the Partnership amended and restated its LPA to provide for the Redeemable Series B Preferred Units (discussed in note 6) and their associated warrants (Class F Common Units), as well as a new class of management incentive units (Class G Common Units).
Under the Third Amended and Restated LPA Agreement, the following order of distributions will occur upon a liquidation event:
First, to the Redeemable Series B Preferred Units until satisfied.
Second, $100 million to the Legacy Unitholders, which consist of the Series A Preferred, Class A and Class B Common Unit holders in order of preference.
Lastly, proceeds will be split 55% to the Series F Common Units (and Series G Common Units once certain thresholds are met) and 45% to the Legacy Unitholders
The Series A Preferred Units are non-voting, perpetual limited partnership units, convertible to Class A-1 Common Units, and are entitled to a priority distribution of 8% per annum, cumulative and non-compounding with no current payment requirement. This payment is reflected as a reclass within the statement of changes in partners’ equity as a deemed distribution. Series A Preferred Units were purchased on November 1, 2013, November 15, 2014, and July 1, 2015.

18


NOTE 7. PARTNERS’ EQUITY - CONTINUED
The amount of cumulative deemed distributions to Series A Preferred Units that have not been paid as of September 30, 2021, was $81.9 million; as a result, the Series A Preferred Unit holder’s total investment in the Partnership, plus its deemed distribution, equals $236.4 million as of September 30, 2021.
As previously noted, the Class F and Class G Common Units represent equity interests in the Partnership created in connection with the 2016 recapitalization. The Class F Common Units were issued to the holder of the Series B Preferred Unit holders and participate in profits once the Series B Preferred distributions have been satisfied and $100.0 million of distributions have been made to legacy unitholders. Accordingly, the value of these Class F Common Units at issuance was de minimis.
Class G Common Units are issued as management incentive units and are considered “profits interests” for tax purposes. The Class Common G Units receive distributions of partnership profits after certain hurdles are met with respect to the other Preferred and Common Units. Accordingly, the value of these Class G Common Units at issuance was also de minimis.
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 Partnership’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 Partnership 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.
NOTE 9. RELATED PARTY TRANSACTIONS
As stated in Note 3, the Partnership, through SFS purchased the Pecos Property from the Chairman of the Board for $2.1 million. Prior to the closing of that transaction, the Partnership had a triple net lease agreement for the use of the property as a field office. Lease payments totaling $0.1 million were paid to the owner during the period ending September 30, 2020.
The Partnership has an affiliate receivable balance due from PEC in the amount of $0.1 million as of September 30, 2021 and December 31, 2020, respectively.
The Partnership’s Blackstone Term Loan is payable to BPP Holdco LLC and the Whittier Trust, both Series B Preferred Unit holders. Additionally, as stated in Note 5, there is a personal guarantee of this note by an entity controlled by the Chairman of the Board.

19


NOTE 9. RELATED PARTY TRANSACTIONS - CONTINUED
The Partnership entered into an agreement with EagleClaw Midstream (“EagleClaw”) on October 1, 2017 to gather and market gas produced pursuant to a gathering and acreage dedication agreement. The Partnership received $41.3 million and $9.9 million in gross sales during the nine-month periods ending September 30, 2021 and 2020, respectively. The Partnership and EagleClaw have the same controlling shareholder, however, there is no common management or shared operations between the two entities outside of the gathering agreement described above.
BPP Energy Partners LLC
The Partnership has shareholders and management in common with BPP Energy Partners LLC (“BPP”), a company formed to acquire oil-and-gas leases and assets within PEP’s operating area. In connection with the formation of BPP, the board approved a shared service agreement between the two companies so that all operations of BPP are conducted by POC and the cost of shared resources (including technology, office space and personnel) are reimbursed to POC by BPP at a rate of cost plus 2%. Additionally, BPP holds non-operated working interest in wells currently being drilled by PEP. Accordingly, PEP is responsible for distributing BPP’s share of revenue and invoicing for the related share of capital and lease operating expenses in accordance with the ownership held by BPP.
On July 11, 2018, BPP purchased approximately 22% of SFS from PRD. An incremental 6.23% and 1.75% was purchased on May 1, 2019 and July 2, 2019, respectively. As of the balance sheet date, BPP has purchased 30% equity ownership in SFS (see details of this purchase in Note 3). 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.
Below represents the balances and activity between BPP and POC (in thousands):
September 30, 2021September 30, 2020
BPP payable to POC$6,810 $111 
Revenue paid to BPP by POC$45,723 $34,124 
Capital and lease operating expenses paid to POC for joint interest billings$53,427 $37,548 
General and administrative expenses reimbursement to POC$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.
Rock Ridge Royalty Company LLC
The Partnership has shareholders and management in common with Rock Ridge Royalty Company LLC (“Rock Ridge”), a Delaware limited liability company formed in late 2016 to acquire and hold mineral and royalty interests in the Delaware Basin. Resources of the Partnership are utilized in the management and operations of Rock Ridge. These resources include technology, office space and personnel employed by POC. The cost of these resources is reimbursed by Rock Ridge based on the time allocated by employees to their work on Rock Ridge as well as actual costs incurred by POC and the Partnership.
20


NOTE 9. RELATED PARTY TRANSACTIONS - CONTINUED
Rock Ridge Royalty Company LLC - continued
On June 8, 2021, Rock Ridge entered into an agreement to contribute all its mineral and royalty interests in exchange for a 25% membership interest in DPM HoldCo, LLC (“Desert Peak Minerals”), a subsidiary of KMF Chambers HoldCo, LLC (“KMF”). The closing of the transaction was effective on June 30, 2021. Prior to the transaction, PRD leased certain acreage blocks for future development from Rock Ridge. As a result, PRD was an operator of certain Rock Ridge properties and paid Rock Ridge its respective royalty for hydrocarbons produced. As of September 30, 2021, no payments have been made by the Partnership to Desert Peak Minerals related to the Rock Ridge mineral and royalty interests included in the transaction.
Below represents the balances and activity between Rock Ridge and POC (in thousands):
September 30, 2021September 30, 2020
Rock Ridge payable to POC$52 $345 
Revenue paid to Rock Ridge by POC$3,600 $3,738 
Cash lease bonuses paid by POC$886 $— 
General and administrative expenses reimbursement to POC$584 $3,010 
Jetta Permian L.P.
On May 8, 2020, POC entered into a comprehensive management services agreement (“MSA”) with an effective date of June 1, 2020 to manage Jetta Permian, L.P. (“Jetta”), which had shareholders in common with the Partnership. Under this MSA, certain POC officers served as officers of Jetta and POC employees operated and maintained all of Jetta’s oil and gas properties, provided back office support and reporting requested by the board and required by Jetta’s bank agreements. For these services, POC received a monthly fee of $30,000 plus an amount of $900 per operated well and a drilling overhead fee of $9,000 per well per month prorated for drilling days to be paid in the month when wells are drilled. All out-of-pocket expenses paid by POC were reimbursed by Jetta.
On July 15, 2021, Jetta closed a divestiture transaction with a third party to sell all its leasehold interests and related assets effective July 1, 2021.
NOTE 10. COMMITMENTS AND CONTINGENCIES
The Partnership’s operations are subject to all the operational and environmental risks normally associated with the crude oil and natural gas industry. Additionally, the Partnership may become involved from time to time in litigation on various matters which are routine to the conduct of its business.
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 Partnership’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 Partnership.
21


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 Partnership totaled $678.5 million and was comprised of $354.5 million of cash consideration and 6.42 million shares of Callon stock issued to the Partnership in exchange for its oil and gas leasehold interests and infrastructure assets, subject to the finalization of purchase price adjustments within 120 days of closing.
On October 1, 2021, in conjunction with the closing of the transaction, the Partnership entered into a Senior Secured Promissory Note Agreement with Blackstone with an aggregate principal amount of $25 million. The unpaid principal balance bears interest at 2.75% per annum with a maturity date of 365 days after the date the loan was funded.
Upon closing, the Partnership used cash proceeds from the Callon Divestiture and the Blackstone Senior Secured Promissory Note to unwind its outstanding derivative contracts for $67.5 million and pay down the outstanding principal balances and accrued interest related to the HPS term loan and the Credit Facility of $151.7 million and $148.9 million, respectively.
The Partnership amended its Term Loan Agreement with Blackstone on October 1, 2021. Accordingly, interest expense related to the Blackstone Term Loan will be paid-in-kind in future interest periods and certain covenants have been eliminated. On November 9, 2021, the Blackstone Term Loan Agreement was amended to extend the maturity date to November 30, 2021.
Subsequent events were evaluated through November 19, 2021, the date the condensed consolidated financial statements were available for issuance.
22
Document
Exhibit 99.3



BPP ENERGY PARTNERS LLC
AND SUBSIDIARIES


CONSOLIDATED FINANCIAL STATEMENTS
AND INDEPENDENT AUDITORS’ REPORT



December 31, 2020 and 2019



CONTENTS


Page
INDEPENDENT AUDITORS’ REPORT
CONSOLIDATED FINANCIAL STATEMENTS
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Changes in Members’ Equity
Consolidated Statements of Cash Flows
Notes to the Consolidated Financial Statements
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)





INDEPENDENT AUDITORS’ REPORT
To the Board of Managers of BPP Energy Partners LLC
Dallas, Texas
We have audited the accompanying consolidated financial statements of BPP Energy Partners LLC and its subsidiaries (the "Company"), which comprise the consolidated balance sheets as of December 31, 2020 and 2019, and the related consolidated statements of operations, changes in members’ equity, and cash flows for the years then ended, and the related notes to the consolidated financial statements.
Management’s Responsibility for the Consolidated Financial Statements
Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.
Auditors’ Responsibility
Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the Company’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
Opinion
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of BPP Energy Partners LLC and its subsidiaries as of December 31, 2020 and 2019, and the results of their operations and their cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP
March 31, 2021





BPP ENERGY PARTNERS LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31
(in thousands)

20202019
Assets
Current Assets
Cash and cash equivalents$3,116 $14,758 
Revenue receivable6,752 14,692 
Commodity derivatives6,060 236 
Prepaid and other19,520 97 
Total current assets35,448 29,783 
Property, plant and equipment, net:
Oil and gas properties, full cost method of accounting87,383 237,416 
Unproved property and uncompleted capital projects excluded from amortization— 5,681 
Total oil and gas properties, net87,383 243,097 
Commodity derivatives2,809 153 
Loan origination cost, net232 235 
Investment in SFS20,339 21,100 
Total Assets$146,211 $294,368 
Liabilities and Members’ Equity
Current Liabilities
Accounts payable$— $49 
Accounts payable - affiliate972 9,906 
Other current liabilities12,329 8,155 
Commodity derivatives76 2,623 
Total current liabilities13,377 20,733 
Line of credit— — 
Term loan, net73,537 73,167 
Commodity derivatives1,868 1,165 
Asset retirement obligation763 523 
Total Liabilities89,545 95,588 
Commitments and contingencies (Note 10)
Members’ Equity56,666 198,780 
Total Liabilities and Members’ Equity$146,211 $294,368 


The accompanying notes are an integral part of these consolidated financial statements.
2



BPP ENERGY PARTNERS LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
THE YEARS ENDED DECEMBER 31
(in thousands)

20202019
Revenues
Oil sales$42,544 $54,241 
Natural gas sales1,128 1,372 
Gain (loss) on derivative instruments, net34,279 (4,672)
Total revenues77,951 50,941 
Costs and expenses
Lease operating expenses12,539 13,207 
Repairs1,503 727 
Production taxes2,126 2,604 
Depreciation, depletion and amortization28,660 20,615 
Impairment of oil and gas properties163,223 — 
General and administrative3,273 2,536 
Total operating expenses211,324 39,689 
(Loss) income from operations(133,373)11,252 
Other income (expense)
Interest expense(7,980)(7,543)
Equity in (loss) earnings of SFS(550)47,942 
Net (loss) income($141,903)$51,651 


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



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

Total
Equity
Balance, January 1, 2019$147,129 
Net income51,651 
Balance, December 31, 2019$198,780 
Purchase of interest from related party by SFS(211)
Net (loss)(141,903)
Balance, December 31, 2020$56,666 


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



BPP ENERGY PARTNERS LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
THE YEARS ENDING DECEMBER 31
(in thousands)

Cash flow from operating activities20202019
Net (loss) income($141,903)$51,651 
Adjustments to reconcile net (loss) income to cash used in operating activities:
Depreciation, depletion, and amortization28,660 20,615 
Impairment of oil and gas properties163,223 — 
Deferred loan cost amortization437 355 
Unrealized (gain) loss on derivative instruments(10,324)4,644 
Equity in loss (earnings) of SFS550 (47,942)
Distributed equity in earnings of SFS— 48,977 
Changes in operating assets and liabilities:
Accounts receivable7,940 (11,287)
Accounts payable(49)(548)
Accounts payable - affiliate(9,183)2,120 
Prepaid and other current assets(19,423)(97)
Other liabilities(3,837)(8,700)
Net cash provided by operating activities16,091 59,788 
Cash flow from investing activities
Additions to oil and gas properties(27,669)(104,446)
Purchase of equity in SFS, an equity method investment— (8,759)
Return of capital from SFS, an equity method investment— 12,047 
Net cash used in investing activities(27,669)(101,158)
Cash flow from financing activities
Proceeds from line of credit— 45,000 
Repayment of line of credit— (45,000)
Proceeds from term loan— 50,000 
Capitalized loan cost(64)(821)
Net cash (used in) provided by financing activities(64)49,179 
Net change in cash and cash equivalents(11,642)7,809 
Cash and cash equivalents, beginning of period14,758 6,949 
Cash and cash equivalents, end of period$3,116 $14,758 
Supplemental cash disclosures:
Property additions included in accrued liabilities$8,260 $8,713 
Asset retirement obligations incurred, including revisions to estimates$197 $341 
Cash paid for interest$7,593 $7,208 


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


BPP ENERGY PARTNERS LLC AND SUBSIDARIES
NOTES TO THE 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.
The Company was formed with 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. The Company’s Series B shareholders are owned by funds controlled by The Blackstone Group L.P. (“Blackstone”) and have a commitment to fund $300 million. Series C common interest holders have a commitment to fund $34.8 million (see Note 7 for detail on membership interest types). As of December 31, 2020, there is $171.1 million and $19.9 million of the above commitment remaining to be funded for the Series B Common and Series C Common, respectively.
Basis of Presentation
The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). These financial statements include the accounts of BPP Energy Partners, LLC and its subsidiaries: (i) BPP EF, and (ii) BPP Acquisition (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
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.
6


NOTE 2. SIGNIFICANT ACCOUNTING POLICIES - CONTINUED
Cash and Cash Equivalents
The Company considers all liquid investments with original maturities of three months or less to be cash equivalents. At December 31, 2020 and 2019, the Company did not have any cash equivalents.
Trade Accounts Receivable
Substantially all the Company’s receivables are within the oil and gas industry, primarily from purchasers of oil and gas. Collectability is dependent upon the general economic conditions of the purchasers and the industry. The receivables are not collateralized. The Company has had minimal bad debts; therefore, there is no allowance for doubtful accounts as of December 31, 2020 or 2019. Management considers the following factors when determining the collectability of specific accounts: credit worthiness, past transaction history, current economic industry trends, and changes in payment terms. If the financial condition of the Company’s purchasers were to deteriorate, adversely affecting their ability to make payments, allowances would be necessary.
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.
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 December 31, 2020, the Company recorded a $163.2 million noncash 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 year ended December 31, 2019.
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. The impairment assessment includes consideration of our intent to fully develop our unproved properties, remaining lease terms, geological and geophysical evaluations, our drilling results, potential drilling locations, availability of capital, assignment of proved reserves, expected divestitures, anticipated future capital expenditures and economic considerations, among others. 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. There were no expired leases during the years ended December 31, 2020 and 2019.
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.

7


NOTE 2. SIGNIFICANT ACCOUNTING POLICIES - CONTINUED
Oil and Gas Properties - continued
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.
Prepaid and Other Assets
Prepaid and other assets at December 31 consist of the following:
20202019
Prepaid drilling costs$19,390 $— 
Other130 97 
Total prepaid and other assets$19,520 $97 
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 Gain (loss) on derivative instruments, net, in the 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.

8


NOTE 2. SIGNIFICANT ACCOUNTING POLICIES - CONTINUED
Fair Value of Financial Instruments - continued
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.
Loan Origination Costs
Loan origination costs are amortized over the term of the related obligation using the effective interest method. Origination cost associated with our reserves-based line of credit are presented net of amortization within long-term assets. Origination cost associated with our term loan is net of amortization cost and are reported as an offset to the outstanding balance within long-term liabilities.
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.
Other Accrued Liabilities
Other accrued liabilities at December 31 consist of the following:
20202019
Accrued capital expenditures$8,010 $5,939 
Lease operating expenses payable3,636 1,481 
Interest payable678 728 
Other
Total other accrued liabilities$12,329 $8,155 
Asset Retirement Obligation
The Company records a liability for asset retirement obligations and increases the carrying value of the related asset in the period in which the liability is incurred. Asset retirement obligations primarily relate to the abandonment of oil and natural gas producing facilities and include costs to dismantle and relocate or dispose of wells and related structures. Accretion expense associated with asset retirement obligations is recorded over time.
The following table shows the changes in the balances of the asset retirement as of December 31 (in thousands).
20202019
Asset retirement obligation, January 1$523 $152 
Liabilities incurred197 148 
Liabilities sold(8)— 
Changes in estimates193 
Accretion expense43 30 
Asset retirement obligation, December 31$763 $523 
9


NOTE 2. SIGNIFICANT ACCOUNTING POLICIES - CONTINUED
Comprehensive income
During the periods ended December 31, 2020 and 2019, the Company did not have any comprehensive income or loss. Accordingly, net income (loss) equals comprehensive income (loss) for the period presented.
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 December 31, 2020 and 2019, the Company had receivables related to contracts with customers of $6.0 million and $14.6 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.
10


NOTE 2. SIGNIFICANT ACCOUNTING POLICIES - CONTINUED
Revenue Recognition - continued
The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical exemption allowed for in GAAP. The exemption 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.
New Accounting Pronouncements
In February 2016, FASB issued ASU 2016-02 – Leases (Topic 842), which requires the recognition of lease assets and lease liabilities by lessees for those leases currently classified as operating leases and makes certain changes to the accounting for lease expenses. This update is effective for fiscal years beginning after December 15, 2021, and for interim periods beginning the following year. ASC 842 should be applied using a modified retrospective approach. The Company is in the process of evaluating the impact of this new standard on its financial statements. The new guidance is expected to impact the Company’s balance sheets due to the recognition of right-of-use assets and lease liabilities that are not currently recognized under current accounting standards. The standard does not apply to leases to explore for or use minerals, oil or gas resources.
In June 2016, the FASB issued ASU 2016-13, "Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments" ("ASU 2016-13"). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, and requires entities to use a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. This update is effective for fiscal years beginning after December 15, 2022, including interim periods within those fiscal years, with early adoption permitted. Entities will use the modified retrospective approach to apply the standard's provisions and record a cumulative-effect adjustment to retained earnings for additional receivable loss allowances, if any, as of the beginning of the first reporting period in which the guidance is adopted. The Company is in the process of evaluating whether it will have a material impact on its consolidated financial statements.
NOTE 3. PROPERTY
Property consisted of the following at December 31 (in thousands):
20202019
Oil and gas properties:
Proved oil and gas properties$305,091 $263,283 
Unproved oil and gas properties excluded from amortization— 5,681 
Accumulated depreciation, depletion and amortization and impairment(217,708)(25,867)
Total net oil and gas properties$87,383 $243,097 
Supplemental Property Information:
Depletion expense$28,618 $20,585 
Capitalized interest$— $569 
11


NOTE 4. INVESTMENT IN SARAGOSA FIELD SERVICES
On July 11, 2018, the Company completed the purchase of 22% of SFS from Primexx Resource Development, LLC (“PRD”), a wholly owned subsidiary of Primexx Energy Partners Ltd (“PEP”) an affiliated entity (see Note 8), 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.
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.
12


NOTE 4. INVESTMENT IN SARAGOSA FIELD SERVICES - CONTINUED
SFS is accounted for on the equity method basis of accounting. The following details the condensed financial statements as of and for the year December 31, 2020 and 2019 (in thousands):
Condensed Balance Sheet
20202019
Current assets$7,290 $11,681 
Property, plant and equipment, net89,996 94,667 
Total assets$97,286 $106,348 
Current liabilities4,990 8,855 
Total liabilities29,490 36,016 
Members’ equity67,796 70,332 
Total Liabilities and Members’ Equity$97,286 $106,348 
Condensed Income Statement
20202019
Sales$25,827 $72,855 
Cost of sales2,371 4,735 
Field service expense10,926 24,841 
Production taxes198 202 
Depreciation, depletion and amortization16,351 19,972 
General and administrative643 1,208 
Total operating expenses30,489 50,958 
Gain on sale of saltwater disposal system— 136,342 
Other income2,829 1,891 
Net (loss) income(1,833)160,130 
Net (loss) income attributable to BPP(550)47,942 
Net (loss) income attributable to controlling owner($1,283)$112,188 
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.
13


NOTE 5. DERIVATIVE INSTRUMENTS - CONTINUED
The fair values of commodity derivatives at December 31 were as follows (in thousands):
20202019
Commodity derivative assets
Current portion$6,060 $236 
Long-term portion2,809 153 
8,869 389 
Commodity derivative liabilities
Current portion76 2,623 
Long-term portion1,868 1,165 
1,944 3,788 
Net commodity derivatives$6,925 ($3,399)
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 December 31, 2020 and 2019:
20202019
Realized gain (loss)
Oil derivatives$23,955 ($28)
Natural gas derivatives— — 
Total realized gain (loss)$23,955 ($28)
Unrealized gain (loss)
Oil derivatives$10,106 ($4,644)
Natural gas derivatives218 — 
Total unrealized gain (loss)$10,324 ($4,644)
Gain (loss) on derivative instruments, net$34,279 ($4,672)
14


NOTE 5. DERIVATIVE INSTRUMENTS - CONTINUED
The Company had the following outstanding open crude oil 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 $— 
Oil Collars:
Notional volume (bbl)— 30,900 216,200 
Weighted average put purchased$— $40.00 $40.00 
Weighted average call sold$— $45.15 $48.36 
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 
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)
The Company had the following outstanding open crude oil positions as of December 31, 2019:
Expirations
202020212022
Oil Swaps:
Notional volume (bbl)1,162,000 794,000 264,000 
Weighted average swap price$57.00 $53.44 $53.54 $51.17 
Mid-Cush Differential (Basis) Swap:
Notional volume (bbl)1,162,000 794,000 264,000 
Weighted average swap price$0.42 $0.99 $1.00 
NOTE 6. LINE OF CREDIT AND TERM LOAN FACILITIES
Debt as of December 31, 2020 and 2019 (in thousands):
20202019
Reserves-based line of credit$— $— 
Term loan - HPS75,000 75,000 
Deferred loan cost - HPS, net(1,463)(1,833)
Total debt outstanding$73,537 $73,167 
15


NOTE 6. LINE OF CREDIT AND TERM LOAN FACILITIES - CONTINUED
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.
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% t o 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.
Deferred loan cost of $0.2 million and $0.2 million (net of $0.1 million and $0.1 million in amortization) is recorded in long-term assets for the period ended December 31, 2020 and 2019, respectively.
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%.
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.
Deferred loan cost of $1.5 million and $1.8 million (net of $0.7 million and $0.3 million in amortization) as of December 31, 2020 and 2019, respectively. These amounts are presented as an offset to long-term debt.
16


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. The following chart details the issuance of these units:
Units outstanding as of January 1, 2019500 
Units granted during 201960 
Forfeitures— 
Units outstanding as of December 31, 2019560 
Units granted during 202061 
Forfeitures— 
Units outstanding as of December 31, 2020621 
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.
17


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 amounts were transacted between BPP and PEP (in thousands):
20202019
Affiliate payable to PEP$1,610 $9,906 
Revenue paid from PEP$50,240 $41,723 
Capital and lease operating expenses paid via joint interest billings to PEP$43,241 $115,845 
General and administrative expenses reimbursed$4,172 $3,239 
BPP had $19.4 million and $0 of unapplied prepaid capital expenditures deposited with PRD recorded in current prepaid assets as of December 31, 2020 and 2019, respectively.
During the year ended December 31, 2019, the Company sold a lease for 203 acres in the amount of $2.0 million (the Company’s cost basis) to PEP.
Rock Ridge Royalty Company
The Company has shareholders and management in common with Rock Ridge Royalty Company (“RRR”) a Delaware limited liability company formed in 2016 to acquire and hold mineral and royalty interests in the Delaware Basin. During 2019, the Company leased approximately 360 acres to BPP receiving a total lease bonus of $3.8 million, respectively.
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.

18


NOTE 10. COMMITMENTS AND CONTINGENCIES - CONTINUED
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 the financial markets. These events, in addition to disruptions in the demand for oil combined with pressures on the global supply-demand balance for oil, resulted in significant volatility in oil prices during 2020. The effects of the COVID-19 pandemic negatively impacted the Company’s results of operations and led to a reduction in capital activities. The impact of these events on the financial performance of the Company’s long-term operations is uncertain, including the duration of the COVID-19 pandemic and long-term effects on global oil demand. The financial statements have been prepared using values and information currently available to the Company.
NOTE 11. SUBSEQUENT EVENTS
On January 8, 2021, the Company and PRD 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 in exchange for interests in certain properties and future technical consulting services in the joint development area.
Subsequent events have been evaluated through March 31, 2021, the date on which the financial statements were available to be issued.
19




















SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
20


Geographic Area of Operation
The Company’s oil and natural gas reserves are located within the continental United States and concentrated in the Delaware Basin of Texas.
Capitalized Oil and Natural Gas Costs
Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion and amortization are as follows (in thousands):
December 31, 2020December 31, 2019
Oil and gas properties
Proved oil and gas properties$305,091 $263,283 
Unproved oil and gas properties— 5,681 
Accumulated depletion and impairment(217,708)(25,867)
Net oil and gas properties capitalized$87,383 $243,097 
Costs Incurred in Oil and Natural Gas Activities
Costs incurred in oil and natural gas property acquisition, exploration and development activities are as follows (in thousands):
December 31, 2020December 31, 2019
Acquisition costs
Proved oil and gas properties$14 $1 
Unproved oil and gas properties1,679 13,680 
Development costs34,376 102,178 
Exploration costs— 225 
Total costs incurred$36,069 $116,084 
Results of Operations from Oil and Natural Gas Producing Activities
The following sets forth the revenues and expenses related to the production and sale of oil and natural gas (in thousands). It does not include any realized hedges, interest costs or general and administrative costs and, therefore, is not necessarily indicative of the net operating results of the Company’s oil and natural gas operations.
December 31, 2020December 31, 2019
Oil and natural gas sales$43,672 $55,613 
Production costs(16,168)(16,538)
Depletion(28,618)(20,585)
Impairment of oil and gas properties(163,223)— 
Results of operations from oil and natural gas producing activities($164,337)$18,490 
The reserves as of December 31, 2020 and 2019 presented below were prepared by independent petroleum engineers. The calculation and analysis of interim changes in proved reserves were prepared by the Company. Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. The reserves are located in the Delaware Basin of Texas.
The following tables set forth estimated net quantities of the Company’s estimated proved reserves, projected future cash inflows, and future production and development costs and are prepared in accordance with guidelines established by the SEC. Accordingly, the reserve estimates are based upon existing economic and operating conditions. For estimates of proved reserves, the average spot prices are determined based upon the 12-month unweighted average of the first day of the month prices adjusted by applying price and cost basis differentials,
21


including transportation and quality, and are then applied to the period-end estimated quantities of oil, natural gas and natural gas liquids (“NGL”) to be produced in the future. Future net cash flows are reduced to present value amounts by applying a ten percent annual discount factor.
The assumptions used to compute the standardized measure are those prescribed by GAAP. These assumptions do not necessarily reflect management’s expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these reserve quantity estimates are the basis for the valuation process. Reserve estimates are inherently imprecise and estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available.
Analysis of Changes in Proved Reserves
The following table sets forth information regarding the Company’s net ownership interest in estimated quantities of proved developed and undeveloped oil and natural gas quantities and the changes therein for each of the periods presented:
OilNatural GasNGLsTotal
(MBbls)(MMcf)(MBbls)(MBOE)
Balance, January 1, 201913,389 14,106 3,242 18,982 
Revisions(1,684)2,032 (372)(1,717)
Extensions12,098 15,299 2,720 17,368 
Acquisitions of reserves142 404 71 280 
Production(1,014)(1,080)(190)(1,384)
Balance, December 31, 201922,931 30,761 5,471 33,529 
Revisions(9,883)(9,947)(1,688)(13,230)
Extensions5,979 10,416 1,875 9,591 
Acquisitions of reserves60 135 25 108 
Production(1,154)(1,839)(330)(1,791)
Balance, December 31, 202017,933 29,526 5,353 28,207 
OilNatural GasNGLsTotal
Proved developed and undeveloped reserves:(MBbls)(MMcf)(MBbls)(MBOE)
Developed as of December 31, 20182,077 2,315 555 3,018 
Undeveloped as of December 31, 201811,312 11,791 2,687 15,964 
Balance at December 31, 201813,389 14,106 3,242 18,982 
Developed as of December 31, 20195,411 8,060 1,392 8,146 
Undeveloped as of December 31, 201917,520 22,701 4,079 25,383 
Balance at December 31, 201922,931 30,761 5,471 33,529 
Developed as of December 31, 20203,630 6,734 1,225 5,977 
Undeveloped as of December 31, 202014,303 22,792 4,128 22,230 
Balance at December 31, 202017,933 29,526 5,353 28,207 
Revisions to previous estimates of proved reserves, either upward or downward, are a result of updated information obtained in the reporting period, including operator drilling activity and production history or changes in economic factors such as commodity prices, operating and development costs.
22


During the year ended December 31, 2020, the Company’s extensions and discoveries of 9,591 MBOE resulted primarily from conversions of non-proved and contingent resources to proved due to drilling activity. The Company acquired 108 MBOE in Reeves County, Texas from 0.1 net producing wells and 0.1 net undeveloped locations. In addition, the Company negatively revised previous estimates by 13,230 MBOE due to the following:
Downgrade of 10,701 MBOE of proved reserves to non-proved due to the decrease in drilling activity in 2020 resulting in development moving outside of the five-year development window,
Negative revision of 3,326 MBOE due to downward movement in SEC pricing,
Increase of 792 MBOE due to decreases in gas and NGL processing and basis differentials, and
Positive revision of 5 MBOE attributed to upward revisions of estimated ultimate recovery, changes in operating and development costs, and adjustments to well spacing and development timing.
During the year ended December 31, 2019, the Company’s extensions and discoveries of 17,368 MBOE resulted primarily from conversions of non-proved and contingent resources to proved due to drilling activity. The Company acquired 280 MBOE in Reeves County, Texas from 0.5 net producing wells. In addition, the Company negatively revised previous estimates by 1,717 MBOE due to the following:
Negative revision of 4,008 MBOE due to downward movement in SEC pricing,
Decrease of 48 MBOE due to increases in gas and natural gas liquids processing and basis differentials, and
Positive revision of 2,339 MBOE attributed upward revisions of estimated ultimate recovery, changes in operating and development costs, and adjustments to well spacing and development timing.
Standardized Measure of Oil and Gas
The standardized measure and projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to the Company. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary. Our calculations of the standardized measure of discounted future net cash flows and the related changes therein do not include the effect of estimated federal income tax expenses because the Company is not subject to federal income taxes. The Company is subject to certain state-based taxes; however, these amounts are not material.
As of December 31, 2020, the reserves are comprised of 64% crude oil, 17% natural gas and 19% NGL on an energy equivalent basis.
The values for the December 31, 2020 and 2019 proved reserves were derived based on prices presented in the table below. The crude oil pricing was based on the West Texas Intermediate (“WTI”) price; the NGL pricing was 21% of WTI for 2020 and 33% of WTI for 2019; the natural gas pricing was based on the Henry Hub price. All prices have been adjusted for transportation, quality and basis differentials.
OilNatural GasNGLs
($/Bbl)($/Mcf)($/Bbl)
December 31, 2020 (Average)36.620.1308.32
December 31, 2019 (Average)46.10-0.02118.32
23


The following summary sets forth the future net cash flows related to proved oil and natural gas reserves based on the standardized measure prescribed in ASC Topic 932 (in thousands):
December 31, 2020December 31, 2019
Future oil and natural gas sales$705,019 $1,156,636 
Future production costs(317,487)(390,967)
Future development costs(203,563)(261,002)
Future net cash flows183,969 504,667 
10% annual discount(96,586)(251,002)
Standardized measure of discounted future net cash flows$87,383 $253,665 
The principal sources of change in the standardized measure of discounted future net cash flows are (in thousands):
Year Ended December 31,
20202019
Standardized measure, beginning of year$253,665 $167,641 
Net change in prices and production costs(68,124)57,424 
Changes in future development costs131,911 54,944 
Oil and gas sales, net of production costs(27,504)(39,075)
Extensions and discoveries33,182 150,177 
Acquisitions of reserves340 3,407 
Revisions of previous quantity estimates(127,191)(28,861)
Development costs incurred during the period8,564 29,762 
Accretion of discount25,367 16,764 
Changes in timing and other(142,827)(158,518)
Standardized measure, end of year$87,383 $253,665 
24
Document
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.
6


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.
7


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.
8


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.
9


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.
10


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.


11


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 
12


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 
13


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 $— $— 
14


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.

15


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.
16


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.
17


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.
19
Document

Exhibit 99.5
Callon Petroleum Company
Unaudited Pro Forma Condensed Combined Financial Information

The following unaudited pro forma condensed combined financial information is derived from the historical consolidated financial statements of Callon Petroleum Company (“Callon” or the “Company”), Primexx Resource Development, LLC (“Primexx”) and BPP Acquisition, LLC (“BPP”) and has been adjusted to reflect the following:
Callon’s acquisition of Primexx’s assets consisting of certain producing oil and gas properties, undeveloped acreage and associated infrastructure assets in the Delaware Basin (the “Primexx Acquisition”) for consideration of approximately $342.3 million in cash and 6.42 million shares of the Company’s common stock (the “Primexx Stock Consideration”), subject to post-closing adjustments.
Callon’s acquisition of BPP’s assets consisting of certain producing oil and gas properties, undeveloped acreage and associated infrastructure assets in the Delaware Basin (the “BPP Acquisition”) for consideration of approximately $102.6 million in cash and 2.42 million shares of the Company’s common stock (the “BPP Stock Consideration”), subject to post-closing adjustments.
Callon’s acquisition of additional interest in the assets described above from certain interest owners exercising their option to sell their interests (together with the Primexx Acquisition and the BPP Acquisition, the “Acquisitions”) for consideration structured similar to the Primexx Acquisition and BPP Acquisition totaling approximately $19.8 million in cash and 0.34 million shares of the Company’s common stock, subject to post-closing adjustments.
Borrowings of approximately $464.7 million under the Company’s senior secured revolving credit facility which were used to fund the Acquisitions (the “Borrowing”).
Certain of Primexx’s and BPP’s historical amounts have been reclassified to conform to the financial statement presentation of Callon. Additionally, the adjustments columns in the unaudited pro forma condensed combined financial statements below include adjustments and eliminations made to Primexx’s and BPP’s historical financial information to reflect certain assets and liabilities retained by Primexx and BPP, respectively, as well as for intercompany eliminations necessary to combine Primexx and BPP as they have shareholders and management in common. The unaudited pro forma condensed combined balance sheet as of September 30, 2021 gives effect to the Acquisitions and Borrowing as if they had occurred on September 30, 2021. The unaudited pro forma condensed combined statements of operations for the year ended December 31, 2020 and the nine months ended September 30, 2021 both give effect to the Acquisitions and Borrowing as if they had occurred on January 1, 2020.    
For income tax purposes, the Acquisitions will be treated as an asset purchase such that the tax bases in the assets and liabilities will generally reflect the allocated fair value at closing. Therefore, the Company does not anticipate a material tax consequence for deferred income taxes related to the Acquisitions. Additionally, Callon has not reflected any estimated tax impact related to the Acquisitions or Borrowing in the accompanying unaudited pro forma condensed combined statements of operations for the nine months ended September 30, 2021 or for the year ended December 31, 2020 because it does not anticipate the impact to be material due to the Company’s net operating loss carryforwards. The Company’s effective tax rate is not meaningful and is expected to remain as such due to the valuation allowance recorded against the Company’s net deferred tax assets.
The following unaudited pro forma condensed combined financial information should be read in conjunction with Callon’s consolidated financial statements and the related notes thereto, which are included in Callon’s Annual Report on Form 10-K for the year ended December 31, 2020 and its Quarterly Report on Form 10-Q for the nine months ended September 30, 2021, and Primexx’s and BPP’s consolidated financial statements and the related notes thereto, which are included elsewhere in this filing.

1


Callon Petroleum Company
Unaudited Pro Forma Condensed Combined Balance Sheet
As of September 30, 2021
(In thousands)
HistoricalTransaction Accounting Adjustments
Callon -
As
Reported
Primexx -
As
Reported
BPP -
As
Reported
Elimination
Adjustments
Acquisitions
and
Borrowing
Pro
Forma
Combined
(a)
ASSETS
Current assets:
Cash and cash equivalents$3,699 $11,724 $18,219 ($29,943)$7,981 (c)$11,680 
Accounts receivable, net216,116 40,654 14,962 (55,616)216,116 
Fair value of derivatives18,605 1,712 562 (2,274)18,605 
Other current assets30,110 1,442 100 (1,542)2,232 (c)32,342 
Total current assets268,530 55,532 33,843 (89,375)10,213 278,743 
Oil and natural gas properties, full cost accounting method:
Evaluated properties, net2,565,601 361,000 108,505 (469,505)623,389 (c)3,188,990 
Unevaluated properties1,712,428 — — 312,700 (c)2,025,128 
Total oil and natural gas properties, net4,278,029 361,000 108,505 (469,505)936,089 5,214,118 
Other property and equipment, net30,591 83,510 — (83,510)(b)30,591 
Fair value of derivatives— 6,161 1,549 (7,710)— 
Deferred financing costs19,274 — — 19,274 
Loan origination cost, net— 1,870 200 (2,070)— 
Investment in SFS— — 21,000 (21,000)— 
Other assets, net89,992 1,136 — (1,136)89,992 
Total assets$4,686,416 $509,209 $165,097 ($674,306)$946,302 $5,632,718 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities$442,053 $54,777 $15,554 ($70,331)$13,658 (c)$455,711 
Fair value of derivatives324,682 39,477 12,799 (52,276)324,682 
Current portion of deferred revenue— 2,797 — (2,797)— 
Current portion of long-term debt, net— 129,999 — (129,999)— 
Other current liabilities61,641 40,632 61 (40,693)28,117 (c)89,758 
Total current liabilities828,376 267,682 28,414 (296,096)41,775 870,151 
Long-term debt2,809,610 296,889 81,300 (378,189)464,678 (d)3,274,288 
Deferred revenue— 22,531 — (22,531)— 
Asset retirement obligations58,703 5,327 763 (6,090)1,870 (c)60,573 
Fair value of derivatives15,250 29,707 8,578 (38,285)15,250 
Deferred tax liability— 46 — (46)— 
Other long-term liabilities41,448 308 — (308)9,426 (c)50,874 
Total liabilities3,753,387 622,490 119,055 (741,545)517,749 4,271,136 
Commitments and contingencies
Redeemable Series B preferred units, net— 575,325 — (575,325)— 
Stockholders’ equity:
Common stock463 — — 92 (e)555 
Capital in excess of par value3,365,121 — — 428,461 (e)3,793,582 
Members’ equity— — 46,042 (46,042)— 
Partners’ equity (deficit)— (709,606)— 709,606 — 
Noncontrolling interest— 21,000 — (21,000)— 
Accumulated deficit(2,432,555)— — — (2,432,555)
Total stockholders’ equity933,029 (688,606)46,042 642,564 428,553 1,361,582 
Total liabilities and stockholders’ equity$4,686,416 $509,209 $165,097 ($674,306)$946,302 $5,632,718 

2


Callon Petroleum Company
Unaudited Pro Forma Condensed Combined Statement of Operations
For the Nine Months Ended September 30, 2021
(In thousands, except per share amounts)
HistoricalTransaction Accounting Adjustments
Callon -
As
Reported
Primexx -
As
Reported
BPP -
As
Reported
Reclassification
& Elimination
Adjustments
Acquisitions
and Borrowing
Pro
Forma
Combined
(a)
Operating Revenues:
Oil$1,009,780 $154,309 $49,870 $1,213,959 
Natural gas84,819 28,858 7,565 1,380 122,622 
Natural gas liquids124,079 — — 124,079 
Sales of purchased oil and gas134,164 — — 134,164 
Field service revenue— 9,985 — (9,985)(b)— 
Total operating revenues1,352,842 193,152 57,435 (8,605)— 1,594,824 
Operating Expenses: 
Lease operating129,619 42,830 14,545 1,283 (b)188,277 
Production and ad valorem taxes66,467 8,642 2,760 2,284 (b)80,153 
Gathering, transportation and processing58,887 739 — 59,626 
Field service expenses— 9,474 — (9,474)(b)— 
Cost of purchased oil and gas139,558 — — 139,558 
Depreciation, depletion and amortization244,005 51,073 12,040 (8,966)(c)298,152 
General and administrative37,367 3,964 2,116 43,447 
Impairment of evaluated oil and gas properties— — — — 
Merger, integration and transaction3,018 — — 3,018 
Other operating3,366 — — 3,366 
Total operating expenses682,287 116,722 31,461 (5,907)(8,966)815,597 
Income (Loss) From Operations670,555 76,430 25,974 (2,698)8,966 779,227 
Other (Income) Expenses: 
Interest expense, net of capitalized amounts76,786 27,346 6,582 (33,928)(1,016)(d)75,770 
Loss on derivative contracts512,155 101,218 34,751 (135,969)512,155 
Gain on extinguishment of debt(2,420)— — (2,420)
Equity in earnings of SFS— — (4,485)4,485 — 
Other (income) expense3,217 (2,174)(39)2,213 3,217 
Total other (income) expense589,738 126,390 36,809 (163,199)(1,016)588,722 
Income (Loss) Before Income Taxes80,817 (49,960)(10,835)160,501 9,982 190,505 
Income tax expense(1,017)(40)— (1,057)
Net Income (Loss)$79,800 ($50,000)($10,835)$160,501 $9,982 $189,448 
Net loss attributable to noncontrolling interest— (4,485)— 4,485 — 
Series B preferred unit distribution— (55,705)— 55,705 — 
Income (Loss) Available to Stockholders $79,800 ($110,190)($10,835)$220,691 $9,982 $189,448 
Net Income (Loss) Per Common Share: 
Basic$1.77 $3.49 
Diluted$1.69 $3.36 
Weighted Average Common Shares Outstanding: 
Basic45,063 9,181 (e)54,244 
Diluted47,119 9,181 (e)56,300 


3


Callon Petroleum Company
Unaudited Pro Forma Condensed Combined Statement of Operations
For the Year Ended December 31, 2020
(In thousands, except per share amounts)
HistoricalTransaction Accounting Adjustments
Callon -
As
Reported
Primexx -
As
Reported
BPP -
As
Reported
Reclassification
& Elimination
Adjustments
Acquisitions
and Borrowing
Pro
Forma
Combined
(a)
Operating Revenues:
Oil$850,667 $139,776 $42,544 $1,032,987 
Natural gas51,866 10,627 1,128 1,513 65,134 
Natural gas liquids81,295 — — 81,295 
Sales of purchased oil and gas49,319 — — 49,319 
Field service revenue— 8,450 — (8,450)(b)— 
Total operating revenues1,033,147 158,853 43,672 (6,937)— 1,228,735 
Operating Expenses:   
Lease operating194,101 46,808 14,042 4,010 (b)258,961 
Production and ad valorem taxes62,638 6,994 2,126 4,207 (b)75,965 
Gathering, transportation and processing77,309 1,868 — 79,177 
Field service expenses— 11,677 — (11,677)(b)— 
Cost of purchased oil and gas51,766 — — 51,766 
Depreciation, depletion and amortization480,631 106,047 28,660 (47,376)(c)567,962 
General and administrative37,187 7,477 3,273 47,937 
Impairment of evaluated oil and gas properties2,547,241 457,502 163,223 3,167,966 
Merger, integration and transaction28,482 — — 28,482 
Other operating10,644 — — 10,644 
Total operating expenses3,489,999 638,373 211,324 (3,460)(47,376)4,288,860 
Income (Loss) From Operations(2,456,852)(479,520)(167,652)(3,477)47,376 (3,060,125)
Other (Income) Expenses:   
Interest expense, net of capitalized amounts94,329 40,138 7,980 (48,118)(50)(d)94,279 
(Gain) loss on derivative contracts27,773 (93,256)(34,279)127,535 27,773 
(Gain) loss on extinguishment of debt(170,370)— — (170,370)
Equity in (earnings) loss of SFS— — 550 (550)— 
Other (income) expense2,983 (2,882)— 2,882 2,983 
Total other (income) expense(45,285)(56,000)(25,749)81,749 (50)(45,335)
Income (Loss) Before Income Taxes(2,411,567)(423,520)(141,903)(85,226)47,426 (3,014,790)
Income tax benefit (expense)(122,054)— (122,048)
Net Income (Loss)($2,533,621)($423,514)($141,903)($85,226)$47,426 ($3,136,838)
Net gain (loss) attributable to noncontrolling interest— 550 — (550)— 
Series B preferred unit distribution— (66,148)— 66,148 — 
Income (Loss) Available to Stockholders($2,533,621)($489,112)($141,903)($19,628)$47,426 ($3,136,838)
Net Income (Loss) Per Common Share: 
Basic($63.79)($64.15)
Diluted($63.79)($64.15)
Weighted Average Common Shares Outstanding:
Basic39,718 9,181 (e)48,899 
Diluted39,718 9,181 (e)48,899 


4


Notes to the Unaudited Pro Forma Consolidated Financial Statements

Note 1 - Basis of Presentation
On October 1, 2021, Callon and Callon Petroleum Operating Company, Callon’s wholly owned subsidiary, completed its acquisition of certain producing oil and gas properties, undeveloped acreage and associated infrastructure assets in the Delaware Basin for total consideration of $464.7 million in cash and 9.18 million shares of the Company’s common stock, subject to post-closing adjustments.
The historical consolidated financial statements have been adjusted in the unaudited pro forma condensed combined financial statements to give effect to pro forma adjustments that are directly attributable to the Acquisitions and Borrowing. The preparation of the unaudited pro forma condensed combined financial statements is in accordance with accounting principles generally accepted in the United States of America. These principles require the use of estimates that affect the reported amounts of revenues and expenses. Actual results could differ from those estimates. The unaudited pro forma condensed combined financial statements are presented for illustrative purposes only to reflect the Acquisitions and Borrowing and do not purport to represent the Company's financial position or what the actual results of operations would have been had the transaction occurred on the respective dates assumed, nor is it necessarily indicative of the Company's future operating results. However, the pro forma adjustments reflected in the unaudited pro forma condensed combined financial statements reflect estimates and assumptions that the Company's management believes to be reasonable. In the opinion of management, all adjustments necessary to present fairly the unaudited pro forma condensed combined financial statements have been made.
Note 2 - Unaudited Pro Forma Condensed Combined Balance Sheet
Adjustments to the Unaudited Pro Forma Condensed Combined Balance Sheet as of September 30, 2021
Reclassification & Elimination Adjustments
The following adjustments have been made to the accompanying unaudited pro forma condensed combined balance sheet as of September 30, 2021 to reclassify certain of Primexx’s and BPP’s historical amounts to conform to the historical presentation of Callon and to eliminate certain assets and liabilities retained by Primexx and BPP:
a)Represents the elimination of Primexx and BPP balances. See “Acquisitions and Borrowing Adjustments” below for discussion of the assets acquired and liabilities assumed in the Acquisitions.
b)Reflects the elimination of other property and equipment, net associated with Saragosa Field Services (“SFS”) as the Company has incorporated those assets into its oil and natural gas properties, net. Upon closing of the Primexx Acquisition and BPP Acquisition, the Company dissolved the SFS entity.
Acquisitions and Borrowing Adjustments
The following adjustments have been made to the accompanying unaudited pro forma condensed combined balance sheet as of September 30, 2021 to reflect the Acquisitions and Borrowing:
c)The Acquisitions will be accounted for as a single transaction because they were entered into at the same time and in contemplation of one another and form a single transaction designed to achieve an overall economic effect. The Acquisitions will be accounted for as a business combination whereby the purchase price is allocated to assets acquired and liabilities assumed based on their estimated acquisition date fair values based on information available at that time. While the Company’s valuation procedures are currently in process, it is using a combination of a discounted cash flow model and market data in determining the fair value of the oil and gas properties. Significant inputs into the calculation include future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. The current preliminary purchase price allocation is based on a preliminary discounted cash flow analysis. The purchase price allocation for the Acquisitions is subject to change based on the Company’s finalization of its valuation procedures as well as purchase price adjustments, which will primarily relate to the revenues, operating expenses and capital expenditures from the effective date to the closing date. The preliminary allocation of the purchase price as of the acquisition date is presented below:
5


Purchase Price Allocation
(In thousands)
Assets
Current assets$10,213 
Oil and natural gas properties
Evaluated properties623,389 
Unevaluated properties312,700
Total oil and natural gas properties936,089
Total assets acquired$946,302 
Liabilities
Suspense payable$13,658 
Other current liabilities28,117
Total current liabilities41,775
Asset retirement obligations1,870
Other long-term liabilities9,426
Total liabilities assumed$53,071 
Net Assets Acquired$893,231 
d)Reflects $464.7 million of borrowings under Callon’s senior secured revolving credit facility which were used to fund the Acquisitions.
e)Reflects the increase in Callon’s common stock and additional paid-in capital resulting from the issuance of Callon shares for the Acquisitions.
Note 3 - Unaudited Pro Forma Condensed Combined Statement of Operations
Adjustments to the Unaudited Pro Forma Condensed Combined Statement of Operations for the nine months ended September 30, 2021
Reclassification & Elimination Adjustments
The following adjustments have been made to the accompanying unaudited pro forma condensed combined statement of operations for the nine months ended September 30, 2021 to reclassify certain of Primexx’s and BPP’s historical amounts to conform to the historical presentation of Callon and to eliminate the effects of certain assets and liabilities retained by Primexx and BPP:
a)Represents adjustments to eliminate the effects of assets and liabilities retained by Primexx and BPP and not associated with the oil and natural gas properties acquired.
b)Reflects the elimination of separate revenue and expense line items associated with SFS, a consolidated subsidiary of Primexx, as the Company has incorporated all SFS operations and activities into its ongoing oil and gas operations. Upon closing of the Primexx Acquisition and BPP Acquisition, the Company dissolved the SFS entity.
Acquisitions and Borrowing Adjustments
The following adjustments have been made to the accompanying unaudited pro forma condensed combined statement of operations for the nine months ended September 30, 2021 to reflect the Acquisitions and Borrowing:
c)Reflects adjustment to depreciation, depletion and amortization expense resulting from the change in basis of evaluated properties acquired.
d)Reflects the following adjustments to interest expense, net of capitalized amounts:
$8.8 million increase in interest expense as a result of the Borrowing,
$1.7 million decrease in interest expense to reflect the reduction in commitment fees as a result of the Borrowing, and
$8.1 million increase in capitalized interest as a result of the effects of the Acquisitions and Borrowing.
e)Reflects 9.18 million shares of Callon common stock issued as a portion of the consideration for the Acquisitions.

6


Adjustments to the Unaudited Pro Forma Condensed Combined Statement of Operations for the year ended December 31, 2020
Reclassification & Elimination Adjustments
The following adjustments have been made to the accompanying unaudited pro forma condensed combined statement of operations for the year ended December 31, 2020 to reclassify certain of Primexx’s and BPP’s historical amounts to conform to the historical presentation of Callon and to eliminate the effects of certain assets and liabilities retained by Primexx and BPP:
a)Represents adjustments to eliminate the effects of assets and liabilities retained by Primexx and BPP and not associated with the oil and natural gas properties acquired.
b)Reflects the elimination of separate revenue and expense line items associated with SFS, a consolidated subsidiary of Primexx, as the Company has incorporated all SFS operations and activities into its ongoing oil and gas operations. Upon closing of the Primexx Acquisition and BPP Acquisition, the Company dissolved the SFS entity.
Acquisitions and Borrowing Adjustments
The following adjustments have been made to the accompanying unaudited pro forma condensed combined statement of operations for the year ended December 31, 2020 to reflect the Acquisitions and Borrowing:
c)Reflects adjustment to depreciation, depletion and amortization expense resulting from the change in basis of evaluated properties acquired.
d)Reflects the following adjustments to interest expense, net of capitalized amounts:
$13.5 million increase in interest expense as a result of the Borrowing,
$2.3 million decrease in interest expense to reflect the reduction in commitment fees as a result of the Borrowing, and
$11.3 million increase in capitalized interest as a result of the effects of the Acquisitions and Borrowing.
e)Reflects 9.18 million shares of Callon common stock issued as a portion of the consideration for the Acquisitions.

7


Note 4 - Supplemental Pro Forma Oil and Gas Information
The following tables present the estimated pro forma combined net proved developed and undeveloped oil and natural gas reserves as of December 31, 2020 for Callon, Primexx and BPP, along with a summary of changes in the quantities of net remaining proved reserves during the year ended December 31, 2020. The pro forma reserve information set forth below gives effect to the Acquisitions as if they had been completed on January 1, 2020.
Reserve estimates are inherently imprecise. As such, actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from the estimates.
Historical
Callon -
As Reported
Primexx -
As Reported
BPP -
As Reported
Pro Forma
Combined
Total proved reserves
Oil (MBbls)
Balance as of January 1, 2020346,361 71,149 22,931 440,441 
Purchase of reserves in place— — 60 60 
Sale of reserves in place(9,673)(53)— (9,726)
Extensions and discoveries25,678 14,225 5,979 45,882 
Revisions to previous estimates(49,336)(26,722)(9,883)(85,941)
Production(23,543)(3,789)(1,154)(28,486)
Balance as of December 31, 2020289,487 54,810 17,933 362,230 
Natural Gas (MMcf)
Balance as of January 1, 2020757,134 97,183 30,761 885,078 
Purchase of reserves in place— — 135 135 
Sale of reserves in place(20,389)(97)— (20,486)
Extensions and discoveries44,282 23,402 10,416 78,100 
Revisions to previous estimates(198,628)(26,490)(9,947)(235,065)
Production(40,801)(5,669)(1,839)(48,309)
Balance as of December 31, 2020541,598 88,329 29,526 659,453 
NGLs (MBbls)
Balance as of January 1, 202067,462 18,064 5,471 90,997 
Purchase of reserves in place— — 25 25 
Sale of reserves in place(3,049)(21)— (3,070)
Extensions and discoveries8,349 4,324 1,875 14,548 
Revisions to previous estimates30,214 (5,010)(1,688)23,516 
Production(6,850)(1,019)(330)(8,199)
Balance as of December 31, 202096,126 16,338 5,353 117,817 
Total (MBoe)
Balance as of January 1, 2020540,012 105,411 33,529 678,952 
Purchase of reserves in place— — 108 108 
Sale of reserves in place(16,120)(90)— (16,210)
Extensions and discoveries41,407 22,449 9,591 73,447 
Revisions to previous estimates(52,227)(36,147)(13,230)(101,604)
Production(37,193)(5,753)(1,791)(44,737)
Balance as of December 31, 2020475,879 85,870 28,207 589,956 

8



Historical
Callon -
As Reported
Primexx -
As Reported
BPP -
As Reported
Pro Forma
Combined
Proved developed reserves
Oil (MBbls)
Balance as of January 1, 2020152,687 16,616 5,411 174,714 
Balance as of December 31, 2020128,923 12,958 3,630 145,511 
Natural gas (MMcf)
Balance as of January 1, 2020320,676 24,717 8,060 353,453 
Balance as of December 31, 2020238,119 24,419 6,734 269,272 
NGLs (MBbls)
Balance as of January 1, 202024,844 4,529 1,392 30,765 
Balance as of December 31, 202043,315 4,509 1,225 49,049 
Total proved developed reserves (MBoe)
Balance as of January 1, 2020230,977 25,265 8,146 264,388 
Balance as of December 31, 2020211,925 21,537 5,977 239,439 
Proved undeveloped reserves
Oil (MBbls)
Balance as of January 1, 2020193,674 54,533 17,520 265,727 
Balance as of December 31, 2020160,564 41,852 14,303 216,719 
Natural gas (MMcf)
Balance as of January 1, 2020436,458 72,466 22,701 531,625 
Balance as of December 31, 2020303,479 63,910 22,792 390,181 
NGLs (MBbls)
Balance as of January 1, 202042,618 13,535 4,079 60,232 
Balance as of December 31, 202052,811 11,829 4,128 68,768 
Total proved undeveloped reserves (MBoe)
Balance as of January 1, 2020309,035 80,146 25,383 414,564 
Balance as of December 31, 2020263,954 64,333 22,230 350,517 
Total proved reserves
Oil (MBbls)
Balance as of January 1, 2020346,361 71,149 22,931 440,441 
Balance as of December 31, 2020289,487 54,810 17,933 362,230 
Natural gas (MMcf)
Balance as of January 1, 2020757,134 97,183 30,761 885,078 
Balance as of December 31, 2020541,598 88,329 29,526 659,453 
NGLs (MBbls)
Balance as of January 1, 202067,462 18,064 5,471 90,997 
Balance as of December 31, 202096,126 16,338 5,353 117,817 
Total proved reserves (MBoe)
Balance as of January 1, 2020540,012 105,411 33,529 678,952 
Balance as of December 31, 2020475,879 85,870 28,207 589,956 
9


The pro forma standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves as of December 31, 2020 is as follows:
Historical
Callon -
As Reported
Primexx -
As Reported
BPP -
As Reported
Pro Forma
Combined
(In thousands)
Future cash inflows$12,458,033 $2,118,782 $705,019 $15,281,834 
Future costs
Production(5,433,496)(881,455)(317,487)(6,632,438)
Development and net abandonment(2,204,301)(619,403)(203,563)(3,027,267)
Future net inflows before income taxes4,820,236 617,924 183,969 5,622,129 
Future income taxes(65,405)— — (65,405)
Future net cash flows4,754,831 617,924 183,969 5,556,724 
10% discount factor(2,444,441)(329,785)(96,586)(2,870,812)
Standardized measure of discounted future net cash flows$2,310,390 $288,139 $87,383 $2,685,912 
The changes in the pro forma standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the year ended December 31, 2020 are as follows:
Historical
Callon -
As Reported
Primexx -
As Reported
BPP -
As Reported
Pro Forma
Combined
(In thousands)
Standardized measure at the beginning of the period$4,951,026 $833,401 $253,665 $6,038,092 
Sales and transfers, net of production costs(649,781)(94,733)(27,504)(772,018)
Net change in sales and transfer prices, net of production costs(2,719,579)(179,308)(68,124)(2,967,011)
Net change due to purchases of in place reserves— — 340 340 
Net change due to sales of in place reserves(202,928)(222)— (203,150)
Extensions, discoveries, and improved recovery, net of future production and development costs incurred250,759 61,236 33,182 345,177 
Changes in future development cost361,008 382,499 131,911 875,418 
Previously estimated development costs incurred318,470 35,167 8,564 362,201 
Revisions of quantity estimates(671,800)(226,579)(127,191)(1,025,570)
Accretion of discount536,958 83,340 25,367 645,665 
Net change in income taxes383,999 — — 383,999 
Changes in production rates, timing and other(247,742)(606,662)(142,827)(997,231)
Aggregate change(2,640,636)(545,262)(166,282)(3,352,180)
Standardized measure at the end of the period$2,310,390 $288,139 $87,383 $2,685,912 
10
Document

Exhibit 99.6
https://cdn.kscope.io/da292b2786bbd9275e621934bcdf735b-image1a.jpg

October 27, 2021


Primexx Operating Corporation
Two Energy Square
4849 Greenville Avenue, Suite 1600
Dallas, Texas 75206

Ladies and Gentlemen:

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2020, to the Primexx Resource Development, LLC (PRD) interest in certain oil and gas properties located in Reeves County, Texas. Also included is PRD's share of the volumes, fees, and revenue for its interest in Saragosa Field Services, LLC (SFS), which provides gas gathering services. It is our understanding that Primexx Operating Corporation (Primexx) is a wholly owned subsidiary of PRD. It is also our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by PRD at the as-of date of this report. We completed our evaluation on or about February 4, 2021. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for Callon Petroleum Company's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

We estimate the net reserves and future net revenue to the PRD interest in these properties, as of December 31, 2020, to be:
Net ReservesFuture Net Revenue (M$)
OilNGLGasPresent Worth
Category(MBBL)(MBBL)(MMCF)Totalat 10%
Proved Developed Producing12,957.54,508.824,418.6235,934.9167,655.0
Proved Undeveloped41,852.011,829.063,909.5381,988.9120,484.4
Total Proved54,809.516,337.888,328.1617,923.8288,139.4
Totals may not add because of rounding.

Note: The oil reserves and future net revenue include PRD's share of the volumes, fees, and revenue for its interest in SFS. For the purposes of this report, PRD's share of the SFS revenue excludes fees paid by third parties.

The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. Our study indicates that as of December 31, 2020, there are no proved developed non-producing reserves for these properties. As requested, probable and possible reserves that exist for these properties have not been included. The estimates of reserves and future revenue included herein have not been adjusted for risk. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated.
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Gross revenue is PRD's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for PRD's share of production taxes, ad valorem taxes, capital costs, abandonment costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2020. For oil and NGL volumes, the average West Texas Intermediate spot price of $39.54 per barrel is adjusted for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $1.985 per MMBTU is adjusted for energy content, transportation fees, and market differentials; for certain properties, gas prices are negative after adjustments. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $36.18 per barrel of oil, $8.34 per barrel of NGL, and -$0.005 per MCF of gas.

Operating costs used in this report are based on operating expense records of Primexx and SFS. These costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Operating costs have been divided into field-level costs, per-well costs, and per-unit-of-production costs. Headquarters general and administrative overhead expenses of Primexx are included to the extent that they are covered under joint operating agreements for the Primexx-operated properties. PRD's working interest share of fees paid to SFS for gas gathering is offset by PRD's share of the SFS revenue; these fees have been included at the field level and, therefore, do not affect the future net revenue or economic limits at the well level. For the purposes of this report, PRD's share of the SFS revenue excludes fees paid by third parties. Operating costs are not escalated for inflation.

Capital costs used in this report were provided by Primexx and are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for new development wells and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Abandonment costs used in this report are our estimates of the costs to abandon the wells, net of any salvage value. Capital costs and abandonment costs are not escalated for inflation.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.

We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the PRD interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on PRD receiving its net revenue interest share of estimated future gross production. Additionally, we have made no specific investigation of any firm transportation contracts that may be in place for these properties; our estimates of future revenue include the effects of such contracts only to the extent that the associated fees are accounted for in the historical field- and lease-level accounting statements.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the Primexx-operated properties will be developed consistent with current development plans as provided to us by Primexx, that the nonoperated properties will be developed consistent with recent history, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with


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actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

For the purposes of this report, we used technical and economic data including, but not limited to, geologic maps, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. A substantial portion of these reserves are for undeveloped locations; such reserves are based on analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from Primexx, other interest owners, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical persons primarily responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. Michael J. Kingrey, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2015 and has over 6 years of prior industry experience. William J. Knights, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 1991 and has over 10 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

Sincerely,
NETHERLAND, SEWELL & ASSOCIATES, INC.
Texas Registered Engineering Firm F-2699
By:
/s/ C.H. (Scott) Rees III
C.H. (Scott) Rees III, P.E.
Chairman and Chief Executive Officer
By:
/s/ Michael J. Kingrey
By:
/s/ William J. Knights
Michael J. Kingrey, P.E. 128848
William J. Knights, P.G. 1532
Vice President
Vice President
Date Signed:October 27, 2021Date Signed:October 27, 2021


MJK:KAT


Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.


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DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2018 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations.

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i)Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
(ii)Same environment of deposition;
(iii)Similar geological structure; and
(iv)Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i)Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
(ii)Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Supplemental definitions from the 2018 Petroleum Resources Management System:
Developed Producing Reserves – Expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate. Improved recovery Reserves are considered producing only after the improved recovery project is in operation.
Developed Non-Producing Reserves – Shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals that are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

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DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(i)Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.
(ii)Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.
(iii)Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.
(iv)Provide improved recovery systems.

(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(i)Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.
(ii)Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.
(iii)Dry hole contributions and bottom hole contributions.
(iv)Costs of drilling and equipping exploratory wells.
(v)Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas producing activities.

(i)Oil and gas producing activities include:
(A)The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;
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DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(B)The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;
(C)The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:
(1)Lifting the oil and gas to the surface; and
(2)Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and
(D)Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

a.The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and
b.In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii)Oil and gas producing activities do not include:

(A)Transporting, refining, or marketing oil and gas;
(B)Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;
(C)Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or
(D)Production of geothermal steam.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i)When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
(ii)Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
(iii)Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
(iv)The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
(v)Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
(vi)Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty
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DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i)When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
(ii)Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
(iii)Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
(iv)See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20) Production costs.

(i)Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

(A)Costs of labor to operate the wells and related equipment and facilities.
(B)Repairs and maintenance.
(C)Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.
(D)Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.
(E)Severance taxes.

(ii)Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i)The area of the reservoir considered as proved includes:

(A)The area identified by drilling and limited by fluid contacts, if any, and
(B)Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii)In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
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DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(iii)Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
(iv)Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A)Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
(B)The project has been approved for development by all necessary parties and entities, including governmental entities.

(v)Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23) Proved properties. Properties with proved reserves.

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:
932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year:
a.Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)
b.Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).
The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.
932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:
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DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
a.Future cash inflows. These shall be computed by applying prices used in estimating the entity’s proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.
b.Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.
c.Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.
d.Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.
e.Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.
f.Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i)Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
(ii)Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

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DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):
Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.
Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:
The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);
The company's historical record at completing development of comparable long-term projects;
The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;
The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and
The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

(iii)Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties. Properties with no proved reserves.
Definitions - Page 7 of 7


Document

Exhibit 99.7
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October 26, 2021


Primexx Operating Corporation
Two Energy Square
4849 Greenville Ave, Suite 1600
Dallas, Texas 75206

Ladies and Gentlemen:

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2019, to the Primexx Resource Development, LLC (PRD) interest in certain oil and gas properties located in Reeves County, Texas. Also included is PRD's share of the volumes, fees, and revenue for its interest in Saragosa Field Services, LLC (SFS), which provides gas gathering and gas lift services. It is our understanding that Primexx Operating Corporation (Primexx) is a wholly owned subsidiary of PRD. It is also our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by PRD at the as-of date of this report. We completed our evaluation on or about January 31, 2020. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for Callon Petroleum Company's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

We estimate the net reserves and future net revenue to the PRD interest in these properties, as of December 31, 2019, to be:
Net ReservesFuture Net Revenue (M$)
OilNGLGasPresent Worth
Category(MBBL)(MBBL)(MMCF)Totalat 10%
Proved Developed Producing16,615.64,529.024,717.3531,912.8353,975.9
Proved Undeveloped54,532.713,534.972,466.11,124,795.4479,424.8
Total Proved71,148.418,063.997,183.41,656,708.0833,400.6
Totals may not add because of rounding.

Note: The oil reserves and future net revenue include PRD's share of the volumes, fees, and revenue for its interest in SFS. For the purposes of this report, PRD's share of the SFS revenue excludes fees paid by third parties.

The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. Our study indicates that as of December 31, 2019, there are no proved developed non-producing reserves for these properties. As requested, probable and possible reserves that exist for these properties have not been included. The estimates of reserves and future revenue included herein have not been adjusted for risk. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated.
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Gross revenue is PRD's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for PRD's share of production taxes, ad valorem taxes, capital costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2019. For oil and NGL volumes, the average West Texas Intermediate spot price of $55.85 per barrel is adjusted for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $2.578 per MMBTU is adjusted for energy content, transportation fees, and market differentials; for certain properties, gas prices are negative after adjustments. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $46.51 per barrel of oil, $18.14 per barrel of NGL, and -$0.154 per MCF of gas.

Operating costs used in this report are based on operating expense records of Primexx and SFS. These costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels; included in these costs are estimated costs for artificial lift installations. Operating costs have been divided into field-level costs, per-well costs, and per-unit-of-production costs. Headquarters general and administrative overhead expenses of Primexx are included to the extent that they are covered under joint operating agreements for the Primexx-operated properties. PRD's working interest share of fees paid to SFS for gas gathering and gas lift services are offset by PRD's share of the SFS revenue; these fees have been included at the field level and, therefore, do not affect the future net revenue or economic limits at the well level. For the purposes of this report, PRD's share of the SFS revenue excludes fees paid by third parties. Operating costs are not escalated for inflation.

Capital costs used in this report were provided by Primexx and are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for new development wells and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Capital costs are not escalated for inflation. As requested, our estimates do not include any salvage value for the lease and well equipment or the cost of abandoning the properties.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.

We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the PRD interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on PRD receiving its net revenue interest share of estimated future gross production. Additionally, we have made no specific investigation of any firm transportation contracts that may be in place for these properties; our estimates of future revenue include the effects of such contracts only to the extent that the associated fees are accounted for in the historical field- and lease-level accounting statements.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the Primexx-operated properties will be developed consistent with current development plans as provided to us by Primexx, that the nonoperated properties will be developed consistent with recent history, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the


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interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

For the purposes of this report, we used technical and economic data including, but not limited to, geologic maps, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. A substantial portion of these reserves are for undeveloped locations; such reserves are based on analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from Primexx, other interest owners, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical persons primarily responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. Michael J. Kingrey, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2015 and has over 6 years of prior industry experience. William J. Knights, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 1991 and has over 10 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

Sincerely,
NETHERLAND, SEWELL & ASSOCIATES, INC.
Texas Registered Engineering Firm F-2699
By:
/s/ C.H. (Scott) Rees III
C.H. (Scott) Rees III, P.E.
Chairman and Chief Executive Officer
By:
/s/ Michael J. Kingrey
By:
/s/ William J. Knights
Michael J. Kingrey, P.E. 128848
William J. Knights, P.G. 1532
Vice President
Vice President
Date Signed:October 26, 2021Date Signed:October 26, 2021

MJK:KAT

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.


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DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2018 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations.

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i)Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
(ii)Same environment of deposition;
(iii)Similar geological structure; and
(iv)Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i)Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
(ii)Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Supplemental definitions from the 2018 Petroleum Resources Management System:
Developed Producing Reserves – Expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate. Improved recovery Reserves are considered producing only after the improved recovery project is in operation.
Developed Non-Producing Reserves – Shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals that are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

Definitions - Page 1 of 7



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DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(i)Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.
(ii)Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.
(iii)Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.
(iv)Provide improved recovery systems.

(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(i)Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.
(ii)Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.
(iii)Dry hole contributions and bottom hole contributions.
(iv)Costs of drilling and equipping exploratory wells.
(v)Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas producing activities.

(i)Oil and gas producing activities include:
(A)The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;
Definitions - Page 2 of 7



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DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(B)The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;
(C)The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:
(1)Lifting the oil and gas to the surface; and
(2)Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and
(D)Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

a.The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and
b.In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii)Oil and gas producing activities do not include:

(A)Transporting, refining, or marketing oil and gas;
(B)Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;
(C)Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or
(D)Production of geothermal steam.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i)When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
(ii)Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
(iii)Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
(iv)The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
(v)Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
(vi)Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty
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DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i)When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
(ii)Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
(iii)Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
(iv)See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20) Production costs.

(i)Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

(A)Costs of labor to operate the wells and related equipment and facilities.
(B)Repairs and maintenance.
(C)Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.
(D)Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.
(E)Severance taxes.

(ii)Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i)The area of the reservoir considered as proved includes:

(A)The area identified by drilling and limited by fluid contacts, if any, and
(B)Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii)In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
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DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(iii)Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
(iv)Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A)Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
(B)The project has been approved for development by all necessary parties and entities, including governmental entities.

(v)Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23) Proved properties. Properties with proved reserves.

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:
932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year:
a.Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)
b.Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).
The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.
932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:
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DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
a.Future cash inflows. These shall be computed by applying prices used in estimating the entity’s proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.
b.Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.
c.Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.
d.Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.
e.Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.
f.Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i)Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
(ii)Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

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DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):
Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.
Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:
The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);
The company's historical record at completing development of comparable long-term projects;
The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;
The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and
The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

(iii)Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties. Properties with no proved reserves.
Definitions - Page 7 of 7


Document

Exhibit 99.8
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October 27, 2021


Primexx Operating Corporation
Two Energy Square
4849 Greenville Avenue, Suite 1600
Dallas, Texas 75206

Ladies and Gentlemen:

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2020, to the BPP Acquisition LLC (BPP) interest in certain oil and gas properties located in Reeves County, Texas. Also included is BPP's share of the volumes, fees, and revenue for its interest in Saragosa Field Services, LLC (SFS), which provides gas gathering services. It is our understanding that Primexx Operating Corporation (Primexx) conducts all oil and gas operations for BPP. It is also our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by BPP at the as-of date of this report. We completed our evaluation on or about February 4, 2021. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for Callon Petroleum Company's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

We estimate the net reserves and future net revenue to the BPP interest in these properties, as of December 31, 2020, to be:
Net ReservesFuture Net Revenue (M$)
OilNGLGasPresent Worth
Category(MBBL)(MBBL)(MMCF)Totalat 10%
Proved Developed Producing3,630.31,225.06,733.660,891.445,008.6
Proved Undeveloped14,303.34,128.122,791.7123,077.442,374.3
Total Proved17,933.55,353.229,525.3183,968.987,382.9
Totals may not add because of rounding.

Note: The oil reserves and future net revenue include BPP's share of the volumes, fees, and revenue for its interest in SFS. For the purposes of this report, BPP's share of the SFS revenue excludes fees paid by third parties.

The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. Our study indicates that as of December 31, 2020, there are no proved developed non-producing reserves for these properties. As requested, probable and possible reserves that exist for these properties have not been included. The estimates of reserves and future revenue included herein have not been adjusted for risk. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated.
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Gross revenue is BPP's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for BPP's share of production taxes, ad valorem taxes, capital costs, abandonment costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2020. For oil and NGL volumes, the average West Texas Intermediate spot price of $39.54 per barrel is adjusted for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $1.985 per MMBTU is adjusted for energy content, transportation fees, and market differentials; for certain properties, gas prices are negative after adjustments. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $36.62 per barrel of oil, $8.32 per barrel of NGL, and $0.130 per MCF of gas.

Operating costs used in this report are based on operating expense records of Primexx and SFS. These costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Operating costs have been divided into field-level costs, per-well costs, and per-unit-of-production costs. Headquarters general and administrative overhead expenses of Primexx are included to the extent that they are covered under joint operating agreements for the Primexx-operated properties. BPP's working interest share of fees paid to SFS for gas gathering is offset by BPP's share of the SFS revenue; these fees have been included at the field level and, therefore, do not affect the future net revenue or economic limits at the well level. For the purposes of this report, BPP's share of the SFS revenue excludes fees paid by third parties. Operating costs are not escalated for inflation.

Capital costs used in this report were provided by Primexx and are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for new development wells and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Abandonment costs used in this report are our estimates of the costs to abandon the wells, net of any salvage value. Capital costs and abandonment costs are not escalated for inflation.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.

We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the BPP interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on BPP receiving its net revenue interest share of estimated future gross production. Additionally, we have made no specific investigation of any firm transportation contracts that may be in place for these properties; our estimates of future revenue include the effects of such contracts only to the extent that the associated fees are accounted for in the historical field- and lease-level accounting statements.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the Primexx-operated properties will be developed consistent with current development plans as provided to us by Primexx, that the nonoperated properties will be developed consistent with recent history, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with


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actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

For the purposes of this report, we used technical and economic data including, but not limited to, geologic maps, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. A substantial portion of these reserves are for undeveloped locations; such reserves are based on analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from Primexx, other interest owners, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical persons primarily responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. Michael J. Kingrey, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2015 and has over 6 years of prior industry experience. William J. Knights, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 1991 and has over 10 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

Sincerely,
NETHERLAND, SEWELL & ASSOCIATES, INC.
Texas Registered Engineering Firm F-2699
By:
/s/ C.H. (Scott) Rees III
C.H. (Scott) Rees III, P.E.
Chairman and Chief Executive Officer
By:
/s/ Michael J. Kingrey
By:
/s/ William J. Knights
Michael J. Kingrey, P.E. 128848
William J. Knights, P.G. 1532
Vice President
Vice President
Date Signed:October 27, 2021Date Signed:October 27, 2021


MJK:KAT


Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.


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DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2018 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations.

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i)Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
(ii)Same environment of deposition;
(iii)Similar geological structure; and
(iv)Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i)Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
(ii)Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Supplemental definitions from the 2018 Petroleum Resources Management System:
Developed Producing Reserves – Expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate. Improved recovery Reserves are considered producing only after the improved recovery project is in operation.
Developed Non-Producing Reserves – Shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals that are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

Definitions - Page 1 of 7



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DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(i)Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.
(ii)Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.
(iii)Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.
(iv)Provide improved recovery systems.

(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(i)Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.
(ii)Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.
(iii)Dry hole contributions and bottom hole contributions.
(iv)Costs of drilling and equipping exploratory wells.
(v)Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas producing activities.

(i)Oil and gas producing activities include:
(A)The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;
Definitions - Page 2 of 7



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DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(B)The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;
(C)The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:
(1)Lifting the oil and gas to the surface; and
(2)Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and
(D)Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

a.The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and
b.In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii)Oil and gas producing activities do not include:

(A)Transporting, refining, or marketing oil and gas;
(B)Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;
(C)Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or
(D)Production of geothermal steam.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i)When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
(ii)Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
(iii)Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
(iv)The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
(v)Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
(vi)Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty
Definitions - Page 3 of 7



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DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i)When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
(ii)Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
(iii)Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
(iv)See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20) Production costs.

(i)Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

(A)Costs of labor to operate the wells and related equipment and facilities.
(B)Repairs and maintenance.
(C)Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.
(D)Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.
(E)Severance taxes.

(ii)Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i)The area of the reservoir considered as proved includes:

(A)The area identified by drilling and limited by fluid contacts, if any, and
(B)Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii)In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
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DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(iii)Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
(iv)Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A)Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
(B)The project has been approved for development by all necessary parties and entities, including governmental entities.

(v)Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23) Proved properties. Properties with proved reserves.

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:
932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year:
a.Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)
b.Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).
The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.
932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:
Definitions - Page 5 of 7



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DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
a.Future cash inflows. These shall be computed by applying prices used in estimating the entity’s proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.
b.Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.
c.Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.
d.Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.
e.Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.
f.Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i)Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
(ii)Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

Definitions - Page 6 of 7



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DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):
Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.
Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:
The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);
The company's historical record at completing development of comparable long-term projects;
The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;
The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and
The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

(iii)Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties. Properties with no proved reserves.
Definitions - Page 7 of 7


Document

Exhibit 99.9
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October 26, 2021


Primexx Operating Corporation
Two Energy Square
4849 Greenville Ave, Suite 1600
Dallas, Texas 75206

Ladies and Gentlemen:

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2019, to the BPP Acquisition LLC (BPP) interest in certain oil and gas properties located in Reeves County, Texas. Also included is BPP's share of the volumes, fees, and revenue for its interest in Saragosa Field Services, LLC (SFS), which provides gas gathering and gas lift services. It is our understanding that Primexx Operating Corporation (Primexx) conducts all oil and gas operations for BPP. It is also our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by BPP at the as-of date of this report. We completed our evaluation on or about January 31, 2020. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for Callon Petroleum Company's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

We estimate the net reserves and future net revenue to the BPP interest in these properties, as of December 31, 2019, to be:
Net ReservesFuture Net Revenue (M$)
OilNGLGasPresent Worth
Category(MBBL)(MBBL)(MMCF)Totalat 10%
Proved Developed Producing5,410.61,391.58,060.2171,441.8116,167.3
Proved Undeveloped17,520.04,079.322,701.4333,224.6137,497.8
Total Proved22,930.65,470.830,761.6504,666.5253,665.1
Totals may not add because of rounding.

Note: The oil reserves and future net revenue include BPP's share of the volumes, fees, and revenue for its interest in SFS. For the purposes of this report, BPP's share of the SFS revenue excludes fees paid by third parties.

The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. Our study indicates that as of December 31, 2019, there are no proved developed non-producing reserves for these properties. As requested, probable and possible reserves that exist for these properties have not been included. The estimates of reserves and future revenue included herein have not been adjusted for risk. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated.
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Gross revenue is BPP's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for BPP's share of production taxes, ad valorem taxes, capital costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2019. For oil and NGL volumes, the average West Texas Intermediate spot price of $55.85 per barrel is adjusted for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $2.578 per MMBTU is adjusted for energy content, transportation fees, and market differentials; for certain properties, gas prices are negative after adjustments. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $46.10 per barrel of oil, $18.32 per barrel of NGL, and -$0.021 per MCF of gas.

Operating costs used in this report are based on operating expense records of Primexx and SFS. These costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels; included in these costs are estimated costs for artificial lift installations. Operating costs have been divided into field-level costs, per-well costs, and per-unit-of-production costs. Headquarters general and administrative overhead expenses of Primexx are included to the extent that they are covered under joint operating agreements for the Primexx-operated properties. BPP's working interest share of fees paid to SFS for gas gathering and gas lift services are offset by BPP's share of the SFS revenue; these fees have been included at the field level and, therefore, do not affect the future net revenue or economic limits at the well level. For the purposes of this report, BPP's share of the SFS revenue excludes fees paid by third parties. Operating costs are not escalated for inflation.

Capital costs used in this report were provided by Primexx and are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for new development wells and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Capital costs are not escalated for inflation. As requested, our estimates do not include any salvage value for the lease and well equipment or the cost of abandoning the properties.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.

We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the BPP interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on BPP receiving its net revenue interest share of estimated future gross production. Additionally, we have made no specific investigation of any firm transportation contracts that may be in place for these properties; our estimates of future revenue include the effects of such contracts only to the extent that the associated fees are accounted for in the historical field- and lease-level accounting statements.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the Primexx-operated properties will be developed consistent with current development plans as provided to us by Primexx, that the nonoperated properties will be developed consistent with recent history, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the


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interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

For the purposes of this report, we used technical and economic data including, but not limited to, geologic maps, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. A substantial portion of these reserves are for undeveloped locations; such reserves are based on analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from Primexx, other interest owners, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical persons primarily responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. Michael J. Kingrey, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2015 and has over 6 years of prior industry experience. William J. Knights, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 1991 and has over 10 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

Sincerely,
NETHERLAND, SEWELL & ASSOCIATES, INC.
Texas Registered Engineering Firm F-2699
By:
/s/ C.H. (Scott) Rees III
C.H. (Scott) Rees III, P.E.
Chairman and Chief Executive Officer
By:
/s/ Michael J. Kingrey
By:
/s/ William J. Knights
Michael J. Kingrey, P.E. 128848
William J. Knights, P.G. 1532
Vice President
Vice President
Date Signed:October 26, 2021Date Signed:October 26, 2021

MJK:KAT

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.


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DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2018 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations.

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i)Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
(ii)Same environment of deposition;
(iii)Similar geological structure; and
(iv)Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i)Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
(ii)Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Supplemental definitions from the 2018 Petroleum Resources Management System:
Developed Producing Reserves – Expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate. Improved recovery Reserves are considered producing only after the improved recovery project is in operation.
Developed Non-Producing Reserves – Shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals that are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

Definitions - Page 1 of 7



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DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(i)Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.
(ii)Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.
(iii)Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.
(iv)Provide improved recovery systems.

(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(i)Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.
(ii)Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.
(iii)Dry hole contributions and bottom hole contributions.
(iv)Costs of drilling and equipping exploratory wells.
(v)Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas producing activities.

(i)Oil and gas producing activities include:
(A)The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;
Definitions - Page 2 of 7



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DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(B)The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;
(C)The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:
(1)Lifting the oil and gas to the surface; and
(2)Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and
(D)Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

a.The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and
b.In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii)Oil and gas producing activities do not include:

(A)Transporting, refining, or marketing oil and gas;
(B)Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;
(C)Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or
(D)Production of geothermal steam.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i)When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
(ii)Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
(iii)Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
(iv)The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
(v)Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
(vi)Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty
Definitions - Page 3 of 7



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DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i)When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
(ii)Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
(iii)Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
(iv)See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20) Production costs.

(i)Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

(A)Costs of labor to operate the wells and related equipment and facilities.
(B)Repairs and maintenance.
(C)Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.
(D)Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.
(E)Severance taxes.

(ii)Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i)The area of the reservoir considered as proved includes:

(A)The area identified by drilling and limited by fluid contacts, if any, and
(B)Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii)In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
Definitions - Page 4 of 7



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DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(iii)Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
(iv)Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A)Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
(B)The project has been approved for development by all necessary parties and entities, including governmental entities.

(v)Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23) Proved properties. Properties with proved reserves.

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:
932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year:
a.Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)
b.Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).
The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.
932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:
Definitions - Page 5 of 7



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DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
a.Future cash inflows. These shall be computed by applying prices used in estimating the entity’s proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.
b.Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.
c.Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.
d.Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.
e.Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.
f.Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i)Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
(ii)Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

Definitions - Page 6 of 7



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DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):
Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.
Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:
The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);
The company's historical record at completing development of comparable long-term projects;
The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;
The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and
The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

(iii)Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties. Properties with no proved reserves.
Definitions - Page 7 of 7


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