Callon Petroleum : CONSOLIDATED FINANCIAL STATEMENTS AND INDEPENDENT AUDITORS’ REPORT - Form 8-K/A

CONSOLIDATED FINANCIAL STATEMENTS

AND INDEPENDENT AUDITORS' REPORT

December 31, 2020 and 2019

CONTENTS

Page
INDEPENDENT AUDITORS' REPORT	1
CONSOLIDATED FINANCIAL STATEMENTS
Consolidated Balance Sheets	2
Consolidated Statements of Operations	3
Consolidated Statements of Changes in Partners' Equity (Deficit)	4
Consolidated Statements of Cash Flows	5
Notes to the Consolidated Financial Statements	6
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)	26

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)

2020	2019
Assets
Current Assets
Cash and cash equivalents	$7,253	$22,501
Trade accounts receivable	17,028	37,126
Accounts receivable - affiliate	1,350	10,849
Prepaids and other	415	520
Commodity derivatives	14,263	638
Total current assets	40,309	71,634
Property, plant and equipment, net:
Oil and gas properties, full cost method of accounting	273,167	730,248
Other property and equipment, net ($0 and $1,463 attributable to a consolidated VIE)	90,953	97,259
Commodity derivatives	9,078	544
Loan origination cost, net	2,468	3,142
Prepaids and other	1,059	452
Total Assets	$417,034	$903,279
Liabilities, Preferred Units and Partners' Equity
Current Liabilities
Accounts payable	$1,629	$17,780
Oil and gas payable	17,421	27,543
Commodity derivatives	974	11,761
Other current liabilities	54,319	29,511
Current portion of deferred gain on oil gathering system	2,625	2,625
Current portion of long-term debt, net	129,994	129,948
Total current liabilities	206,962	219,168
Line of credit	87,500	138,000
Term loans, net	147,933	147,436
Deferred gain on oil gathering system	24,500	27,125
Commodity derivative	4,775	3,815
Other long-term liabilities	295	-
Asset retirement obligation	5,327	3,664
Deferred tax liability	46	133
Total Liabilities	477,338	539,341
Commitments and contingencies (Note 11)
Redeemable Series B Preferred Units, net	518,562	451,003
Equity
Partners' Equity (deficit)	(599,205)	(110,234)
Noncontrolling interest	20,339	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)

2020	2019
Revenues
Oil sales	$139,776	$200,419
Natural gas sales	10,627	8,942
Field service revenue	8,450	20,777
Gain (loss) on derivative instruments, net	93,256	(30,148)
Total revenues	252,109	199,990
Costs and expenses
Lease operating expenses	41,988	24,800
Repairs	4,820	6,061
Production taxes	6,994	9,516
Transportation and marketing	1,868	1,005
Field service expenses	11,677	26,521
Depreciation, depletion and amortization	106,047	96,783
Impairment of oil and gas properties	457,502	-
General and administrative	7,477	7,027
Total operating expenses	638,373	171,713
(Loss) income from operations	(386,264)	28,277
Other income (expense)
Gain on sale of saltwater disposal system	-	136,342
Other income	2,882	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 expense	81	-
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 interest	550	(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 Partner	Series 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 activities	2020	2019
Net (loss) income	($423,514)	$119,395
Adjustments to reconcile net income to cash used in operating activities:
Depreciation, depletion, and amortization	106,047	96,783
Impairment of oil and gas properties	457,502	-
Deferred loan cost amortization	1,826	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 issuance	1,411	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 receivable	20,098	(20,166)
Accounts receivable - affiliate	9,499	(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 other	10,913	(13,751)
Net cash provided by operating activities	121,512	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 credit	44,000	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 period	22,501	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:

2020	2019
Inventory	$1,039	$212
Other	435	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:

2020	2019
Accrued capital expenditures	$14,215	$14,268
Lease operating expenses payable	12,042	10,029
Liability for drilling costs prepaid by joint interest partners	21,927	1,098
Other	6,430	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):

2020	2019
Asset retirement obligation, January 1	$3,664	$575
Liabilities incurred	231	650
Liabilities sold	-	(49)
Liabilities settled	(281)	(1,379)
Changes in estimates	1,407	3,628
Accretion expense	306	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):

2020	2019
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 properties	273,167	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 equipment	4,013	3,942
Field service assets	131,872	120,032
Accumulated depreciation	(44,932)	(28,178)
Total net other property and equipment	90,953	95,796
Total other property and equipment, net	90,953	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):

2020	2019
Commodity derivative assets
Current portion	$14,263	$638
Long-term portion	9,078	544
23,341	1,182
Commodity derivative liabilities
Current portion	974	11,761
Long-term portion	4,775	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:

2020	2019
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
2021	2022	2023
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
2020	2021	2022
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.

16

NOTE 6. LINE OF CREDIT AND TERM LOAN FACILITIES

Debt as of December 31 (in thousands):

2020	2019
Reserves-based line of credit	$87,500	$138,000
Term loan - HPS	150,000	150,000
Term loan - Blackstone	130,000	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.

18

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.

19

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 issuance	1,409
Interest earned	57,923
Balance as of December 31, 2019	$451,003
Accretion of discount on issuance	1,411
Interest earned	66,148
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, 2019	79,559
Units granted during 2019	7,621
Forfeitures	-
Units outstanding as of December 31, 2019	87,180
Units granted during 2020	-
Forfeitures	-
Units outstanding as of December 31, 2020	87,180

The following summarizes the limited partner units issued and outstanding as of December 31, 2020:

Partnership Class	Description	Units Outstanding
Preferred Limited Partners
Series A Preferred	Non-voting, perpetual, 8% priority distribution, convertible to A-1 Common.	65,999
Series B Preferred	Non-voting, 13.5% cumulative and compounding quarterly. Distribution paid in additional Series B preferred units.	518,562
Common Limited Partners
Class A	Voting, 9% compounded preferred return, subject to 25% reversion to Class B after an 19% internal rate of return (IRR).	6,667
Class A-1	Issued upon conversion by Series a preferred holder, voting, subject to 30% reversion to Class E after a 20% IRR.	-
Class B	Founders and management units, voting	108,929
Class C	Management profit participation units, voting. 10,000 units are authorized with 0 outstanding.	-
Class D	Director units, profit participation units contingent upon Series A Preferred conversion to Class A-1 Common	2,570
Class E	Management 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 G	Management 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):

2020	2019
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):

2020	2019
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, 2020	December 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, 2020	December 31, 2019
Acquisition costs
Proved oil and gas properties	$14	$7
Unproved oil and gas properties	3,237	3,135
Development costs	88,801	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, 2020	December 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

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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:

Oil	Natural Gas	NGLs	Total
(MBbls)	(MMcf)	(MBbls)	(MBOE)
Balance, January 1, 2019	53,691	61,649	13,160	77,126
Revisions	(11,462)	(2,374)	(1,972)	(13,830)
Extensions	32,720	41,956	7,622	47,335
Divestitures of reserves	(29)	(33)	(8)	(42)
Production	(3,771)	(4,015)	(738)	(5,178)
Balance, December 31, 2019	71,149	97,183	18,064	105,411
Revisions	(26,722)	(26,490)	(5,010)	(36,147)
Extensions	14,225	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, 2020	54,810	88,329	16,338	85,870

Oil	Natural Gas	NGLs	Total
Proved developed and undeveloped reserves:	(MBbls)	(MMcf)	(MBbls)	(MBOE)
Developed as of December 31, 2018	10,818	14,166	3,177	16,356
Undeveloped as of December 31, 2018	42,873	47,483	9,983	60,770
Balance at December 31, 2018	53,691	61,649	13,160	77,126
Developed as of December 31, 2019	16,616	24,717	4,529	25,265
Undeveloped as of December 31, 2019	54,533	72,466	13,535	80,146
Balance at December 31, 2019	71,149	97,183	18,064	105,411
Developed as of December 31, 2020	12,958	24,419	4,509	21,537
Undeveloped as of December 31, 2020	41,852	63,910	11,829	64,333
Balance at December 31, 2020	54,810	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.

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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.

Oil	Natural Gas	NGLs
($/Bbl)	($/Mcf)	($/Bbl)
December 31, 2020 (Average)	36.18	-0.005	8.34
December 31, 2019 (Average)	46.51	-0.154	18.14

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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, 2020	December 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 flows	617,924	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,
2020	2019
Standardized measure, beginning of year	$833,401	$794,839
Net change in prices and production costs	(179,308)	59,012
Changes in future development costs	382,499	262,594
Oil and gas sales, net of production costs	(94,733)	(171,724)
Extensions and discoveries	61,236	378,088
Divestitures of reserves	(222)	(431)
Revisions of previous quantity estimates	(226,579)	(154,147)
Development costs incurred during the period	35,167	127,944
Accretion of discount	83,340	79,484
Changes in timing and other	(606,662)	(542,258)
Standardized measure, end of year	$288,139	$833,401

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