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	3
Condensed Consolidated Statements of Operations	4
Condensed Consolidated Statements of Changes in Partners’ Equity (Deficit)	5
Condensed Consolidated Statements of Cash Flows	6
Notes to the Unaudited Condensed Consolidated Financial Statements	7

PRIMEXX ENERGY PARTNERS, LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

UNAUDITED

(in thousands)

	September 30, 2021	December 31, 2020
Assets
Current Assets
Cash and cash equivalents	$11,724	$7,253
Trade accounts receivable	33,661	17,028
Accounts receivable - affiliate	6,993	1,350
Prepaids and other	1,442	415
Commodity derivatives	1,712	14,263
Total current assets	55,532	40,309
Property, plant and equipment, net:
Oil and gas properties, full cost method of accounting	361,000	273,167
Other property and equipment, net	83,510	90,953
Commodity derivatives	6,161	9,078
Loan origination cost, net	1,870	2,468
Prepaids and other	1,136	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 payable	34,976	17,421
Commodity derivatives	39,477	974
Other current liabilities	40,632	54,319
Current portion of deferred revenue	2,797	2,625
Current portion of long-term debt, net	129,999	129,994
Total current liabilities	267,682	206,962
Line of credit	148,500	87,500
Term loans, net	148,389	147,933
Deferred revenue	22,531	24,500
Commodity derivatives	29,707	4,775
Other long-term liabilities	308	295
Asset retirement obligation	5,327	5,327
Deferred tax liability	46	46
Total Liabilities	622,490	477,338
Commitments and contingencies (Note 10)
Redeemable Series B Preferred Units, net	575,325	518,562
Equity
Partners’ Equity (deficit)	(709,606)	(599,205)
Noncontrolling interest	21,000	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
	2021	2020
Revenues
Oil sales	$154,309	$109,594
Natural gas sales	28,858	5,878
Field service revenue	9,985	6,319
(Loss) gain on derivative instruments, net	(101,218)	111,877
Total revenues	91,934	233,668
Costs and expenses
Lease operating expenses	35,709	33,255
Repairs	7,121	3,347
Production taxes	8,642	5,371
Transportation and marketing	739	897
Field service expenses	9,474	10,878
Depreciation, depletion and amortization	51,073	79,771
Impairment of oil and gas properties	—	325,683
General and administrative	3,964	5,870
Total operating expenses	116,722	465,072
(Loss) from operations	(24,788)	(231,404)
Other income (expense)
Other income	2,174	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 expense	40	—
Total income tax expense	40	—
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 Partner	Series 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 Partner	Series 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 activities	2021	2020
Net (loss)	($50,000)	($259,794)
Adjustments to reconcile net (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization	51,073	79,771
Impairment of oil and gas properties	—	325,683
Deferred loan cost amortization	1,138	1,464
Deferred revenue amortization	(2,078)	(1,969)
Gain on sale of property - net	1	—
Accretion of discount on preferred unit issuance	1,058	1,058
Unrealized loss (gain) on derivative instruments	78,904	(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 payable	7,899	(15,697)
Oil and gas payable	17,556	(8,911)
Accrued liabilities and other	(34,832)	(12,280)
Deferred revenue	282	—
Net cash provided by operating activities	47,640	74,323
Cash flows from investing activities
Additions to oil and gas properties	(97,220)	(67,139)
Proceeds from sale of oil and gas properties	2,188	—
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 credit	109,000	40,500
Repayments of line of credit	(48,000)	(53,500)
Capitalized loan cost	(101)	(507)
Net cash provided by (used in) financing activities	56,864	(15,646)
Net change in cash and cash equivalents	4,471	(16,571)
Cash and cash equivalents, beginning of period	7,253	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, 2021	December 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 properties	361,000	273,167
Other property and equipment:
Other property and equipment:
Office and equipment	5,261	4,013
Field service assets	135,595	131,872
Accumulated depreciation	(57,346)	(44,932)
Total net other property and equipment	83,510	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, 2021	December 31, 2020
Commodity derivative assets
Current portion	$1,712	$14,263
Long-term portion	6,161	9,078
	7,873	23,341
Commodity derivative liabilities
Current portion	39,477	974
Long-term portion	29,707	4,775
	69,184	5,749
Net commodity derivatives	($61,311)	$17,592

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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, 2021	September 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
	2021		2022	2023	2024
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
	2021		2022	2023
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, 2021	December 31, 2020
Reserves-based line of credit	$148,500	$87,500
Term loan - HPS	150,000	150,000
Term loan - Blackstone	130,000	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”).

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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.

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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.

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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 issuance	1,058
Interest earned	55,705
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.

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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.

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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, 2021	September 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.

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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, 2021	September 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.

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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 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.

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