Permian Resources (PR) 8-K Entry into a Material Definitive Agreement

Exhibit 99.4

Report of Independent Auditors

To the Board of Managers

Luxe Energy LLC

We have audited the accompanying consolidated financial statements of Luxe Energy LLC and subsidiaries, which comprise the consolidated balance sheet as of December 31, 2020, and the related consolidated statements of operations, members’ equity and cash flows for the year then ended, and the related notes to the consolidated financial statements.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these financial statements in conformity with U.S. generally accepted accounting principles; this includes the design, implementation and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free of material misstatement, whether due to fraud or error.

Auditor’s Responsibility

Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit 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 financial statements are free of material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the 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 entity’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 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 financial statements referred to above present fairly, in all material respects, the consolidated financial position of Luxe Energy LLC and subsidiaries at December 31, 2020, and the consolidated results of its operations and its cash flows for the year then ended in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Denver, Colorado

May 13, 2021

1

LUXE ENERGY LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(IN THOUSANDS)

	December 31, 2020
	(in thousands)
ASSETS
Current assets
Cash and cash equivalents		68,129
Accounts receivable, net of allowance for doubtful accounts of $8,980 and $0, respectively		26,400
Derivative instruments		—
Prepaid expenses and other		259
Total current assets		94,788
Oil and natural gas properties, other property and equipment
Oil and natural gas properties, successful efforts method		770,368
Accumulated depreciation, depletion and amortization		(159,710	)
Unproved oil and natural gas properties		192,537
Other property and equipment, net of accumulated depreciation of $2,164 and $1,746, respectively		13,619
Total property and equipment, net		816,814
Noncurrent assets
Derivative instruments		—
Other noncurrent assets		6,823
Total assets		918,425
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable		1,333
Accrued Expenses		17,306
Revenue and royalties payable		22,484
Current portion of long-term debt		—
Derivative instruments		11,304
Other liabilities		3,435
Total current liabilities		55,862
Noncurrent liabilities
Revolving credit facility		—
Term loan		62,549
Asset retirement obligations		3,352
Deferred tax liability		2,272
Derivative instruments		2,700
Deferred royalty payment and drilling incentive		24,239
Other long-term liabilities		—
Total liabilities		150,974
Members’ equity		767,451
Total liabilities and members’ equity		918,425

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

2

LUXE ENERGY LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(IN THOUSANDS)

	December 31, 2020
Revenues
Oil sales		97,500
Natural gas sales		8,084
Natural gas liquid sales		4,429
Other Revenues		—
Total revenues		110,013
Operating expenses
Lease operating expenses		44,542
Production taxes		4,589
Depreciation, depletion, amortization and accretion of asset retirement obligations		82,456
Impairment and abandonment expense		56,155
General and administrative expenses		10,856
Bad debt expenses		8,980
Total operating expenses		207,578
Gain on sale of oil and natural gas properties		(3,717	)
Total operating loss		(93,848	)
Other income (expense)
Interest expense		(9,327	)
Net gain (loss) on derivative instruments		72,969
Other income		423
Total other income (expense)		64,065
Income tax expense		(2,272	)
Net loss	$	(32,055	)

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

3

LUXE ENERGY LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF MEMBERS’ EQUITY

(IN THOUSANDS)

	Total Members’ Equity
Balance at December 31, 2019	$	674,506
Contributions		125,000
Net loss		(32,055	)
Balance at December 31, 2020	$	767,451

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

4

LUXE ENERGY LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(IN THOUSANDS)

	For the Year Ended December 31, 2020
	(in thousands)
Cash flows from operating activities
Net loss	$	(32,055	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Accretion of asset retirement obligations		140
Depreciation, depletion and amortization		82,316
Gain on sale of oil and natural gas properties		(3,717	)
Amortization of drilling incentive		184
Deferred royalty payment		24,724
Amortization of deferred royalty payment		1,530
(Gain) loss on derivative instruments		(72,969	)
Net cash received (paid) for derivative settlements		89,399
Deferred taxes		2,272
Unproved property impairment		56,120
Amortization of debt issuance costs		519
Bad debt expense		8,980
Changes in operating assets and liabilities:
Accounts receivable		(13,318	)
Prepaid and other assets		670
Accounts payable and other liabilities		(4,691	)
Other liabilities		28,975
Net cash provided by operating activities		169,079
Cash flows from investing activities
Acquisition of oil and natural gas properties		(5,508	)
Development of oil and natural gas properties		(100,990	)
Proceeds from sales of oil and natural gas properties and other assets		33
Purchases of other property and equipment		(330	)
Acquisitions of Land		—
Net cash used in investing activities		(106,795	)
Cash flows from financing activities
Capital contributions		125,000
Proceeds from revolving credit facility		—
Repayment of revolving credit facility		(140,583	)
Proceeds from term loan		—
Cost of debt financing		(374	)
Net cash (used in) provided by financing activities		(15,957	)
Increase in cash and cash equivalents		46,327
Cash and cash equivalents, beginning of period		21,802
Cash and cash equivalents, end of period	$	68,129
Supplemental disclosure of cash flow information:
Cash paid for interest	$	3,000
Supplemental disclosure of noncash activity:
Development of oil and natural gas properties—changes in related accruals	$	15,674

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

5

LUXE ENERGY LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Organization and Nature of Operations

Luxe Energy LLC, a Delaware limited liability company (“Luxe”), and its subsidiaries (collectively, “the Company”) was formed on April 30, 2015. The Company is an oil and gas exploration and production company focused on the acquisition, development, exploration and exploitation of unconventional oil and natural gas reserves in liquids rich basins in the Permian Basin.

Note 2—Basis of Presentation and Significant Accounting Policies

Basis of Presentation

The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Our significant accounting policies are discussed below. All intercompany accounts and transactions were eliminated in consolidation.

Certain prior period amounts have been reclassified to conform to the current period presentation.

Segment Information

The Company operates in only one industry segment, which is the exploration and production of oil, natural gas and natural gas liquids (“NGLs”). All of its operations are conducted in one geographic area of the United States. All revenue are derived from customers located in the United States.

Use of Estimates

The preparation of the Company’s consolidated financial statements in conformity with GAAP requires the Company’s management to make estimates and judgements that affect the reported amounts of assets, liabilities, revenues and expenses, and disclosures of commitments and contingencies. Areas of significance requiring the use of management’s judgement include the estimation of proved oil and natural gas reserves used in calculating depletion, cash flow estimates used in impairment tests of long-lived assets, the estimation of future abandonment obligations used in recording asset retirement obligations, fair value measurements and contingencies. The Company evaluates its estimates on an on-going basis and bases them on historical experience and various other assumptions the Company believes to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions.

The process of estimating quantities of oil and gas reserves is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering, and economic data. The data for a given field may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that our reserve estimates represent the most accurate assessments possible, subjective decisions, and available data for our various fields make these estimates generally less precise than other estimates included in financial statement disclosures.

Cash and cash equivalents

Cash and cash equivalents consist of cash in banks and investments readily convertible into cash, which have original maturities of three months or less. The carrying value of cash and cash equivalents approximates fair value.

6

Oil and Natural Gas Properties

The Company’s oil and natural gas producing activities are accounted for using the successful efforts method of accounting. Under this method, the costs incurred to acquire, drill and complete development wells are capitalized to proved properties. Exploration costs, including personnel and other internal costs, geological and geophysical expenses, delay rentals for oil and natural gas leases and costs associated with unsuccessful lease acquisitions are charged to expense as incurred. Costs of drilling exploratory wells are initially capitalized but are charged to expense if the well is determined to be unsuccessful. As of December 31, 2020, no costs were capitalized in connection with exploratory wells in progress. Costs to operate, repair and maintain wells and field equipment are expensed as incurred.

Proved Properties

Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing oil and natural gas are capitalized. All costs incurred to drill and equip successful exploratory wells, development wells, development-type stratigraphic test wells and service wells, including unsuccessful development wells, are capitalized. Capitalized costs are depleted on a unit-of production method based on proved oil, natural gas and NGL reserves.

Net carrying values of retired, sold or abandoned properties that constitute less than a complete unit of depreciable property are charged or credited, net of proceeds, to accumulated depletion, depreciation and amortization and accretion of asset retirement unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized. Gains or losses from the disposal of complete units of depreciable property are recorded in the Consolidated Statements of Operations.

The Company reviews its proved oil and natural gas properties for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying amount of such property. There were no impairments of proved oil and natural gas properties for the year ended December 31, 2020.

Unproved Properties

Unproved properties consist of costs to acquire undeveloped leases as well as costs to acquire unproved reserves. Acquisition costs associated with the acquisition of non-producing leaseholds are recorded as unproved leasehold costs and capitalized as incurred. These consist of costs incurred in obtaining a mineral interest or right in a property, such as a lease in addition to options to lease, broker fees, recording fees and other similar costs related to acquiring properties. Leasehold costs are classified as unproved until proved reserves are discovered on or otherwise attributed to the property, at which time related costs are transferred to proved oil and natural gas properties.

The Company evaluates significant unproved properties for impairment on a property-by-property basis, and any impairment in value is charged to expense. Impairment is assessed based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage. Impairment of unproved properties was $56.1 million as of December 31, 2020.

Other Property and Equipment

Other property and equipment such as office furniture and equipment, buildings, vehicles and other computer hardware and software is recorded at cost. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets ranging from three to twenty years. Major renewals and improvements are capitalized while expenditures for maintenance and repairs are expensed as incurred. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounts.

7

Asset Retirement Obligations

The Company recognizes the present value of the fair value of liabilities for retirement obligations associated with tangible long-lived assets in the period in which there is a legal obligation associated with the retirement of such assets and the amount can be reasonably estimated. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. This liability includes costs related to the abandonment of wells, the removal of facilities and equipment, and site restorations. In periods subsequent to the initial measurement of an asset retirement obligation at present value, a period-to-period increase in the carrying amount of the liability is recognized as accretion expense, which represents the effect of the passage of time on the amount of the liability. An equivalent amount is added to the carrying amount of the liability. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement capitalized cost. Capitalized costs are included as a component of the depletion, depreciation and amortization (DD&A) calculations. Cash payments for settlements of retirement obligations are classified as cash used in operating activities in the accompanying consolidated statements of cash flows. For additional discussion, please refer to Note 9—Asset Retirement Obligations.

Derivative Financial Instruments

The Company’s derivative contracts are recorded on the consolidated balance sheets at fair value and records changes in the fair value of derivatives in current earnings as they occur. The Company’s derivatives have not been designated as hedges for accounting purposes. For additional discussion, please refer to Note 7—Derivative Financial Instruments.

Revenue Recognition

Revenue is recognized from the sales of oil, gas, and NGLs when the customer obtains control of the product, when we have no further obligations to perform related to the sale. All of our sales of oil, gas, and NGLs are made under contracts, which typically include variable consideration based on monthly pricing tied to local indices and monthly volumes delivered. The nature of our contracts with customers does not require us to constrain that variable consideration or to estimate the amount of transaction price attributable to future performance obligations for accounting purposes. Transportation and gathering fees included in the contract incurred after control transfers are included as a reduction to the transaction price. Performance obligations are met at a point-in-time through monthly delivery of oil, gas, and/or NGLs. We receive payment for product sales one to two months after delivery.

At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from customers are accrued in accounts receivable in the consolidated balance sheets. Variances between the Company’s estimated revenue and actual payments are recorded in the month the payment is received; however, differences have been historically insignificant.

Revenue from sale of natural gas is recorded on the basis of gas actually sold by the Company. If the Company’s aggregate sales volumes for a well are greater (or less) than our proportionate share of production from the well, a liability (or receivable) is established to the extent there are insufficient proved reserves available to make-up the overproduced (or underproduced) imbalance. Imbalances have not been significant in the periods presented.

Incentive Units

Incentive units are accounted for as profit interests under the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 710, Compensation—General and ASC Topic 718, Compensation—Stock Compensation. No incentive compensation expense was recorded at December 31, 2020, because it was not probable that the performance criterion would be met. For additional discussion, please refer to Note 10—Members’ Equity and Incentive Units.

8

Income Taxes

The Company is a limited liability company treated as a pass-through entity for U.S. federal income tax purposes. Accordingly, members are taxed on their allocable share of taxable income or loss as determined under the Company’s operating agreement.

Beginning January 1, 2018, new rules apply to IRS audits of partnerships. Under these rules, adjustments resulting from an IRS audit may be assessed at the partnership level on behalf of its members. As of December 31, 2020, the Company has no tax years under audit.

The Company is subject to the Texas margin tax, at a statutory rate of .75% of income. Deferred tax assets and liabilities are recognized for future Texas margin tax consequences attributable to differences between the financial statement carrying amount of existing assets and liabilities and their respective Texas margin tax bases. A deferred tax liability of $2.3 million was recorded as of December 31, 2020 related solely to carrying value differences associated with oil & gas property for book and tax purposes.

The Company evaluates the tax positions taken or expected to be taken in the course of preparing its 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 Company’s management does not believe that any tax positions included in its tax returns would not meet this threshold. The Company’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.

Recently Issued Accounting Standards

In February 2016, the FASB issued ASU 2016-02, Leases. This update applies to any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. While there were no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. The FASB issued ASU 2020-05, which defers the effective date for private entities with fiscal years beginning after December 15, 2021, and interim reporting periods beginning after December 15, 2022. Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The Company is reviewing the provisions of ASU 2016-02 to determine the impact on its consolidated financial statements and related disclosures.

Note 3—Accounts Receivable and Accrued Expenses

Accounts receivable are comprised of the following for the period indicated (in thousands):

	December 31, 2020
Oil, natural gas and NGL sales	$	15,705
Joint interest billings		17,173
Allowance for doubtful accounts		(8,980	)
Other		2,502
Total	$	26,400

Accrued expenses are comprised of the following for the period indicated (in thousands):

	December 31, 2020
Accrued capital expenditures	$	6,573
Accrued lease operating expenses		8,234
Other		2,499
Total	$	17,306

9

Revenue payables are comprised of the following for the period indicated (in thousands):

	December 31, 2020
Revenue Suspense	$	17,411
Accrued transportation, processing, gathering and other operating expense		4,496
Accrued production taxes		412
Other		165
Total	$	22,484

Note 4—Acquisitions and Divestitures

2020 Acquisition Activity

During the year ended December 31, 2020, the Company acquired from third-parties, a combination of new leases and additional working interests in wells it operates through a number of separate, individually insignificant negotiated transactions for aggregate cash consideration of $5.5 million, all of which were accounted for as asset acquisitions. The Company reflected the total consideration as $5.5 million in unproved oil and natural gas properties.

Note 5—Other Liabilities

In August 2020, in connection with the SUA, the Company exercised the put option in exchange for the water royalties the Company had acquired from WaterBridge Texas Midstream LLC (“WaterBridge”). In exchange for relinquishing the water royalties, the Company received $26.3 million from WaterBridge. The deferred royalty payment will be recognized as a deduction to lease operating expenses and capital expenditures over 10 years in connection with the Water Transaction, refer to Note 4—Acquisitions and Divestitures. As of December 31, 2020, the total deferred royalty payment is $24.7 million, of which $3.1 million is included as other current liabilities and $21.7 million is included in deferred royalty payment and drilling incentive on the accompanying consolidated balance sheet.

In 2018, the Company signed a natural gas gathering and processing agreement with Salt Creek Midstream LLC, a Delaware limited liability company (“Salt Creek”). As part of the natural gas gathering and processing agreement Salt Creek provided Luxe the opportunity to earn drilling incentive payments for up to $12.5 million by November 20, 2023, for each well the Company drills, completes, and delivers gas. During the year ended December 31, 2020, the Company earned $3.1 million of incentive payments. The Company deferred recognition of the incentive payments and will recognize it over 10 years as a deduction to gathering, processing and transportation expense, which is presented net of revenue on the accompanying consolidated income statement. As of December 31, 2020, the deferred amount is $2.9 million of which $0.4 million is included as other current liabilities and $2.5 million is included in deferred royalty payment and drilling incentive on the accompanying consolidated balance sheet.

Note 6—Long-Term Debt

Credit Facility

On May 10, 2018, the Company entered into a credit agreement with JPMorgan Chase Bank, N.A. and Wells Fargo Securities, LLC (“Creditors”) as Joint Lead Arrangers (“the Credit Agreement”). The Credit Agreement, which allows for a maximum borrowing base of $175.0 million, had an original borrowing base of $55.0 million and a maturity date of May 10, 2023. At December 31, 2020, the Credit Agreement, as amended, had a borrowing base of $85.0 million, with $85.0 million in unused borrowing capacity, net of outstanding letters of credit. The borrowing base is redetermined semi-annually on each May 1 and November 1.

10

Borrowings under the revolving credit facility comprising of Eurodollar Loans shall bear interest at the Adjusted LIBOR Rate plus an applicable margin ranging from 250 to 350 basis points, depending on the percentage of the borrowing base utilized. Borrowings under the revolving credit facility comprising of Alternate Base Rate Loans shall bear interest at the Alternate Base Rate plus an applicable margin ranging from 75 to 175 basis points, depending on the percentage of the borrowing base utilized. The Company also pays a commitment fee on the unused amounts under its facility of a range of 37.5 to 50.0 basis points, depending on the percentage of the borrowing base utilized. The Company may repay any borrowing amounts prior to the maturity date without any premium or penalty other than the customary LIBOR breakage costs.

The Credit Agreement requires the Company to maintain compliance with the following financial ratios: (i) a current ratio of not less than 1.0 to 1.0 and (ii) a leverage ratio, which, as defined in the Credit Agreement, as the ratio of Total Net Debt to Consolidated EBITDAX of not greater than 3.50 to 1.00 commencing with the fiscal year December 31, 2020. The Credit Agreement also contains restrictive covenants that limit the Company’s ability to, among other things: incur additional indebtedness; make investments, loans, and advances; make or declare dividends and distributions; enter into commodity hedges exceeding a specified percentage of our expected production; enter into interest rate hedges exceeding a specified percentage of its outstanding indebtedness; incur liens; sell assets; engage in transactions with affiliates; and enter into take-or-pay agreements exceeding a specified percentage of our expected production. For the year ended December 31, 2020, the Company received a waiver from its Creditors that permitted liens to remain in place against certain non-operated oil and gas properties owed by the Company. These liens exceeded the threshold amount permitted by the Credit Agreement. Refer to Note 11—Commitments and Contingencies for details of the liens. At December 31, 2020, the Company was in compliance with these covenants.

Debt issuance costs consist of costs directly associated with obtaining credit with financial institutions. These costs are capitalized and are included in other non-current assets on the consolidated balance sheet. The capitalized costs are amortized over the life of the credit agreement, which approximates the effective-interest method. Any unamortized debt issuance costs are expensed in the year when the associated debt instrument is terminated. Amortization expense for debt issuance costs was $0.4 million for the year ended December 31, 2020 and is included in interest expense in the consolidated statements of operations.

DrillShip Agreement

On October 30, 2019, the Company entered into a Note Purchase Agreement (“NPA”) with EIG Global Energy Partners (“EIG”) to fund the development of 25 wellbores (“DrillShip Wells”). At closing, the Company contributed 13 wellbores (“Contributed Wells”) into a wholly owned, unrestricted subsidiary, Luxe DrillShip Operating, LLC (“Luxe DrillShip”). The Company also committed to contribute to Luxe DrillShip 12 additional wellbores in two separate tranches upon successfully passing as asset coverage test. Luxe DrillShip is primarily funded by a $175 million commitment (“Notes”) from EIG. The Notes mature on October 30, 2024 and are non-recourse to the other subsidiaries of the Company.

As part of the NPA, the Company is required to fund 15% and Luxe DrillShip is required to fund 85% of the development capital associated with the Contributed Wells. If a monthly asset coverage test is triggered and met, the Company will receive 15% of the monthly cash flows from the Contributed Wells. Once the Notes achieve a certain payout threshold, the interests in the wellbores fully revert to the Company. The repayment of the Notes at a predetermined value is required under the NPA at the earlier of maturity of the Notes on October 30, 2024, a change of control by the Company, or an event of default. Luxe DrillShip also pays and 8% interest rate that is attributable to the payout threshold.

At December 31, 2020, Luxe DrillShip had approximately $59.4 million Notes outstanding and the monthly asset coverage ratio had not been triggered. The total amount of assets collateralized by the Notes was $110.8 million at December 31, 2020. Debt issuance costs of $3.1 million were recorded as debt issuance costs and will be amortized over the life of the Notes.

11

At closing, the Company also conveyed an overriding royalty interest on the Contributed Wells to EIG that had a fair value of $4.3 million. During the year ended December 31, 2020 this balance was reclassed as a debt payable, the outstanding balance as of December 31, 2020 is $3.1 million, included in the Term loan on the accompanying Consolidated Balance Sheet.

Note 7—Derivative Financial Instruments

The Company uses derivative instruments to mitigate volatility in commodity prices. While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future cash flow from favorable price changes.

The Company may use commodity derivative instruments known as fixed price swaps to realize a known price for a specific volume of production, basis swaps to hedge the difference between the index price and a local index price, or collars to establish fixed price floors and ceilings. All transactions are settled in cash with one party paying the other for the resulting difference in price multiplied by the contract volume.

The following table summarizes the approximate volumes and average contract prices of swap contracts the Company had in place as of December 31, 2020:

	2021			2022
Crude Oil Fixed Price Swaps:
Notional volumes (Bbl)		923,163			580,067
Weighted average floor price ($/Bbl)	$	43.44		$	44.98
Crude Oil Basis Swaps:
Notional volumes (Bbl)		923,163			580,067
Weighted average fixed price ($/Bbl)	$	0.25		$	0.30
Natural Gas Fixed Price Swaps:
Notional volumes (MMBtu)		6,592,362			4,327,903
Weighted average fixed price ($/MMBtu)	$	2.61		$	2.54
Natural Gas Basis Fixed Price Swaps:
Notional volumes (MMBtu)		6,592,362			4,327,903
Weighted average fixed price ($/MMBtu)	$	(0.70	)	$	(0.55	)
Natural Gas Liquids Fixed Price Swaps:
Notional volumes (Bbl)		397,201			294,501
Weighted average fixed price ($/Bbl)	$	18.90		$	19.60

Derivative Gains and Loses

Net gains and losses on our derivative instruments are a function of fluctuations in the underlying commodity index prices as compared to the contracted prices and the monthly cash settlements (if any) of the instruments. The Company has elected not to designate its derivatives as hedging instruments for accounting purposes and, therefore, the Company does not apply hedge accounting treatment to its derivative instruments. Consequently, changes in the fair value of its derivative instruments and cash settlements on the instruments are included as a component of operating costs and expenses as either a net gain or loss on derivative instruments. Cash settlements of our contracts are included in cash flows from operating activities in our statements of cash flows.

The following table presents gains and losses for derivative instruments for the period indicated:

	For the Year Ended December 31, 2020
Net gain (loss) on derivative instruments (in thousands)		72,969

12

Derivative Fair Value

The Company’s commodity derivatives are carried at their fair value on the consolidated balance sheets using level 2 inputs and are subject to master netting arrangements, which allows the Company to offset recognized asset and liability fair value amounts on contracts with the same counterparty.

The table below presents the amounts and classification of the Company’s derivative assets and liabilities in the consolidated balance sheets, including commodity and interest swaps, as well as the gross recognized derivative assets, liabilities and amounts offset:

	Balance Sheet Classification		Gross Amounts		Netting Adjustments			Net Amounts Presented on the Balance Sheet
December 31, 2020:
Assets:
Derivative instruments		Current assets	$	1,630	$	(1,630	)	$	—
Derivative instruments		Non-current assets		567		(567	)		—
Total assets			$	2,197	$	(2,197	)	$	—
Liabilities:
Derivative instruments		Current liabilities	$	12,934	$	(1,630	)	$	11,304
Derivative instruments		Non-current liabilities		3,267		(567	)		2,700
Total liabilities			$	16,201	$	(2,197	)	$	14,004

The Company is exposed to financial risks associated with our derivative contracts from non-performance by our counterparties. The Company minimizes the credit risk from counterparties by: (i) limiting its exposure to any single counterparty; and (ii) monitoring the creditworthiness of its counterparties on an ongoing basis. The Company’s counterparties do not require it to post collateral for its derivative liability positions, nor does the Company require its counterparties to post collateral for its benefit. The Company believes all counterparties are currently acceptable credit risks. As of December 31, 2020, the Company had commodity derivative contracts with four counterparties, all of which are members of the Company’s credit facility lender group.

Note 8—Fair Value Measurements

Assets and Liabilities Measured at Fair Value

The Company has categorized its assets and liabilities measured at fair value, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. Level 1 inputs are the highest priority and consist of unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 are inputs other than quoted prices that are observable for the asset or liability, either directly or indirectly. Level 3 are unobservable inputs for an asset or liability.

The following table is a listing of the Company’s assets and liabilities that are measured at fair value and where they were classified within the fair value hierarchy as of December 31, 2020 (in thousands):

	Level 1		Level 2		Level 3
Assets:
2020 Derivative instruments(1)	$	—	$	—	$	—
Liabilities:
2020 Derivative instruments(1)	$	—	$	14,004	$	—

(1) This represents a financial asset or liability that is measured at fair value on a recurring basis.

13

Assessing the significance of a particular input to the fair value measurement requires judgment, including the consideration of factors specific to the asset or liability. The fair value of our derivative instruments (Level 2) was estimated using discounted cash flow. These models use certain observable variables including forward prices, volatility curves, interest rates, and credit ratings and spreads. The fair value estimates are adjusted relative to non-performance risk as appropriate. Refer to Note 7—Derivative Financial Instruments for further information on the fair value of our derivative instruments.

Nonrecurring Fair Value Measurements

The fair value measurements of assets acquired and liabilities assumed are measured on a nonrecurring basis on the acquisition date using an income valuation technique based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs to the valuation of acquired oil and natural gas properties include estimates of: (i) reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices, including price differentials; (v) future cash flows; and (vi) a market participant-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation. Refer to Note 4—Acquisitions and Divestitures for additional information on the fair value of assets acquired during the year ended December 31, 2020.

The initial measurement of ARO at fair value is calculated using discounted cash flow techniques and is based on internal estimates of future retirement costs associated with long-lived assets. Significant Level 3 inputs used in the calculation of ARO include plugging costs and reserve lives. Refer to Note 9—Asset Retirement Obligations for additional information on the Company’s ARO.

Other Financial Instruments

The carrying amounts of our cash, accounts receivable, accounts payable and accrued expenses approximate fair value due to the short-term maturities and/or liquid nature of these assets and liabilities. The carrying values of the amounts outstanding under the revolving credit facilities approximate fair value because the variable interest rates are reflective of current market conditions.

The Company relied on current information including interest rates and the specific terms of the Notes to estimate the fair value. The fair value of the Notes on December 31, 2020 is the same as the carrying value, which approximates the principal less the unamortized discount, refer to Note 6—Long-Term Debt.

Accounts Receivable

Most of the Company’s accounts receivable balances are uncollateralized and result from transactions with other companies in the oil and natural gas industry. Concentration of customers may impact the Company’s overall credit risk because its customers may be similarly affected by changes in economic or other conditions within the industry. The Company conducts credit analyses prior to making any sales to new customers or increasing credit for existing customers and may require parent company guarantees, letters of credit, or prepayments when deemed necessary. For properties the Company operates, it typically has the right to realize amounts due to the Company from non-operators by netting the non-operators’ share of production revenues from those properties.

The Company routinely assesses the recoverability of all material accounts receivable and accrue a reserve to the allowance for credit losses based on its estimation of expected losses over the life of the receivables.

Major Customers

The Company is subject to credit risk resulting from the concentration of its oil, natural gas and NGL receivables with several significant purchasers. The future availability of a ready market for oil, natural gas and

14

NGLs depends on numerous factors outside the Company’s control, none of which can be predicted with certainty. The Company does not believe the loss of any single purchaser would materially impact its results of operations because oil, natural gas and NGLs are fungible products with well-established markets and numerous purchasers. For the year ended December 31, 2020, three purchasers accounted for approximately 78.8% of revenue.

Note 9—Asset Retirement Obligations

The following table summarizes the changes in the Company’s asset retirement obligations for the periods indicated (in thousands):

	December 31, 2020
Asset retirement obligations, beginning of period	$	930
Liabilities incurred(1)		70
Accretion expense		104
Revisions of estimated liabilities(2)		2,248
Asset retirement obligations, end of period	$	3,352

(1) Reflects liabilities incurred through drilling activities and acquisitions of drilled wells.

(2) Primarily reflects changes in estimated plug and abandonment costs.

Note 10—Members’ Equity and Incentive Units

Members’ Equity

The Company was formed with equity capital commitments from NGP XI U.S. Holdings, L.P. and Luxe management via Class A Equity. Following the divestiture of the significant majority of the Company’s assets on September 1, 2016, the Company distributed $472 million to Class A shareholders and terminated the Class A Incentive Units. As of December 31, 2020, $220.2 million of contributions relate to the original Class A Equity investment.

On October 5, 2016, the Company executed an Amended and Restated Limited Liability Company Agreement (the “A&R LLC Agreement”). The A&R LLC Agreement created a new class of equity (the “Class B Equity”) and received new Class B equity capital commitments from NGP XI U.S. Holdings, L.P. and Luxe management, respectively. In February 2017, NGP XI Luxe Holdings, L.P. created NGP XI Luxe Holdings, LLC as the investor in Luxe Energy LLC with the funds coming from the existing commitment from NGP.

As of December 31, 2020, NGP XI U.S. Holdings, LLC and Luxe management had contributed $801 million and $11.3 million, respectively, to Class B Equity.

The A&R LLC Agreement authorizes the issuance of Class B Member Company Interests and Incentive Interests. The Class B Member Company Interests each contain separate rights, privileges, preferences, restrictions and obligations as provided in the A&R LLC Agreement.

In general, cash distributions are allocated in accordance with the provisions of the A&R LLC Agreement whereby the Class B Members receive payment until they have received cumulative cash distributions equal to the amount of their respective cumulative capital contributed plus a preferred return. Once the capital and certain rate of returns are achieved, distributions will be made to Class B Members and the Incentive Interest holders in accordance with the A&R LLC Agreement. Subsequent to the preferred return, distributions allocable to Incentive Interest holders increase based on stated return thresholds.

15

Class B Member Company Interests

Class B Member Company Interests are issued in exchange for capital contributions by each Class B Member. Any distributions to Class B Members will be in accordance with the Class B Sharing Ratio, as defined in the A&R LLC Agreement. At December 31, 2020, the Class B Sharing Ratio was approximately 98.6% for NGP XI Luxe Holdings LLC and 1.4% for Luxe management’s aggregate Class B interests. At December 31, 2019, the Class B Sharing ratio was approximately 98.4% for NGP XI Luxe Holdings LLC and 1.6% for Luxe management’s aggregate Class B interests.

Incentive Units

The Incentive Interests are Company Interests that provide economic incentives to our employees who receive them. The Incentive Interests are intended to be “profits interests.” The Incentive Interests vest over a three-year or five-year period, as provided in the A&R LLC Agreement, and may be forfeited or repurchased by the Company under certain circumstances as set forth in the plan governing the Incentive Interests and individual Incentive Interests grant agreements.

The Incentive Interests do not represent a substantive class of equity. Due to the awards’ forfeiture provisions, the unit holders are primarily entitled to profit-sharing distributions while employed and such awards are forfeited upon voluntary termination. Accordingly, these Incentive Interests are accounted for as a profit-sharing arrangement pursuant to FASB ASC 710, Compensation—General.

The Company has granted Incentive Interests to select employees of the Company. The Incentive Interests are treated as conditionally vesting equity but are deemed to be a profit-sharing arrangement due to certain forfeiture or repurchase features of the plan. Award recipients may derive economic value in the instrument through profit sharing distributions. As such, the Company accounts for these Incentive Interests as profit-sharing arrangements and no liability or compensation expense will be recognized until amounts payable under such awards become probable and reasonably estimable.

For the year ended December 31, 2020, the Company recognized no compensation expense related to the Incentive Interests.

Note 11—Commitments and Contingencies

Commitments

The following is a schedule of minimum future lease payments with commitments that have initial or remaining non-cancelable lease terms in excess of one year as of December 31, 2020 (in thousands):

	Year Ending December 31,
2021	$	393
2022		297
2023		302
2024		311
2025		320
Total	$	1,623

Office Leases

The Company leases office space in Austin, Houston, and Midland, Texas. The Company recognized rent expense of $0.9 million for the year ended December 31, 2020.

16

Contingencies

The Company is subject to litigation and claims arising in the ordinary course of business. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. In the opinion of management, the results of such pending litigation and claims will not have a material effect on the results of operations, the financial position or the cash flows of the Company.

On November 8, 2019, the Company’s largest non-operated partner, MDC Energy, LLC (“MDC”) filed Chapter 11 bankruptcy. Prior to filing bankruptcy protection, some of MDC’s vendors placed statutory liens (“MDC Liens”) against the leases operated by MDC. The Company owned an interest in a portion of the leases that are subject to the MDC Liens. The Company has balances in accounts receivable and accounts payable with MDC that are pending the outcome of the bankruptcy proceedings. At December 31, 2020, the Company had a net receivable of $3.9 million due from MDC and expects to receive the amounts owed by MDC for revenues and joint interest billings during the next year. For the year ended December 31, 2020, the Company received a waiver from its Creditors to permit the temporary existence of liens related to the Company’s non-operated properties operated by MDC.

Note 12—Transactions with Affiliates

During the year-ended December 31, 2020, the Company shares certain general and administrative services with Luxe Minerals LLC and collects payments for any allocated expenses. The amount of general and administrative expense allocated to Luxe Minerals LLC during 2020 was $1.7 million. There were no outstanding accounts receivable with Luxe Minerals LLC as of December 31, 2020.

In July 2020, the Company entered into a Management Services Agreement with Camino Natural Resources, LLC, a Delaware limited liability company, and its subsidiaries (“Camino”). As compensation for services rendered in the management of the Luxe, Luxe pays Camino an annual management fee based on the Management Service Agreement. For the year ended December 31, 2020 Luxe paid $2.0 million in management fees, included in general and administrative expenses on the accompanying combined and consolidated income statement. As of December 31, 2020, accounts payable on the accompanying balance sheet includes $1.2 million to Camino, Note 3—Accounts Receivable and Accrued Expenses.

Note 13—Subsequent Events

On April 7, 2021, the Company paid off the outstanding debt and interest associated with the NPA for $56.8 million. At closing, the Company also purchased from EIG the originally conveyed overriding royalty interests on the Contributed Wells for $4.3 million. The initial accounting for this transaction is incomplete as of the date of this filing.

The Company entered into a Limited Consent and Seventh Amendment to the Credit Agreement with the requisite lenders to its Credit Facility on April 21, 2021, which provided an extension of time for the delivery of its audited and consolidated financial statements and related certificate of compliance for the year ended December 31, 2020 as required by Section 8.01(a) and 8.01(c) of the Credit Agreement until May 31, 2021. The Company received an additional waiver from its Creditors that permitted liens to remain in place against certain non-operated oil and gas properties owed by the Company. These liens exceeded the threshold amount permitted by the Credit Agreement.

The Company has evaluated subsequent events through May 13, 2021, the date the consolidated financial statements were available to be issued. No other subsequent events were identified requiring additional recognition or disclosure in the accompanying consolidated financial statements.

17

Supplemental Disclosure of Oil and Natural Gas Operations (unaudited)

Reserve Quantity Information

The following information represents estimates of the Company’s proved reserves. Proved oil and natural gas reserves were calculated based on the prices for oil and natural gas during the 12-month period before the reporting date, determined as the unweighted average of the first-day-of-the-month pricing. For oil and NGL volumes, the pricing that was used for estimates of the Company’s proved reserves as of December 31, 2020 and 2019 was $39.54 per Bbl and $55.85 per Bbl, respectively. For gas volumes, the pricing that was used for estimates of the Company’s proved reserves as of December 31, 2020 and 2019 was $1.99 per MMBtu and $2.58 per MMBtu, respectively. All prices have been adjusted for transportation, quality and basis differentials.

Subject to limited exceptions, proved undeveloped reserves may only be recognized if they relate to wells scheduled to be drilled within five years of the date of their initial recognition. This rule limited, and may continue to limit, the Company’s potential to record additional proved undeveloped reserves. Moreover, the Company may be required to write down its proved undeveloped reserves if it does not drill on those reserves within the required five-year timeframe. All of the Company’s recorded proved undeveloped reserves are scheduled to be drilled within five years of the date of their initial recognition.

The Company’s proved oil and natural gas reserves are all located in the United States, in the Permian Basin of West Texas. All of the estimates of the proved reserves at December 31, 2020 are based on reports prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers. Proved reserves were estimated in accordance with the guidelines established by the SEC and the FASB.

Oil and natural gas reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.

The following table provides the changes in the proved reserves for the period ended December 31, 2020:

	Oil			Gas			NGL			Total
	(MBbl)			(MMcf)			(MBbl)			(MBoe)
Total proved reserves at December 31, 2019		39,705			166,595			23,142			90,613
Revisions		(22,170	)		(8,004	)		(7,530	)		(31,034	)
Extensions and discoveries		4,627			32,632			3,053			13,119
Production		(2,592	)		(16,512	)		(1,292	)		(6,636	)
Total proved reserves at December 31, 2020		19,570			174,711			17,373			66,063
Proved Developed Reserves:
January 1, 2020		13,107			70,069			10,445			35,230
December 31, 2020		9,366			103,628			10,386			37,024
Proved Undeveloped Reserves:
January 1, 2020		26,598			96,526			12,697			55,383
December 31, 2020		10,204			71,083			6,987			29,038

The change in total proved reserves during 2020 was primarily the result of recording approximately 31 MMBoe of negative revisions. The negative revisions were primarily the result of an approximate 33 MMBoe

18

decrease related to the removal of proved undeveloped locations due to an adoption of a development plan and a decrease of approximately 2 MMBoe related to the decrease in commodity prices partially offset by an increase of 4 MMBoe related to well performance exceeding previous estimates. The Company recorded extensions and discoveries during 2020 of approximately 13 MMBoe which were a result of our successful drilling and completion program during 2020. The Company also had production of approximately 7 MMBoe,

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows is computed by applying the 12-month unweighted average of the first-day-of-the-month pricing for oil and natural gas (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved oil and natural gas reserves less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves (including cost for future dismantlement, abandonment and rehabilitation obligations), discounted using a rate of 10 percent per year to reflect the estimated timing of the future cash flows. Future income taxes are calculated by comparing undiscounted future cash flows to the tax basis of oil and natural gas properties plus any available carryforwards and credits and applying the applicable current tax rates to the difference.

Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of oil and natural gas properties. Estimates of fair value would also consider probable and possible reserves, anticipated future oil and natural gas prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is necessarily subjective and imprecise.

The following table provides the standardized measure of discounted future net cash flows of the at December 31, 2020:

	Year Ended December 31, 2020
	(in thousands)
Oil and gas producing activities:
Future cash inflows	$	1,190,309
Future production costs		(620,610	)
Future development costs		(185,957	)
Future income tax expense		(6,249	)
Future net cash flows		377,493
10% annual discount factor		(201,507	)
Standardized measure of discounted future net cash flows	$	175,986

19

The following table provides a rollforward of the standardized measure of discounted future net cash flows of the for the year ended December 31, 2020:

	Year Ended December 31, 2020
	(in thousands)
Oil and gas producing activities:
Balance, beginning of year	$	588,744
Extensions and discoveries		9,715
Previously estimated development costs incurred		54,689
Net changes in prices and production costs		(314,254	)
Oil and natural gas sales, net of production costs		(60,882	)
Changes in future development costs		24,349
Revisions of previous estimates		(158,859	)
Accretion of discount		52,104
Net change to income taxes		1,363
Changes in timing and other		(20,983	)
Standardized measure of discounted future net cash flows	$	175,986

20