Document


			Page
Independent Auditor's Report			3
Balance Sheets as of December 31, 2022 and 2021			5
Statements of Operations for the Years Ended December 31, 2022 and 2021			6
Statements of Changes in Member's Equity for the Years Ended December 31, 2022 and 2021			7
Statements of Cash Flows for the Years Ended December 31, 2022 and 2021			8
Notes to Financial Statements			9

We have audited the financial statements of Pecos Oil & Gas, LLC (the “Company”), which comprise the balance sheets as of December 31, 2022 and 2021, and the related statements of operations, changes in member’s equity, and cash flows for the years then ended, and the related notes to the financial statements.

In our opinion, the accompanying financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021, and the results of its operations and its cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America (GAAS). Our responsibilities under those standards are further described in the Auditor’s Responsibilities for the Audit of the Financial Statements section of our report. We are required to be independent of the Company and to meet our other ethical responsibilities, in accordance with the relevant ethical requirements relating to our audits. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Management is responsible for the preparation and fair presentation of the financial statements in accordance with accounting principles generally accepted in the United States of America, and for the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

In preparing the financial statements, management is required to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the Company’s ability to continue as a going concern within one year after the date that the financial statements are issued or available to be issued.

Our objectives are to obtain reasonable assurance about whether the financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable assurance is a high level of assurance but is not absolute assurance and therefore is not a guarantee that an audit conducted in

accordance with GAAS will always detect a material misstatement when it exists. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control. Misstatements are considered material if there is a substantial likelihood that, individually or in the aggregate, they would influence the judgment made by a reasonable user based on the financial statements.


	As of December 31, 2022	As of December 31, 2021
Assets	(in thousands)
Current assets:
Cash and cash equivalents	$ 12,785	$ 13,630
Accounts receivable	15,938	10,989
Inventory	1,322	—
Prepaids and other current assets	1,695	985
Derivative instruments	506	—
Total current assets	32,246	25,604
Oil and natural gas properties, successful efforts method:
Proved properties	192,051	150,516
Unproved properties	12,747	13,535
Less: Accumulated depreciation, depletion and amortization	(37,334)	(19,460)
Total oil and natural gas properties, net	167,464	144,591
Total assets	$ 199,710	$ 170,195

Liabilities and Member’s Equity
Current liabilities:
Accounts payable	$ 7,882	$ 1,892
Revenue payable	8,352	7,891
Accrued and other liabilities	1,793	952
Earnout liability	15,251	12,594
Derivative instruments	887	5,403
Asset retirement obligations	3,300	1,350
Total current liabilities	37,465	30,082
Related party note payable	100,609	94,122
Derivative instruments	—	20
Asset retirement obligations	7,869	11,446
Total liabilities	145,943	135,670
Commitment and contingencies (Note 8)
Member’s equity	53,767	34,525
Total liabilities and member’s equity	$ 199,710	$ 170,195


	For the Year Ended December 31, 2022	For the Year Ended December 31, 2021
	(in thousands)
Revenues:
Oil and natural gas sales, net	$ 113,414	$ 62,374
Total revenues	113,414	62,374
Operating expenses:
Lease operating	17,915	12,947
Production and ad valorem taxes	9,465	5,214
Depletion and accretion	23,470	15,245
General and administrative	5,189	4,966
Total operating expenses	56,039	38,372
Operating income	57,375	24,002
Other (expense) income:
Loss on derivative instruments	(13,117)	(18,602)
Loss on earnout liability	(3,804)	(12,097)
Gain on settlement of asset retirement obligations	226	265
Related party interest expense	(15,387)	(14,295)
Total other (expense) income, net	(32,082)	(44,729)
Net income (loss)	$ 25,293	$ (20,727)


	For the Year Ended December 31, 2022	For the Year Ended December 31, 2021
	(in thousands)
Cash flows from operating activities:
Net income (loss)	$ 25,293	$ (20,727)
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion and accretion	23,470	15,245
Gain on settlement of asset retirement obligations	(226)	(265)
Non-cash interest	6,487	14,295
Unit-based compensation expense	1,379	1,882
Loss on earnout liability	3,804	12,097
Loss on derivative instruments	13,117	18,602
Settlements on derivative instruments	(17,957)	(10,526)
Changes in operating assets and liabilities:
Accounts receivable	(4,949)	(7,613)
Inventory	(1,322)	—
Prepaids and other current assets	(912)	(852)
Accounts payable	2,948	490
Accrued and other liabilities	841	941
Revenues payable	461	4,856
Net cash provided by operating activities	52,434	28,425
Cash flows from investing activities:
Additions to oil and natural gas properties	(53,279)	(26,271)
Net cash used in investing activities	(53,279)	(26,271)
Cash flows from financing activities:
Borrowings under related party note payable	—	8,500
Net cash provided by financing activities	—	8,500
Net increase (decrease) in cash	(845)	10,654
Cash - Beginning of year	13,630	2,976
Cash - End of year	$ 12,785	$ 13,630

Supplemental disclosure of cash activity:
Cash paid for interest	$ (8,957)	$ —
Supplemental disclosure of noncash activity:
Changes in accrued capital expenditures	$ 505	$ —
Changes in asset retirement obligations	$ 12	$ (4,388)
Distribution of nonmonetary assets (Note 9)	$ (7,430)	$ —

Pecos Oil & Gas LLC (the "Company") was formed pursuant to the laws of the State of Delaware on May 19, 2020. The Company is engaged in the acquisition and development of oil and natural gas producing properties in onshore areas of the continental United States. Pecos WI LLC (the "Member") is the sole member. The Member is ultimately owned by Cibolo Energy LRR, LLC. (“Cibolo Energy”), a private equity firm.

The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates and judgments are based on information available at the time such estimates and judgments are made.

Making accurate estimates and assumptions is particularly difficult in the oil and natural gas industry, given the challenges resulting from volatility in oil and oil and natural gas prices. The most significant estimates pertain to proved oil and natural gas reserves and related cash flow estimates used in impairment tests of long-lived assets, estimates of future development, dismantlement and abandonment costs, valuation of derivative instruments and, valuation of the earnout liability. Certain of these estimates require assumptions regarding the Company’s enterprise value, future commodity prices, future costs and expenses and future production rates.

The Company evaluates these estimates on an ongoing basis, using historical experience, and other methods the Company considers reasonable in the particular circumstances. Actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

The Company uses the successful efforts method of accounting for its oil and natural gas producing activities. Under this method, all property acquisition costs and costs of development wells are capitalized as incurred. The costs of development wells are capitalized whether producing or non-producing. Costs to drill exploratory wells are capitalized pending the determination of whether proved reserves are found. If an exploratory well is determined to be unsuccessful, the costs of drilling the unsuccessful exploratory well are charged to exploration costs.

Geological and geophysical costs, including seismic studies, are charged to exploration costs as incurred. Expenditures incurred to operate and for maintenance, repairs and minor renewals necessary to maintain our oil and natural gas properties in operating condition are charged to lease operating expenses as incurred.

On the sale or retirement of a complete unit of a proved property or field, the cost and related accumulated depletion, depreciation and amortization are eliminated from the oil and natural gas property accounts, and the resulting gain or loss is recognized. On the sale of a partial unit of proved property, the unamortized cost of the property is apportioned to the interest sold and the interest retained is accounted for on the basis of the fair value of the retained interests and a gain or loss is recognized if the divestiture significantly affects the depletion rate.

Proceeds from sales of all or a partial interest in individual unproved properties assessed for impairment on a group basis are accounted for as a recovery of costs. No gain or loss is recognized unless the sales proceeds exceed the original cost of the entire interest in the property, in which a gain will be recognized for the excess.

The cost of proved oil and natural gas properties are assessed on a field-by-field basis for impairment at least annually or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The expected undiscounted future cash flows of the oil and natural gas properties are compared to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the carrying amount of the oil and natural gas properties is adjusted to estimated fair value. Assumptions associated with discounted cash flow models or valuations used in the impairment evaluation include estimates of future oil and natural gas prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk-adjusted discount rates and other relevant data. Unproved oil and natural gas properties are assessed periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage.

Capitalized costs of proved oil and natural gas properties are amortized using the units-of-production method based on production and estimates of proved reserve quantities. Leasehold acquisition costs of proved properties are depleted over total estimated proved reserves, and capitalized development costs of wells and related equipment and facilities are depleted over total estimated proved developed reserves. During the years ended December 31, 2022 and 2021, the Company recognized depletion expense of $22.3 million and $13.8 million, respectively.

The Company is obligated to fund the costs of disposing of long-lived assets upon their abandonment. The Company’s asset retirement obligations (“ARO”) relate to the plugging of wells and the related abandonment of oil and natural gas properties. The Company records a liability for the present value of all legal obligations associated with the retirement of tangible long-lived assets with an offsetting increase in the carrying value of the associated asset when the assets are placed into service. The liability is accreted to its future value each period and capitalized costs are depleted over the estimated useful life of the related asset. Upon settlement of the liability, any gain or loss, if applicable, is recognized in income. The computation of ARO requires the Company to make assumptions about the ultimate amount and timing of settlements, discount rates and changes in legal and regulatory requirements.


	Year Ended December 31, 2022			Year Ended December 31, 2021
	(in thousands)
ARO, beginning balance	$	12,796		$	16,694
Liabilities incurred and acquired			12			8
Liabilities relinquished			—			(4,396	)
Liabilities settled			(2,764)			(929)
Accretion expense			1,125			1,419
ARO, ending balance			11,169			12,796
Less: current ARO			(3,300)			(1,350)
ARO, long-term	$	7,869		$	11,446

Under the Company’s oil contract, oil production is sold at the wellhead or central facilities. The Company collects an agreed-upon index price adjusted for location differentials and product quality. Revenue is recognized when control transfers to the purchaser at the wellhead or central facilities at the net price received by the Company.

Under the Company’s natural gas contracts, the Company delivers natural gas to a midstream processing company at the wellhead or the inlet of the midstream processing company’s gathering system. The midstream processing company gathers and processes the natural gas and remits the associated proceeds to the Company. For contracts where control is transferred to the processor at the plant inlet or wellhead, the Company recognizes volumes and revenue on a net basis with transportation and processing fees recorded as a contra-revenue amount.

Certain financial instruments are reported at fair value on our balance sheets. Fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants (i.e., an exit price). To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels:

The valuation techniques that may be used to measure fair value include a market approach, an income approach and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost). These approaches are considered Level 3 in the fair value hierarchy.

The carrying values of financial instruments comprising cash and cash equivalents, payables, receivables, related party accounts receivable/payable and advances from joint interest owners approximate fair values due to the short-term maturities of these instruments and are considered Level 1 in the fair value hierarchy. Assets and liabilities accounted for at fair value on a non-recurring basis in accordance with the fair value hierarchy include the initial recognition of asset retirement obligations, the fair value of oil and natural gas properties when acquired in a business combination and impairment assessments are considered Level 3 in the fair value hierarchy.

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. See Note 6 – Fair Value Measurements for further information.

On July 10, 2020, the Company closed on its initial acquisition of oil and natural gas properties located in Eddy County, New Mexico (the Acquisition). As part of the total consideration transferred, the purchase and sale agreement included a provision for potential contingent consideration to the seller, which is based on qualified distributions, as defined in the agreement, in future quarters. As the contingent consideration would be settled in cash, the Company considers the contingent consideration to be a liability, which is revalued at each reporting period (“Earnout Liability”). See further discussion in Note 6 - Fair Value Measurements for further information. Any subsequent changes in the fair value of the Earnout Liability are recognized in other (expense) income within the Company’s statements of operations. The Company recognized a loss of $3.8 million and $12.1 million for the years ended December 31, 2022 and 2021, respectively, as a result of changes in the fair value of the Earnout Liability.

The Company accounts for all business combinations using the acquisition method, under which the assets acquired and liabilities assumed are measured and recorded at their acquisition date fair values. The difference between the fair value of assets acquired and liabilities assumed and the purchase price, if any, is recorded as either goodwill or a bargain purchase gain.

The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents. The Company places its cash with financial institutions that are insured by the Federal Deposit Insurance Corporation. The Company maintains deposits in banks which from time-to-time exceed the amount of deposit insurance available. The Company had cash deposits in excess of federally insured amounts of approximately $12.5 million and $13.4 million at December 31, 2022 and 2021, respectively. Management assesses the financial condition of the institutions and believes that any possible credit loss would be minimal.

Accounts receivable consist primarily of amounts due from purchasers of oil and natural gas and from outside working interest owners. Accounts receivable from oil, natural gas and natural gas liquids sales are recorded at the invoiced amount and do not bear interest. The Company routinely assesses the financial strength of its customers and bad debts are recorded based on an account-by-account evaluation. As of December 31, 2022 and 2021, the Company had no reserves for doubtful accounts.

The Company established right-of-use assets and lease liabilities on the balance sheet for all leases with a term longer than 12 months. Typical right-of-use operating lease assets of the Company are for certain leases related to drilling rigs and other equipment related to the exploration, development and production of oil and natural gas.

In August 2020, the Company’s Member issued unit-based compensation awards in the form of Series B Profits Interest Awards (“Class B Unit”) to a participant under its Limited Liability Company Agreement (“LLC Agreement”) in connection with the Management Services Agreement (“MSA”) for services to be rendered to the Company. The Company evaluated the Class B Unit awards and determined they are a substantive class of equity subject to ASC 718, Compensation – Stock Compensation (“ASC 718”), which requires compensation expense related to all awards to be recognized in the financial statements. For the Class B Unit awards granted, the associated expenses are being recognized in the Company’s financial statements on a straight-line basis over the awards’ vesting periods of five years based on their fair values on the dates of grant. The amount of Class B unit awards expense recognized at any date is approximately equal to the ratable portion of the grant date value of the award that is vested at that date with a corresponding increase to equity. Class B Unit awards compensation expense is included in the general and administrative expense in the statement of operations. See Note 7 – Unit-Based Compensation for further information.

The objective of the Company’s use of commodity derivative instruments is to achieve more predictable cash flows in an environment of volatile oil and natural gas prices and to manage its exposure to commodity price risk. While the use of these commodity derivative instruments limits the downside risk of adverse price movements, such use may also limit the Company’s ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions.

All derivative instruments are recorded on the Company’s balance sheets as either assets or liabilities, measured at fair value. The Company has not designated any derivative instruments as hedges for accounting purposes and does not enter into such instruments for speculative trading purposes. Gains and losses on commodity derivative contracts are presented in the other (expense) income section of the Company’s statements of operations as a net gain or loss on commodity derivatives. The Company’s cash flow is only impacted when the actual settlements under the derivative contracts result in the Company making a payment to or receiving a payment from the counterparty.

of credit risk related to derivative financial instruments. The Company operates, per a Management Services Agreement with Redwood Operating LLC, a substantial portion of its oil and natural gas properties. As the operator of a property, the Company makes full payments for costs associated with the property and seeks reimbursement from the other working interest owners in the property for their respective share of those costs.

The Company’s joint interest partners consist primarily of independent oil and natural gas producers, and the purchasers of the Company’s oil and natural gas production consist primarily of independent marketers, major oil and natural gas companies, and natural gas pipeline companies. While the Company has not experienced any significant losses from uncollectible accounts, if the oil and natural gas exploration and production industry in general was adversely affected, the ability of the Company’s joint interest partners to reimburse the Company and of the Company’s customers to make payments for oil and natural gas purchases could be adversely affected. To minimize risk, ongoing credit evaluations of customers’ and joint interest partners’ financial condition are performed, although collateral generally is not required.

For the year ended December 31, 2022, three individual customers accounted for 78%, 19%, and 2%, respectively, of the Company’s sales. For the year ended December 31, 2021, three individual customers accounted for 76%, 19%, and 5%, respectively, of the Company’s sales. The Company does not believe the loss of any one of its purchasers would materially affect the Company’s ability to sell the oil and natural gas it produces as it believes other purchasers are available in the Company’s areas of operations.

In February 2016, the Financial Accounting Standards Board (“FASB”) issued ASC 842, “Leases.” This Accounting Standards Update (“ASU”) replaced previous lease accounting guidance in GAAP. The new guidance requires the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. It also retains a distinction between finance leases and operating leases. For lessors, the new accounting model remains largely the same, although some changes have been made to align it with the new lessee model and the ASC 606 revenue recognition guidance. We adopted ASC 842 on January 1, 2022, using the modified retrospective method, with no adjustment to comparative period information, which remains reported under ASC 840, and no cumulative effect adjustment to equity. The adoption of this lease accounting guidance did not have any material impact on the financial statements as of or for the year ended December 31, 2022.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses. In May 2019, ASU 2016-13 was subsequently amended by ASU 2019-04, Codification Improvements to Topic 326, Financial Instruments – Credit Losses and ASU 2019-05, Financial Instruments – Credit Losses (Topic 326: Targeted Transition Relief). ASU 2016-13, as amended, affects trade receivables, financial assets and certain other instruments that are not measured at fair value. The amended guidance will be effective for the Company for annual periods beginning after December 15, 2022. The Company is evaluating the effect of these ASUs on its consolidated financial statements and related disclosures and has not yet determined the effect.

On September 1, 2021, Pecos Oil & Gas, LLC entered into an agreement with Tyton Energy LLC of Colorado (“Tyton”) to relinquish certain assets in Eddy County New Mexico. These properties were known as the Atoka San Andres Unit (ASAU) properties. Also, on October 1, 2021, Pecos Oil & Gas, LLC entered into another agreement with Tyton to relinquish certain assets in Eddy County New Mexico. These properties were known as the West Red Lake Unit (WRLU) properties. The disposal of the ASAU and WRLU properties resulted in the disposition of related asset retirement obligations of $4.4 million. The disposition of the ASAU and WRLU properties did not significantly affect the depletion rate, and accordingly, no gain or loss was recognized on these transactions.

The Company is exposed to commodity price risk and considers it prudent to periodically reduce the Company’s exposure to cash flow variability resulting from commodity price changes. Accordingly, the Company may enter into derivative instruments to manage its exposure to commodity price fluctuations. The following table summarizes the open financial derivative positions as of December 31, 2022, related to oil and natural gas production:

Period of Production

Instrument Type

Notional Volume

Swap Price

Floor Price

Ceiling Price

NYMEX HH Natural Gas (MMBTUs):

Jan - Feb 2023

Swap

29,500

$ 3.36

N/A

Jan - Mar 2023

Collar

312,218

N/A

$ 5.25

$ 15.75

NYMEX WTI Crude Oil (MBBLs):

Jan - Mar 2023

Collar

134,541

N/A

$ 70.00

$ 88.52

Apr - Jun 2023

Collar

125,765

N/A

$ 70.00

$ 83.01

Jul - Sep 2023

Collar

113,995

N/A

$ 70.00

$ 79.00


	As of December 31, 2022
	Gross Amount			Netting Adjustments		Net Amount
	(in thousands)
Derivative assets:
Current assets	$	506		$	—	$	506
Long-term assets			—		—			—
Total derivative assets	$	506		$	—	$	506
Derivative liabilities:
Current liabilities	$	(887)		$	—	$	(887)
Long-term liabilities			—		—			—
Total derivative liabilities	$	(887)		$	—	$	(887)


	As of December 31, 2021
	Gross Amount			Netting Adjustments			Net Value
	(in thousands)
Derivative assets:
Current assets	$	9		$	(9)		$		—
Long-term assets			—			—			—
Total derivative assets	$	9		$	(9)		$		—
Derivative liabilities:
Current liabilities	$	(5,412)		$	9		$	(5,403)
Long-term liabilities			(20)			—			(20)
Total derivative liabilities	$	(5,432)		$	9		$	(5,423)

All of the Company’s derivative transactions have been carried out in the over-the-counter market. The use of derivative instruments involves the risk that either counterparty may be unable to meet the financial terms of the transactions. The Company monitors the creditworthiness of itself and of each of its counterparties and assesses the possibility of whether each counterparty to the derivative contract would default by failing to make any contractually required payments as scheduled in the derivative instrument in determining the fair value. The derivative transactions are placed with major financial institutions that present minimal credit risks to the Company.

On July 10, 2020 the Company entered into a Note Purchase Agreement (“Note Payable”) with Cibolo Energy (“Holder”) and Cibolo Energy Partners LLC (“Administrative Agent”) with a maturity date of July 10, 2025. The Holder and Administrative Agent are affiliated entities of Cibolo Energy, who is the owner of the Member, and thus, the Notes Payable are held with related parties of the Member.

The Note Payable is collateralized by a first priority security interest in 100% of the oil and natural gas properties acquired by the Company. The Note Payable contains certain restrictive covenants, including a Proved Asset Coverage Ratio. The Proved Asset Coverage Ratio must be less than 1.50 to 1.00 as of the last day of any fiscal quarter. As of December 31, 2022 and 2021, the Company was in compliance with its covenants.


	Fair Value Measurement at the End of Reporting Period
	Level 1	Level 2	Level 3	Total
As of December 31, 2022
Assets:
Commodity derivative instruments	$ —	$ 506	$ —	$ 506
Liabilities:
Commodity derivative instruments	$ —	$ (887)	$ —	$ (887)
Earnout liability	$ —	$ —	$ (15,251)	$ (15,251)

As of December 31, 2021
Assets:
Commodity derivative instruments	$ —	$ —	$ —	$ —
Liabilities:
Commodity derivative instruments	$ —	$ (5,423)	$ —	$ (5,423)
Earnout liability	$ —	$ —	$ (12,594)	$ (12,594)

Fair value of our commodity derivatives is determined using industry-standard models that consider various assumptions including current market and contractual prices for the underlying instruments, time value, implied volatilities, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be supported by observable data.

As of December 31, 2021, the fair value of our Earnout Liability was estimated using a Monte Carlo Simulation model which simulated enterprise value of the Company using the assumptions noted below. Expected volatility was estimated by observing the equity volatilities of comparable public guideline companies, un-levering to arrive at an asset volatility estimate and re-levering using the Company’s capital structure as of the valuation date. The volatilities of the public guideline companies were based on the average of their historical volatilities and the implied volatilities, where available, from their traded stock. The look-back period for the historical volatility was equal to the expected term of the Earnout Liability. The risk-free interest rate is based on the U.S. Department of the Treasury daily treasury yield curve rate with a term matching the expected term of the Earnout Liability. Below is a summary of the inputs:

As of December 31, 2022, the fair value of our Earnout Liability was estimated using a discounted cash flows model where future cash flows were based on the expected proceeds received from the sale of the Company’s oil and natural gas properties, which closed in April 2023. In April 2023, the Company made payments of approximately $12.5 million related to the partial payment of the earnout liability. See Note 10 – Subsequent Events for further discussion of the sale.

Nonfinancial assets and liabilities that are measured at fair value on a nonrecurring basis are comprised primarily of assets acquired in business combinations, asset retirement obligations, and assets evaluated for impairment. These assets and liabilities are recorded at fair value when acquired/incurred but not re-measured at fair value in subsequent periods. These initial measurements are classified as Level 3 since certain significant unobservable inputs are utilized in their determination.

In August 2020, the Class B Unit awards were issued by the Company’s Member under the LLC Agreement in connection with the MSA for services to be rendered to the Company. These Class B Unit awards were issued as a class of membership interests that entitles its holders to receive a portion of the proceeds of any distributions from the Member which are in excess of certain target investment return thresholds that must be first paid to Cibolo Energy. After Cibolo Energy has received their equity contributions from the Company’s Member, the holders of Class B Units are entitled to participate in all amounts distributed thereafter, at increasing percentages, based on various thresholds.

The Company accounts for its Class B Unit awards in accordance with ASC 718 for equity classified awards. The awards vest equally on each of the first five anniversaries of the grant date. Compensation expense is recognized over the five-year requisite service period on a straight-line basis based on the $6.9 million fair value of the awards at the date of grant. There have been no issuances of additional Class B Unit awards since the initial issuance in August 2020.

The Company recognized $1.4 million and $1.9 million of equity-based compensation related to these Class B Unit awards in for the years ended December 31, 2022 and 2021, respectively. Total unrecognized compensation expense as of December 31, 2022 was $3.6 million which will be recognized over the remaining 2.6 year vesting period.

Various federal, state and local laws and regulations covering, among other things, the release of waste materials into the environment and state and local taxes affect the Company’s operations and costs. Management believes the Company is in substantial compliance with applicable federal, state and local laws, and the ultimate resolution of any claims or legal proceedings instituted against the Company will not have a material effect on its financial position or results of operations.

In March 2022, the Company conveyed certain overriding royalty interest (“ORRI”) across the Company’s existing operated oil and natural gas properties to Pecos Royalty, LLC (“Pecos Royalty”), a newly formed affiliate. The ORRI entitles Pecos Royalty to a percentage of production revenues, as calculated in the conveyance agreement, associated with certain leases held by the Company. The ORRIs include an average of overriding royalty interest of approximately 5.3% across 281 operated wells. The conveyance of the ORRIs from the Company to Pecos Royalty was accounted for as a transaction between entities under common control. As a result, the distributed ORRIs have been recorded at their carrying balance at the date of the ORRI conveyance and no gain or loss being recorded by the Company. Additionally, a portion of the Earnout Liability was attributable to the ORRI that was conveyed. As such, the Company included the fair value of this portion of the Earnout Liability in determining the amount of the nonmonetary distribution. Below is a summary:

On February 28, 2023, the Company entered into a definite purchase and sales agreement to sell substantially all of the Company’s oil and natural gas properties to Riley Exploration Permian, Inc. (NYSE American: REPX) for cash consideration of $330 million, subject to customary purchase closing adjustments. The divestiture closed on April 3, 2023.

Capitalized costs for unproved properties include costs for acquiring or extending oil and natural gas leaseholds where no proved reserves have been identified. Work in progress include costs of exploratory and development wells that are in the process of drilling or in active completion, and costs of exploratory and development wells suspended or waiting on completion.


	As of December 31, 2022		As of December 31, 2021
	(in thousands)

Oil and natural gas properties:
Proved properties	$ 192,051	$ 150,516
Unproved properties	12,747	13,535
Total oil and natural gas properties	204,798	164,051
Less: accumulated depreciation, depletion and impairment	(37,334)	(19,460)
Oil and natural gas properties, net	$ 167,464	$ 144,591

Amounts reported as costs incurred include both capitalized costs and costs charged to expense when incurred for oil and natural gas property acquisition, exploration and development activities. Costs incurred also include new ARO established in the current year as well as increases or decreases to ARO resulting from changes to cost estimates during the year. Exploration costs presented below include the costs of drilling and equipping successful and unsuccessful exploration wells during the year, geological and geophysical expenses and the costs of retaining undeveloped leaseholds. Development costs include the costs of drilling and equipping development wells and construction of related production facilities.

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 the changes in prices and operating costs. Management 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.


	Oil (MBbls)	Natural Gas (MMcf)	NGLs (MBbls)	Total (MBoe)
Proved reserves at December 31, 2020	9,200	19,941	4,180	16,704
Revisions	911	(400)	(95)	749
Extensions	6,492	8,536	1,790	9,705
Divestiture of Reserves	(3)	(12)	(3)	(8)
Production	(694)	(1,975)	(412)	(1,435)
Proved reserves at December 31, 2021	15,906	26,090	5,460	25,715
Revisions	(5,899)	(6,097)	(1,425)	(8,340)
Extensions	350	486	99	530
Divestiture of Reserves	(660)	(1,285)	(269)	(1,143)
Production	(939)	(2,443)	(498)	(1,844)
Proved reserves at December 31, 2022	8,758	16,751	3,367	14,918

The guidelines prescribed in FASB Codification Topic 932, Extractive Activities – Oil and Gas, were followed in computing the standardized measure of net cash flows and changes therein relating to estimated quantities of proved reserves. Prices are based on the unweighted arithmetic average first-day-of-the-month for the preceding 12-month period, unless prices are defined by contractual agreements. All prices are then further adjusted for transportation, quality and basis differentials and are set forth in the following table:

The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value of the properties. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary.


	As of December 31, 2022		As of December 31, 2021
	(in thousands)

Future cash inflows	$ 986,723	$ 1,252,605
Future production costs	(269,098)	(342,139)
Future development costs	(36,614)	(160,632)
Future income tax expense (1)	—	—
Future net cash flows	681,011	749,834
10% annual discount for estimated timing of cash flows	(298,015)	(397,741)
Standardized measure of discounted future net cash flows	$ 382,996	$ 352,093


	As of December 31, 2022		As of December 31, 2021
	(in thousands)

Balance, beginning of period	$ 352,093	$ 82,860
Net change in prices and production costs	107,237	181,118
Net change in future development costs	9,683	(14,906)
Oil & Gas net revenue	(83,213)	(51,087)
Extensions	12,743	114,178
Divestiture of reserves	(5,281)	(67)
Revisions of previous quantity estimates	(72,549)	15,816
Previously estimated development costs incurred	26,373	20,309
Net change in taxes	—	—
Accretion of discount	35,209	8,286
Changes in timing and other	701	(4,414)
Standardized measure of discounted future net cash flows	$ 382,996	$ 352,093


	Year Ended December 31, 2022	Year Ended December 31, 2021
	(in thousands)

Oil	$ 88,993		$ 47,720
Natural gas	11,280		5,919
Natural gas liquids	13,141		8,735
Oil and natural gas sales, net	$ 113,414		$ 62,374


	As of December 31, 2022		As of December 31, 2021
	(in thousands)

Oil, natural gas and NGL	$ 14,628	$ 10,298
Joint interest accounts receivable	1,310	691
Accounts receivable	$ 15,938	$ 10,989


						As of December 31, 2021
Expected term (in years)						1.0
Expected volatility						51.0%
Risk-free interest rate						0.4%


Carrying value of ORRI			$ 8,578
Fair value of Earnout Liability attributable to ORRI			(1,148)
Distribution of net assets			$ 7,430


	December 31, 2022		December 31, 2021

Crude oil (WTI Cushing price per MBbl)	$ 91.80	$ 65.23
Natural gas (Henry Hub price per MMBtu)	$ 4.51	$ 2.95
Natural gas liquids (WTI Cushing price per MBbl)	$ 31.85	$ 25.29


			Member’s Equity
			(in thousands)
Balance – January 1, 2021			$ 53,370
Unit-based compensation			1,882
Net loss			(20,727)
Balance - December 31, 2021			34,525
Distribution of nonmonetary assets (Note 9)			(7,430)
Unit-based compensation			1,379
Net income			25,293
Balance - December 31, 2022			$ 53,767