Document

We have reviewed the accompanying financial information of Percussion Petroleum II, LLC (the Company), which comprise the balance sheet as of March 31, 2023, and the related statements of operations, members’ equity, and cash flows for the three months ended March 31, 2023, and the related notes to the financial statements (collectively referred to as the interim financial information).

We conducted our review in accordance with auditing standards generally accepted in the United States of America (GAAS) applicable to reviews of interim financial information. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. A review of interim financial information is substantially less in scope than an audit conducted in accordance with GAAS, the objective of which is an expression of an opinion regarding the financial information as a whole, and accordingly, we do not express such an opinion. 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 review. We believe that the results of the review procedures provide a reasonable basis for our conclusion.

Management is responsible for the preparation and fair presentation of the interim financial information 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 interim financial information that is free from material misstatement, whether due to fraud or error.


						March 31, 2023
ASSETS

CURRENT ASSETS
Cash and cash equivalents						$20,449,217
Accounts receivable - oil and gas sales						31,508,559
Accounts receivable - other						5,769,043
Prepaid expenses & other						374,070
Inventory						12,766,013
Total current assets						70,866,902

OIL AND GAS PROPERTIES, full cost
Proved and unproved properties						676,779,012
Other property & equipment						3,396,188
Accumulated depreciation, depletion and amortization						(117,631,712)
Total oil and gas properties, net						562,543,488

OTHER ASSETS
Debt issuance costs, net						2,696,771
Operating lease - right-of-use asset						2,352,614
Total other assets						5,049,385

TOTAL ASSETS						$638,459,775

LIABILITIES AND MEMBERS’ EQUITY

CURRENT LIABILITIES
Accounts payable and accrued liabilities						$63,324,957
Revenue and taxes payable						26,308,841
Current portion of derivative liabilities, net						25,335,599
Current portion of operating lease liabilities						563,023
Total current liabilities						115,532,420

NON-CURRENT LIABILITIES
Long-term debt						220,000,000
Asset retirement obligations						3,010,295
Long-term portion of derivative liabilities						15,972,238
Operating lease liabilities, net of current portion						1,933,519
Total non-current liabilities						240,916,052

Total liabilities						356,448,472

MEMBERS’ EQUITY						282,011,303

TOTAL LIABILITIES AND MEMBERS’ EQUITY						$638,459,775


						March 31, 2023
REVENUES
Oil and gas revenue						$68,978,478
Realized loss on oil and gas derivatives						(7,992,687)
Total revenues						60,985,791

OPERATING EXPENSES
Lease operating expense						12,037,035
Production and ad valorem taxes, net						4,588,713
Marketing, transportation, and gathering expenses						2,077,512
Minimum volume commitment deficiency fees						955,080
General and administrative expenses						1,500,851
Transaction cost						913,363
Depreciation, depletion, amortization, and accretion						16,279,522
Total operating expenses						38,352,076

Income from operations						22,633,715

OTHER INCOME (EXPENSE)
Interest expense, net						(5,168,643)
Other income						142,855
Net unrealized gain on oil and gas derivatives						47,686,511
Total other expense						42,660,723

NET INCOME						$65,294,438


CASH FLOWS FROM OPERATING ACTIVITIES						March 31, 2023
Net income						$65,294,438
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion, amortization, and accretion						16,279,522
Amortization of debt issuance costs						301,790
Change in fair value of oil and gas derivatives						(47,686,511)
Inventory write down						100,655
ASC 842 - non-cash lease expense						(3,619)
Changes in operating assets and liabilities
Accounts receivable - oil and gas sales						438,760
Inventory						(1,311,196)
Prepaid expenses and other current assets						122,260
Accounts payable and accrued liabilities						(21,343,381)
Settlement of ARO						(57,477)
Net cash provided by operating activities						12,135,241

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures						(43,810,025)
Divestment of oil and gas properties						(620,299)
Additions to other property and equipment						(70,362)
Net cash used in investing activities						(44,500,686)

CASH FLOWS FROM FINANCING ACTIVITIES
Deferred financing costs						(13,548)
Net cash used in financing activities						(13,548)

Net decrease in cash and cash equivalents						(32,378,993)

CASH AND CASH EQUIVALENTS, beginning of year						52,828,210

CASH AND CASH EQUIVALENTS, end of year						$20,449,217

SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES
Change in capital expenditures accrued in accounts payable						$8,763,879
OTHER SUPPLEMENTAL CASH FLOW INFORMATION
Interest paid						$3,729,959
Cash paid for operating leases						$108,014

Percussion Petroleum Management II, LLC (Percussion Management II) is a wholly owned subsidiary of the Company and acts as management of the Company. Percussion Petroleum Operating II, LLC (Percussion Operating II) is a wholly owned subsidiary of the Company and acts as operators of the properties owned by the Company. Percussion Petroleum Intermediate II, LLC (Percussion Intermediate II) is a wholly owned subsidiary of the Company.

The Company prepares its consolidated financial statements in accordance with United States generally accepted accounting principles (U.S. GAAP). Accounting principles and the methods of applying these principles that materially affect the determination of financial position, results of operations, and cash flows are summarized below.

These unaudited condensed consolidated financial statements (the “consolidated financial statements”) should be read in conjunction with the audited financial statements and the notes thereto for the year ended December 31, 2022. In the opinion of management, the unaudited condensed consolidated financial statements for the interim period presented include all adjustments necessary to present a fair statement of the results for such interim period.

The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires the Company’s management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

Significant assumptions are required in the valuation of proved oil and gas reserves which may affect the amount at which oil and gas properties are recorded, provisions for depletion and impairment of oil and gas properties. Estimation of asset retirement obligations is based on estimates regarding the timing and cost of future asset abandonments. Estimation of production volumes near period end is required in order to determine the amount of oil and gas revenue receivable at period end. Estimates of the fair value and settlement value of derivative instruments are inherently imprecise. It is possible these estimates could be revised in the near term and these revisions could be material.

Accounts receivable – oil and gas sales include amounts due from oil and gas purchasers. Accounts receivable include accrued revenues due under normal trade terms, generally requiring payment within 30 days of production. No interest was charged in 2023 on past due balances. The Company’s allowance for doubtful accounts is determined based upon reviews of individual accounts, historical losses, existing economic conditions and other pertinent factors. No allowance was recorded as of March 31, 2023.

Inventory is added to the books upon the purchase of supplies (inclusive of freight and sales tax costs) to use on well sites, and inventory is reduced by material transfers for inventory usage based on the initial invoiced value. The Company reports inventory balances at the lower of cost or market value and excludes inventory balances from depletion calculations.

The Company uses derivative instruments to manage market risks resulting from fluctuations in the prices of crude oil, natural gas and NGLs. The Company enters into derivative contracts, including price swaps, basis swaps and collars, which require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of crude oil, natural gas and NGLs without the exchange of underlying volumes. The notional amounts of these financial instruments are based on expected production from existing wells. The Company may also use exchange traded futures contracts and option contracts to hedge the delivery price of crude oil at a future date.

The Company follows the provisions of FASB ASC 815, Derivatives and Hedging, as amended. It requires that all derivative instruments be recognized as assets or liabilities in the balance sheet, measured at fair value and marked-to-market at the end of each period. Any realized gains and losses on settled derivatives, as well as mark-to-market gains or losses, are aggregated and recorded to gain (loss) on derivative instruments, net on the statement of operations. See Note 4 for a description of the derivative contracts into which the Company has entered.

The Company utilizes commodity price swaps, basis swaps, and collars (purchased put options and written call options) to (i) reduce the effects of volatility in price changes on the crude oil and natural gas commodities it produces and sells, (ii) reduce commodity price risk and (iii) provide a base level of cash flow in order to assure it can execute at least a portion of its capital spending.

as hedges for accounting purposes and does not enter into such instruments for speculative trading purposes. If a derivative does not qualify as a hedge or is not designated as a hedge, the changes in the fair value are recognized in the Company’s statement of operations as a gain or loss on derivative instruments. Mark-to-market gains and losses represent changes in fair values of derivatives that have not been settled. The Company’s cash flow is only impacted when the actual settlements under the derivative contracts result in making or receiving a payment to or from the counterparty. These cash settlements represent the cumulative gains and losses on the Company’s derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled, as applicable.

The Company has master netting agreements on individual derivative instruments with certain counterparties and therefore the current assets and liabilities are netted in the consolidated balance sheet and the non-current assets and liabilities are netted in the consolidated balance sheet for contracts with these counterparties.

Other property and equipment is stated at cost. Repairs and maintenance are charged to expense as incurred, with additions and improvements being capitalized. Upon sale or other retirement of depreciable property, the cost and accumulated depreciation are removed from the related accounts and any gain or loss is reflected in the consolidated statements of operations.

The Company follows the full cost method of accounting for crude oil and natural gas operations whereby all costs related to the exploration and development of crude oil and natural gas properties are initially capitalized into a single cost pool (full cost pool). Capitalized costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition, and exploration activities. Internal costs that are capitalized are directly attributable to acquisition, exploration and development activities and do not include costs related to the production, general corporate overhead or similar activities. Costs associated with production and general corporate activities are expensed in the period incurred. As of March 31, 2023, the Company held leasehold interests on acreage in various counties in Texas. The Company capitalized $54,836,439 of costs to the full cost pool for the three months ended March 31, 2023 for capital expenditures to develop their reserve base.

Proceeds from property sales will generally be credited to the full cost pool, with no gain or loss recognized, unless such a sale significantly alters the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool.

Capitalized costs associated with impaired properties and capitalized cost related to properties having proved reserves, plus the estimated future development costs and asset retirement costs, are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves as determined by petroleum engineers on at least an annual basis. The costs of unproved properties are withheld from the depletion base until such time as they are either developed or abandoned. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion and full cost ceiling calculations. Depletion expense on proved property was $16,086,693 for the three months ended March 31, 2023, and is included in depreciation, depletion, amortization and accretion in the consolidated statement of operations.

The Company evaluates capitalized costs annually for impairment using the full cost ceiling test method of accounting. Capitalized costs of crude oil and natural gas properties may not exceed an amount equal to the present value, discounted at 10% per annum, of the estimated future net cash flows from proved crude oil and natural gas reserves plus the cost of unproved properties. Should capitalized costs exceed this ceiling, impairment is recognized. The present value of estimated future net cash flows is computed by applying the 12-month average price of crude oil and natural gas to estimated future production of proved crude oil and natural gas reserves as of year-end, less estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions. Such present value of proved reserves' future net cash flows excludes future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheets. Should this comparison indicate an excess carrying value, the excess is charged to earnings as an impairment expense. Each part of this calculation is subject to a large degree of judgment, including the determination of the depletable fields’ estimated reserves, future net cash flows and fair value. For the three months ended March 31, 2023, the Company did not realize an impairment of its proved properties.

Debt issuance costs consist of costs directly attributable to the acquisition of debt financing. These costs are capitalized as non-current other asset charges and amortized over the life of the credit instrument obtained. During the three months ended March 31, 2023, the Company capitalized $0 of debt issuance costs and for the three months then ended recognized $301,790 of amortization related to debt issuance costs, which is included in interest expense on the consolidated statement of operations. As of the three months ended March 31, 2023, the Company had net debt issuance costs of $2,696,771.

Accounts payable and accrued liabilities consist primarily of vendor obligations under normal trade terms for services rendered or products received. Accrued liabilities include revenue collected on behalf of mineral interest owners to be disbursed subsequent to year-end and prepayments from working interest owners for future expenses and accrued capital expenditures.

The Company accounts for its asset retirement obligations in accordance with FASB ASC Topic 410, Asset Retirement and Environmental Obligations. Asset retirement obligations consist of estimated costs of dismantlement, removal, site reclamation and similar activities associated with oil and gas properties. A liability is recorded when the fair value of the asset retirement obligation can be reasonably estimated and recognized in the period a legal obligation is incurred. A liability is incurred when a well is drilled and completed. The liability amounts are based on future retirement cost estimates and incorporate many assumptions, such as expected economic recoveries of oil and gas, time to abandonment, future inflation rates and the adjusted risk-free rate of interest.

The retirement obligation is recorded at its estimated present value at the asset's inception with an offsetting increase to proved properties in the consolidated balance sheet. This addition to proved properties represents a non-cash investing activity for purposes of the consolidated statement of cash flows. After initially recording the liability, it accretes for the passage of time and the related cost of capital, with the increase reflected as accretion expense in the consolidated statement of operations.

The Company’s revenues are primarily derived from its interests in the sale of oil and natural gas production. The Company recognizes revenue from its interests in the sales of oil and natural gas in the period that its performance obligations are satisfied. Performance obligations are satisfied at a point in time when the customer obtains control of product, when the Company has no further obligations to perform related to the sale, when the transaction price has been determined and when collectability is probable. The sales of oil and natural gas are made under contracts which have been negotiated with purchasers, which typically include variable consideration that is based on pricing tied to local indices and volumes delivered in the current month. The Company receives payment from the sale of oil and natural gas production from one to three 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 trade accounts receivable, on the consolidated balance sheet. Variances between the Company’s estimated revenue and actual payments are recorded in the month the payment is received, however, differences have been and are insignificant. Accordingly, the variable consideration is not constrained.

The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical expedient in accordance with ASC 606. The expedient, as described in ASC 606-10-50-14(a), applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.

The Company’s oil is typically sold at delivery points under contracts terms that are common in the energy industry. The Company’s natural gas produced is delivered to various purchasers at agreed upon delivery points under a limited number of contract types that are also common in the energy industry. Regardless of the contract type, the terms of these contracts compensate the well operators for the value of the oil and natural gas at specified prices, and then the well operators will remit payment to the Company for its share in the value of the oil and natural gas sold.

Exploration and development and the production and sale of oil and gas are subject to extensive federal, state, provincial, tribal, and local regulations. Management believes it is in substantial compliance with currently applicable laws and regulations and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations. However, current regulatory requirements may change, currently unforeseen resource or environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. Environmental compliance costs, including ongoing maintenance and monitoring, are expensed as incurred.

The Company accounts for the Incentive Units in accordance with the provisions of FASB ASC Topic 710, Compensation – Generally due to the payouts being consistent with profit sharing of the Company based on substantive terms of the instruments. Due to the nature of the Incentive Units, no value is attributed and no expense recognized at the date of issuance, and amounts earned by holders of the Incentive Units will be charged to compensation expense in the period in which they are earned and can be reasonably estimated and deemed probable.

The Company is organized as a limited liability company and is considered a pass through entity for federal income tax purposes. As a result, income or losses are taxable or deductible to the members rather than at the Company level; accordingly, no provision has been made for federal income taxes in the accompanying consolidated financial statements. In certain instances, the Company is subject to state taxes on income arising in or derived from the state tax jurisdictions in which it operates.

State income tax positions are evaluated in a two-step process. The Company first determines whether it is more likely than not that a tax position will be sustained upon examination. If a tax position meets the more likely than not threshold, it is then measured to determine the amount of expense to record in the consolidated financial statements. The tax expense recorded would equal the largest amount of expense related to the outcome that is 50% or greater likely to occur. The Company classifies any potential accrued interest recognized on an underpayment of income taxes as interest expense and classifies any statutory penalties recognized on a tax position taken as operating expense. Management of the Company has not taken a tax position that, if challenged, would be expected to have a material effect on the consolidated financial statements as of March 31, 2023.

Under the new centralized partnership audit rules effective for tax years beginning after 2017, the Internal Revenue Service (IRS) assesses and collects underpayments of tax from the partnership instead of from each partner. The partnership may be able to pass the adjustments through to its partners by making a push-out election or, if eligible, by electing out of the centralized partnership audit rules.

The collection of tax from the partnership is only an administrative convenience for the IRS to collect any underpayment of income taxes including interest and penalties. Income taxes on partnership income, regardless of who pays the tax or when the tax is paid, are attributed to the partners. Any payment made by the partnership as a result of an IRS examination will be treated as a distribution from the partnership to the partners in the consolidated financial statements.

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instruments’ complexity.

Current accounting guidance provides a framework for measuring fair value and establishes a fair value hierarchy that prioritizes the inputs used to measure fair value, giving the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities and the lowest priority to unobservable inputs. The three levels are as follows:

Level 2: Inputs include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability (i.e., interest rates, yield curves, etc.), and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market corroborated inputs).

The Company attempts to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. In measuring the fair value of its assets and liabilities, the Company uses market data or assumptions that it believes market participants would use in pricing an asset or liability, including assumptions about risk when appropriate. A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement.

The fair value of derivative assets and liabilities are valued using an option pricing model with primarily level 1 inputs, including underlying commodity price, strike price and volatility of similar instruments in observable markets. This is categorized as level 2, using the market approach.


	Level 1	Level 2	Level 3	Total
Liability - current
Commodity derivative instruments	$—	$25,335,599	$—	$25,335,599

Liability - non-current
Commodity derivative instruments price swap contracts	—	15,972,238	—	15,972,238

Total financial liability	—	41,307,837	—	41,307,837

Net financial liability	$—	$41,307,837	$—	$41,307,837

Such derivative instruments will not exceed anticipated production volumes, are expected to have a reasonable correlation between price movements in the futures market and the spot markets where the Company’s production is sold, and are authorized by the Board of Managers. Derivatives are expected to be realized as related production occurs, but may be terminated earlier if anticipated downward price movement occurs or if the Company believes the potential for such movement has abated. The Company’s crude oil and natural gas derivative positions consist of swaps and collars. Swaps and collars are designed so that the Company receives or makes payments based on a differential between fixed and variable prices for crude oil and natural gas. The Company utilizes WTI Roll Swaps to mitigate the financial risk associated with the Argus CMA Roll component of the Company’s realized price for physical oil sales.


Oil Contracts	For the Remainder 2023	For the Full Year 2024

Swap Contracts (WTI)
Total Volumes	—	—
Weighted Average price per barrel	$—	$—

Collar Contracts (WTI)
Total Volumes	604,955	—
Weighted Average price per barrel
Floor	$60.00	$—
Ceiling	$72.40	$—

Three-Way Collar Contracts (WTI)
Total Volumes	1,431,444	3,963,023
Weighted Average price per barrel
Sub-floor	$45.00	$48.16
Floor	$55.00	$58.16
Ceiling	$69.77	$78.86

Roll Swaps (WTI vs. CMA)
Total Volumes	1,512,363	—
Weighted Average price per barrel	$0.30	$—


Natural Gas Contracts	For the Remainder 2023	For the Full Year 2024

HHub Swaps
Total Volumes	—	—
Total Weighted Average Swap	$—	$—

HHub Collars
Total Volumes	616,675	6,778,555
Total Weighted Average Floor	$2.82	$3.00
Total Weighted Average Ceiling	$3.63	$3.33

Waha Swaps
Total Volumes	2,750,000	3,660,000
Total Weighted Average Swap	($1.94)	($1.06)


NGL Contracts	For the Remainder 2023	For the Full Year 2024

Ethane Swaps
Total Volumes	4,448,226	—
Total Weighted Average Swap	$0.23	$—

Propane Swaps
Total Volumes	4,537,761	—
Total Weighted Average Swap	$0.74	$—

iButane Swaps
Total Volumes	1,318,051	985,388
Total Weighted Average Swap	$0.84	$0.79

nButane Swaps
Total Volumes	4,036,978	3,028,411
Total Weighted Average Swap	$0.85	$0.79

Gasoline Swaps
Total Volumes	5,254,122	—
Total Weighted Average Swap	$1.34	$—


						March 31, 2023
Derivative liabilities - current
Gross amounts without effects of netting						$34,583,592
Effects of netting						(9,247,993)

Current portion of derivative liabilities, net						$25,335,599

Derivative liabilities - non-current
Gross amounts without effects of netting						$35,740,510
Effects of netting						(19,768,272)

Long-term portion of derivative liabilities, net						$15,972,238

The Company entered into a bank credit facility (the Credit Facility) on June 29, 2021. Pursuant to the credit agreement, from time to time the Company may borrow up to the lesser of: the available borrowing base, as determined by the credit agreement, or $500,000,000, which is the maximum borrowing capacity of the facility. The borrowing base is re-determined semi-annually each May 1 and November 1. At March 31, 2023, the Company had a maximum borrowing base of $235,000,000 and a remaining borrowing capacity of $10,000,000. The outstanding principal balance was $220,000,000 and outstanding issued letters of credit was $5,000,000 as of March 31, 2023.

During 2022, The Credit Facility was modified and allows for Secured Overnight Financing Rate (“SOFR”) loans and Base Rate Loans (as respectively defined in the Credit Facility). The interest rate on each SOFR Loan will be the adjusted SOFR (subject to a Floor of 0.5%) for the applicable interest period plus a margin between 3.0% and 4.0% (depending on the then-current level of Borrowing Base usage) plus a margin between 0.10% and 0.25% depending on the applicable term. The annual interest rate on each Base Rate Loan is the Federal Funds Rate (as defined in the Credit Facility) plus 0.5% per annum plus a margin between 2.0% and 3.0% (depending on the then-current level of Borrowing Base usage) plus a margin of 0.10%. In addition to interest, the Company must pay a commitment fee of 0.50% on the undrawn portion of the borrowing base. For the period ending March 31, 2023, interest expense recognized was approximately $4,866,852.

The Company’s revolving line of credit is secured by all property of the Company and its subsidiaries. It contains various nonfinancial and financial covenants, including a minimum current ratio and maximum net debt to EBITDAX ratio. No amounts were drawn on the letters of credit for the three months ended March 31, 2023.

Capital contributions are based on capital calls, determined by the board of managers. Contribution requests to the Members are based on their commitment and any items in nature of income or gain will be applied to the Members' capital accounts in accordance with their earnings interest, as defined by the Membership Agreement. The Company has three classes of members' equity, Classes A, B, and C

All distributions by the Company shall be made to unitholders in accordance with their respective class sharing percentage set forth in the Company’s Membership Agreement. Additionally, net income (loss) is allocated to the unitholders in accordance with their respective partnership percentages.

Pursuant to the Percussion Petroleum II, LLC Amended Company Agreement (Company Agreement), the Board has authorized issuance of Incentive Units. The Incentive Units do not have an exercise price and do not expire until the Company is dissolved. The incentive units entitle the holder to participate in distributable cash flow generated by the Company in the event that certain payouts are achieved in accordance with the distribution provisions of the Company Agreement. The Incentive Units are accounted for consistent with requirements of ASC Topic 710 due to the payouts being consistent with profit sharing of the Company based on substantive terms of the instruments. Accordingly, no value was attributed to the Incentive Units and no expense recognized at the date of issuance.

Transactions between related parties are considered to be related party transactions even though they may not be given accounting recognition. FASB ASC Topic 850, Related Party Disclosures (ASC Topic 850), requires that transactions with related parties that would make a difference in decision making be disclosed so that users of the consolidated financial statements can evaluate their significance.

Carnelian Energy Capital, Catena Resources Operating and Catena Resources Management are considered related parties under ASC Topic 850. The Company provides all services that are generally required for the day-to-day operation of business to Catena Resources, LLC under a Services Agreement. For the three months ended March 31, 2023, the Company invoiced Catena $253,208 relating to these services and as of March 31, 2023, $225,358 of this amount was due from Catena.

The Company is engaged in oil and gas exploration and production and may become subject to certain liabilities as they relate to environmental cleanup of well sites or other environmental restoration procedures as they relate to the drilling of oil and gas wells and the operation thereof. In the Company’s acquisition of existing or previously drilled wellbores, the Company may not be aware of what environmental safeguards were taken at the time such wells were drilled or during such time the wells were operated. Should it be determined that a liability exists with respect to any environmental clean-up or restoration, the liability to cure such a violation could fall upon the Company.

The Company is subject to legal proceedings and certain claims have arisen in the ordinary course of its business. In the opinion of management, any possible contingencies with respect to these actions will not materially affect the financial position of the Company and are not considered by management to be probable as of the date of this report was available to be issued.

In 2021, the Company entered into a lease arrangement for its corporate office in Houston, Texas that expires in 2027. For the three months ended March 31, 2023, the Company’s office rent was $143,692. Office rent expense is included in general and administrative expenses in the accompanying consolidated statement of operations.

On May 3, 2023, the Company entered into an agreement with Callon Petroleum Company (“Callon”, “CPE”) for the sale of its oil and gas properties in the Delaware Basin for cash consideration of $265.0 million and $210.0 million of shares of CPE common stock. Additionally, Callon could have to pay up to $62.5 million of contingent consideration if the WTI price of oil exceeds certain thresholds in 2023, 2024, and 2025. Upon signing, Callon paid $36.0 million as a deposit into third-party escrow accounts. The transaction is structured as the acquisition by Callon Petroleum Operating Company of 100% of the interest in Percussion Petroleum Operating II, LLC. Closing of the transaction is expected to occur early in July 2023, subject to completion of various customary conditions.


			Page

Independent Auditor’s Report			1
Consolidated Financial Statements
Consolidated Balance Sheet			2
Consolidated Statement of Operations			3
Consolidated Statement of Changes in Members’ Equity			4
Consolidated Statement of Cash Flows			5
Notes to the Consolidated Financial Statements			6


						Members’ Equity

Balance, December 31, 2022						$216,716,865

Net Income						65,294,438

Balance, March 31, 2023						$282,011,303


Computers and software			3-10 years
Vehicles			5 years
Leasehold improvements			Lease term
Furniture and fixtures			10 years
Machinery and equipment			5-10 years


						March 31, 2023

Balance, beginning January 1,						$2,968,630
Additions						10,979
Accretion expense						88,163
Settlement of liabilities						(57,477)

Balance, ending March 31,						$3,010,295



Non-current portion						$3,010,295