Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2022 | Mar. 22, 2023 | Jun. 30, 2022 | |
Cover [Abstract] | |||
Entity Registrant Name | ALPINE SUMMIT ENERGY PARTNERS, INC. | ||
Entity Central Index Key | 0001882607 | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2022 | ||
Amendment Flag | false | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | No | ||
Document Annual Report | true | ||
Entity Current Reporting Status | Yes | ||
Entity Filer Category | Non-accelerated Filer | ||
Entity Common Stock, Shares Outstanding | 33,929,921 | ||
Document Fiscal Period Focus | FY | ||
Document Fiscal Year Focus | 2022 | ||
Entity Voluntary Filers | No | ||
Entity Emerging Growth Company | true | ||
Entity Small Business | true | ||
Entity Ex Transition Period | false | ||
Entity Shell Company | false | ||
Entity Interactive Data Current | Yes | ||
Document Transition Report | false | ||
Entity File Number | 001-41510 | ||
Entity Incorporation, State or Country Code | A1 | ||
Entity Address, Address Line One | 3322 West End Ave. | ||
Entity Address, Address Line Two | Suite 450 | ||
Entity Address, City or Town | Nashville | ||
City Area Code | 346 | ||
Local Phone Number | 264-2900 | ||
Entity Address, State or Province | TN | ||
Entity Address, Postal Zip Code | 37203 | ||
Entity Tax Identification Number | 98-1623755 | ||
Entity Public Float | $ 180,786,853 | ||
Title of 12(b) Security | Class A Subordinate Voting Shares | ||
Trading Symbol | ALPS | ||
Security Exchange Name | NASDAQ | ||
Auditor Name | WEAVER AND TIDWELL, L.L.P. | ||
Auditor Location | Houston, Texas | ||
Auditor Firm ID | 410 | ||
ICFR Auditor Attestation Flag | false |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) | Dec. 31, 2022 | Dec. 31, 2021 |
Current assets: | ||
Cash and cash equivalents | $ 7,123,068 | $ 8,622,815 |
Restricted cash | 3,375,395 | 0 |
Accounts receivable, net | 26,466,208 | 18,797,635 |
Derivative assets | 2,019,600 | 0 |
Prepaid expenses | 1,075,697 | 535,474 |
Total current assets | 40,059,968 | 27,955,924 |
Oil and natural gas properties, full-cost method: | ||
Evaluated | 347,541,801 | 110,155,103 |
Unproved and unevaluated | 42,866,767 | 24,987,312 |
Less: accumulated depreciation, depletion and amortization | (87,993,495) | (25,911,025) |
Oil and natural gas properties, net | 302,415,073 | 109,231,390 |
Other noncurrent assets: | ||
Operating lease assets | 548,963 | 434,488 |
Derivative assets | 1,057,479 | 0 |
Total assets | 344,081,483 | 137,621,802 |
Current liabilities | ||
Accounts payable and accrued liabilities | 96,432,486 | 48,245,677 |
Corporate credit facility | 41,500,000 | 2,200,000 |
Current portion of operating lease liabilities | 210,157 | 119,371 |
Current portion of long-term debt (net) | 60,226,919 | 7,059,834 |
Accrued liability for automatic share purchase plan | 4,670,507 | 0 |
Derivative liabilities | 0 | 6,479,508 |
Total current liabilities | 203,040,069 | 64,104,390 |
Long-term debt, net | 48,678,708 | 16,139,307 |
Operating lease liabilities | 401,734 | 389,218 |
Asset backed preferred instrument | 0 | 18,687,351 |
Derivative liabilities | 0 | 13,901,672 |
Asset retirement obligations | 458,078 | 431,704 |
Deferred income tax liability | 0 | 1,928,319 |
Total liabilities | 252,578,589 | 115,581,961 |
Redeemable non-controlling interest | 107,583,737 | 46,552,839 |
SHAREHOLDERS’ DEFICIENCY | ||
Additional paid-in capital | 36,436,307 | 40,252,848 |
Accumulated deficit | (76,210,173) | (83,638,308) |
Shareholders' equity (deficit) attributable to the Company | 9,000,921 | 28,687 |
Non-controlling interest | (25,081,764) | (24,541,685) |
Total Shareholders’ Deficiency | (16,080,843) | (24,512,998) |
TOTAL LIABILITIES, REDEEMABLE NON-CONTROLLING INTEREST AND SHAREHOLDERS’ DEFICIENCY | 344,081,483 | 137,621,802 |
Subordinate Voting Shares [Member] | ||
SHAREHOLDERS’ DEFICIENCY | ||
Share capital | 47,595,028 | 41,989,020 |
Multiple Voting Shares [Member] | ||
SHAREHOLDERS’ DEFICIENCY | ||
Share capital | 1,051,546 | 1,296,914 |
Proportionate Voting Shares [Member] | ||
SHAREHOLDERS’ DEFICIENCY | ||
Share capital | $ 128,213 | $ 128,213 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parentheticals) - shares | Dec. 31, 2022 | Dec. 31, 2021 |
Subordinate Voting Shares [Member] | ||
Common stock, shares issued | 33,956,073 | 32,535,731 |
Common stock, shares outstanding | 33,956,073 | 32,535,731 |
Multiple Voting Shares [Member] | ||
Common stock, shares issued | 8,380 | 10,336 |
Common stock, shares outstanding | 8,380 | 10,336 |
Proportionate Voting Shares [Member] | ||
Common stock, shares issued | 15,947 | 15,947 |
Common stock, shares outstanding | 15,947 | 15,947 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
REVENUES | ||
Oil and gas revenues | $ 195,648,957 | $ 70,796,790 |
Gain / (loss) on derivative instruments, net | (10,023,495) | (33,525,453) |
Revenues | 185,625,462 | 37,271,337 |
EXPENSES | ||
Production costs and transportation | 41,495,709 | 12,087,223 |
General and administrative | 26,090,160 | 25,021,117 |
Depreciation, depletion, and amortization | 62,082,471 | 23,497,715 |
Asset Retirement Obligation, Accretion Expense | 43,756 | 24,209 |
Total operating expenses | 129,712,096 | 60,630,264 |
OPERATING INCOME (LOSS) | 55,913,366 | (23,358,927) |
OTHER INCOME (EXPENSE) | ||
Finance and interest expense | (13,428,333) | (5,727,544) |
Acquisition costs | 0 | (1,567,967) |
Total other income (expense) | (13,428,333) | (7,295,511) |
INCOME (LOSS) BEFORE INCOME TAXES | 42,485,033 | (30,654,438) |
Income tax provision (benefit) | (1,928,319) | 1,928,319 |
NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) | 44,413,352 | (32,582,757) |
NET INCOME (LOSS) ATTRIBUTABLE TO REDEEMABLE NON-CONTROLLING INTEREST | 33,796,021 | 13,091,908 |
NET INCOME (LOSS) ATTRIBUTABLE TO NON-CONTROLLING INTEREST | 3,189,196 | (13,330,237) |
NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO THE COMPANY | $ 7,428,135 | $ (32,344,428) |
Earnings (loss) per SVS and PVS, and MVS on an as-converted basis | ||
Basic | $ 0.22 | $ (0.76) |
Diluted | $ 0.2 | $ (0.76) |
Weighted average number of shares per SVS and PVS, and MVS on an as-converted basis | ||
Basic | 34,453,696 | 42,596,264 |
Diluted | 53,586,327 | 42,596,264 |
CONSOLIDATED STATEMENTS OF CHAN
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' DEFICIT - USD ($) | Total Share Capital [Member] | Additional Paid-in Capital [Member] | Accumulated Deficit [Member] | Total shareholders' equity attributable to the Company [Member] | Non-controlling interests [Member] | Total |
Beginning balance at Dec. 31, 2020 | $ 37,097,376 | $ 3,721,683 | $ (39,408,964) | $ 1,410,095 | $ 1,410,095 | |
Issuance of member units for cash | 8,044,700 | 8,044,700 | 8,044,700 | |||
Issuance of member units exchanged for notes | 3,475,000 | 3,475,000 | 3,475,000 | |||
Issuance of member units for oil and gas properties | 3,499,995 | 3,499,995 | 3,499,995 | |||
Issuance of member units to contractors | 9,073,228 | 9,073,228 | 9,073,228 | |||
Redemption of member units | (8,680,786) | (11,884,916) | (20,565,702) | (20,565,702) | ||
Issuance of member units exchanged for notes | 2,300,000 | 2,300,000 | 2,300,000 | |||
Origination Member Units split 1:3 | 0 | |||||
Allocation of opening non-controlling interest | (18,721,276) | 30,208,275 | 11,486,999 | $ (11,486,999) | ||
Exchange of units for SVS and MVS | 0 | |||||
Shares issued for cash, net of issuance costs of $247,218 | 5,499,832 | 5,499,832 | 5,499,832 | |||
PVS issued for cash | 128,213 | 128,213 | 128,213 | |||
Shares issued on reverse recapitalization | 1,697,865 | 1,697,865 | 1,697,865 | |||
Stock based compensation | 5,405,548 | 5,405,548 | 5,405,548 | |||
Development partnership redemption for Origination Member Units | 917,342 | 917,342 | 275,551 | 1,192,893 | ||
Conversion of MVS to SVS | 0 | |||||
Net loss | (32,344,428) | (32,344,428) | (13,330,237) | (45,674,665) | ||
Ending balance at Dec. 31, 2021 | 43,414,147 | 40,252,848 | (83,638,308) | 28,687 | (24,541,685) | (24,512,998) |
Settlement of RSUs | 9,685,555 | (9,685,555) | ||||
Repurchase of SVS for cancellation | (4,324,915) | (4,324,915) | (4,324,915) | |||
Change in NCI ownership | 1,445,850 | 1,445,850 | (1,445,850) | |||
Automatic share purchase plan | (4,670,507) | (4,670,507) | (4,670,507) | |||
Stock based compensation | 10,197,720 | 10,197,720 | 10,197,720 | |||
Development partnership redemption for Origination Member Units | 11,312,710 | 11,312,710 | 4,269,258 | 15,581,968 | ||
Dividends declared | (12,416,759) | (12,416,759) | (6,552,683) | (18,969,442) | ||
Net loss | 7,428,135 | 7,428,135 | 3,189,196 | 10 | ||
Ending balance at Dec. 31, 2022 | $ 48,774,787 | $ 36,436,307 | $ (76,210,173) | $ 9,000,921 | $ (25,081,764) | $ (16,080,843) |
CONSOLIDATED STATEMENTS OF CH_2
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' DEFICIENCY (Parentheticals) | 12 Months Ended |
Dec. 31, 2022 USD ($) | |
Statement of Stockholders' Equity [Abstract] | |
Issuance costs of shares issued for cash | $ 247,218 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Cashflows from operating activities | ||
Net income (loss) | $ 44,413,352 | $ (32,582,757) |
Adjustments to reconcile net income (loss) to cashflows from operating activities: | ||
Depletion and depreciation | 62,082,471 | 23,497,715 |
Amortization of operating lease asset | 121,088 | 64,559 |
Asset retirement obligation accretion expense | 43,756 | 24,209 |
Share-based compensation | 10,197,720 | 14,478,776 |
Amortization of deferred financing costs | 5,199,882 | 1,058,759 |
Unrealized (gain) / loss on derivative instruments | (26,246,352) | 15,859,796 |
Deferred income tax expense (benefit) | (1,928,319) | 1,928,319 |
Margin returns/(calls) on derivative instruments, net | 2,788,093 | 0 |
Changes in operating assets and liabilities | 3,769,555 | 8,667,404 |
Cashflows from operating activities | 92,902,136 | 32,996,780 |
Cashflows used in investing activities | ||
Capital expenditures on oil and natural gas properties | (212,210,813) | (56,678,478) |
Cashflows from investing activities | (212,210,813) | (56,678,478) |
Cashflows from financing activities | ||
Issuance of shares for cash, net of issuance costs | 0 | 13,672,745 |
Cash acquired on acquisition | 0 | 396,173 |
Proceeds from Redeemable NCI | 53,728,933 | 41,042,693 |
Redemption and distributions to Redeemable NCI | (10,369,504) | (6,388,870) |
Proceeds from credit facility draws | 108,000,000 | 2,200,000 |
Repayment on credit facility | (68,700,000) | 0 |
Proceeds from promissory notes | 0 | 3,375,000 |
Repayment of promissory notes | 0 | (2,025,000) |
Repayment of asset backed preferred notes | (18,687,351) | (4,735,700) |
ABS Facility issuance, net of issuance costs | 130,761,336 | 0 |
Payment on ABS Facility | (25,017,323) | 0 |
Other long term debt repayment | (25,237,409) | (18,122,088) |
Dividends on common shares and noncontrolling interest | (18,969,442) | 0 |
Cash used for common share repurchases | (4,324,915) | 0 |
Cashflows provided by financing activities | 121,184,325 | 29,414,953 |
Net increase/(decrease) in cash and cash equivalents and restricted cash | 1,875,648 | 5,733,255 |
Cash, cash equivalents and restricted cash, beginning of year | 8,622,815 | 2,889,560 |
Cash, cash equivalents and restricted cash, end of year | $ 10,498,463 | $ 8,622,815 |
GENERAL
GENERAL | 12 Months Ended |
Dec. 31, 2022 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
GENERAL [Text Block] | 1. GENERAL Description of Business Alpine Summit Energy Partners, Inc. (formerly Red Pine Petroleum Ltd. ("Red Pine") (the "Company" or "Alpine Summit") was incorporated on July 30, 2008 under the Business Corporations Act (British Columbia) ("BCBCA"). On April 8, 2021, the Company entered into a Business Combination Agreement ("BCA") pursuant to which it agreed to complete the BCA with HB2 Origination LLC ("Origination") and changed its name to "Alpine Summit Energy Partners, Inc." upon completion of the BCA (described below). The Company is engaged in oil and natural gas development, production, acquisition, and exploration activities in Texas through its controlled subsidiary Origination. The Company's operating activities are mainly focused in the Austin Chalk and Eagle Ford formations in the Giddings Field, as well as the Hawkville Field. Reverse Takeover Agreement On April 8, 2021, the Company, Origination, Alpine Summit Energy Partners Finco, Inc. (“Finco”), Red Pine Petroleum Subco Ltd. (“Subco”) and Alpine Summit Energy Investors, Inc. (“Blocker”) entered into the BCA pursuant to which the parties agreed to complete a series of transactions to effect a combination between the Company (through its predecessor Red Pine Petroleum Ltd.) and Origination and that resulted in a reverse take-over (“RTO”) of the Company by the members of Origination. The principal steps of this transaction were as follows: (a) (b) (i) (ii) (iii) (c) (i) (ii) (iii) (iv) (v) (vi) (vii) (viii) The Finco Financing On August 18, 2021, Finco completed a brokered private placement of the Subscription Receipts, consisting of an aggregate of 161,976 subordinate voting subscription receipts at a subscription price of CAD$4.01 per subscription receipt and 17,057 multiple voting subscription receipts at a subscription price of CAD$401.29 per subscription receipt for aggregate gross proceeds of approximately CAD$7,500,000 (net proceeds of US$5,499,832). Finco is a special purpose British Columbia company incorporated solely for the purpose of the Finco Financing. The Finco Financing was completed pursuant to the terms of an agency agreement dated August 18, 2021 among Finco, the Company and Eight Capital ("Agent"), as lead agent and sole bookrunner. The Subscription Receipts are governed by the terms of the subscription receipt agreement (the "Subscription Receipt Agreement") dated August 18, 2021 among Finco, the Agent and Odyssey Trust Company in its capacity as subscription receipt agent. Each subordinate voting subscription receipt and each multiple voting subscription receipt entitled the holder thereof to receive, upon automatic exchange in accordance with the terms of the Subscription Receipt Agreement, without payment of additional consideration or further act or formality on the part of the holder thereof, one Class A share of Finco and one Class B share of Finco, respectively, upon the satisfaction or waiver of the escrow release conditions at or before the escrow release deadline. Each Class A share of Finco was exchanged for one SVS and each Class B share of Finco was exchanged for one MVS upon completion of the BCA. In connection with the Finco financing, the Agent was entitled to receive a cash commission of $21,002 and an advisory fee of $156,381 (collectively, the "Agent's Fees"). On closing of the Finco Financing, the Agent received payment of 50% of the Agent's Fees. The remaining 50% of the Agent's Fees were paid to the Agent upon the satisfaction of the escrow release conditions. Reverse Takeover On September 7, 2021, the Company completed the BCA (as described above). As a result, the former shareholders of Origination acquired control of the combined Company and, thereby the transaction constitutes a reverse recapitalization of Red Pine by Origination. The BCA is considered a purchase of the Red Pine's net assets by Origination. As Red Pine did not qualify as a business in accordance with Accounting Standards Codification ("ASC") Topic 805 - Business Combinations As a part of the reverse takeover, the Company issued 534,384 SVS on September 7, 2021, for total consideration of $1,697,865 based on the Finco Financing value of CAD$4.01/SVS (US$3.18/SVS), for the Red Pine net assets, which were made up primarily of cash valued at $396,173. The difference between the fair value of the consideration issued and the net assets acquired was recorded in additional paid in capital. Acquisition related costs of $1,567,967 were recognized as transaction costs in other income (expense) within the consolidated statements of operations and comprehensive income (loss) for the year ended December 31, 2021, when the costs were incurred. |
SUMMARY OF SIGNIFICANT ACCOUNTI
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 12 Months Ended |
Dec. 31, 2022 | |
Accounting Policies [Abstract] | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES [Text Block] | 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES These consolidated financial statements (the "financial statements") of the Company and its subsidiaries have been prepared in conformity with accounting principles generally accepted in the United States of America ("US GAAP"). Amounts are stated in US dollars unless otherwise noted. The Company historically prepared its consolidated financial statements under International Financial Reporting Standards. For the year ended and as at December 31, 2022 the Company transitioned to US GAAP and applied US GAAP retrospectively. Basis of Measurement The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities in the financial statements. In determining these estimates, management makes subjective and complex judgments that may require assumptions about matters that are inherently uncertain. The estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimate is revised if the revision affects only that period, or in the period of the revision and future periods if the revision affects both current and future periods. Estimates and assumptions that, in the opinion of the Company’s management, are significant include the estimation of oil and natural gas reserves and depletion (Note 2 below), the redemption value of redeemable non-controlling interests (Note 2 below and Note 9), determination of whether long-lived assets are impaired (Note 2 below), valuation of asset retirement obligations (Note 2 below and Note 6), and deferred tax assets/liabilities (Note 2 below and Note 15). The Company bases its estimates and judgments on historical experience and on various other assumptions and information believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be predicted with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained, or if the Company’s operating environment changes. Actual results may differ from the estimates and assumptions used in the preparation of these financial statements. Going Concern The financial statements have been prepared assuming that the Company will continue as a going concern, which contemplates continuity of operations, realization of assets, and liquidation of liabilities in the normal course of business. As at December 31, 2022 the Company had a working capital deficit of $162,980,101, reflecting a significant increase in outstanding accounts payable and accrued liabilities as well as borrowings, due to the Company’s increased capital expenditures on oil and natural gas properties. As a result, the Company does not currently have the cash resources to meet its current liabilities for the next twelve months. These factors raise substantial doubt about the Company’s ability to continue as a going concern. The Company’s ability to continue as a going concern is dependent on its ability to generate sufficient cash flows from operations, as well as its ability to obtain financing via an asset sale and/or the issuances of debt and/or equity in the short term. While the Company believes it has sufficient forecasted funds to meet foreseeable obligations, there can be no assurance that the Company will be successful in its efforts to raise additional funds in the short term and its ability to generate sufficient operating cash flows. Due to these factors, the Company may be unable to continue as a going concern. The financial statements do not include any adjustments related to the recoverability and classification of recorded asset amounts or the amounts and classification of liabilities that might be necessary should the Company be unable to continue as a going concern, and such adjustments could be material. Basis of Consolidation Subsidiaries The financial statements include the accounts of the Company and its consolidated subsidiaries, after the elimination of intercompany transactions and balances. The Company consolidates all entities that it controls either through a majority voting interest or as the primary beneficiary of variable interest entities ("VIEs"). The Company evaluates (1) whether it holds a variable interest in an entity, (2) whether the entity is a VIE, and (3) whether the Company's involvement would make it the primary beneficiary. The assessment of whether the entity is a VIE is generally performed qualitatively, which requires judgment. These judgments include: (a) determining whether the equity investment at risk is sufficient to permit the entity to finance its activities without additional subordinated financial support, (b) evaluating whether the equity holders, as a group, have the characteristics of a controlling financial interest, (c) determining whether two or more parties' equity interests should be aggregated, (d) determining whether the equity investors have proportionate voting rights to their obligations to absorb losses or rights to receive returns from the entity, and (e) if disproportionate voting rights are identified, whether substantially all of the investee's activities are on behalf of an investor that has disproportionately few voting rights. Significant judgements involve the analysis of the risks and rewards that the VIE's operations generate and the nature of the Company's involvement with and interest in the VIE, including the form of the Company's ownership interest, representation in an entity's governance, and ability to participate in making decisions. For entities that are determined to be VIEs, the Company consolidates those entities where it has concluded it is the primary beneficiary. The primary beneficiary is defined as the variable interest holder with (a) the power to direct the activities of a VIE that most significantly impact the entity's economic performance and (b) the obligation to absorb losses or the right to receive benefits from the entity that could potentially be significant to the VIE. In evaluating whether the Company is the primary beneficiary, the Company evaluates its economic interests in the entity held either directly or indirectly by the Company, and its ability to control the VIEs through arrangements such as general partnership interests or contracts. The Company's consolidated VIEs consist of its controlled subsidiary, Origination, as its control over Origination is contractually provided and not granted via the equity interest. Origination, through its subsidiaries, holds the Company's main operations, including external financing. Some of Origination's drilling programs are structured through limited partnerships (the "Development Partnerships"), which are consolidated VIEs of Origination (see Note 9). Under the contractual agreements with the VIEs, the Company has the power to direct activities of the VIEs and can have assets transferred out of the VIEs under its control. Therefore, the Company considers that there is no asset in any of the VIEs that can be used only to settle obligations of the VIE, except for certain assets that are designated as collateral for long term debt (Note 7). If an entity is determined to not be a VIE, the voting interest entity model is applied, where an investor holding the majority voting rights consolidates the entity. Ownership interests in subsidiaries represented by other parties that do not control the entity are presented in the consolidated financial statements as activities and balances attributable to noncontrolling interests. Joint Arrangements A portion of the Company's oil and natural gas business activities involve jointly controlled assets and are conducted under joint operating agreements. These consolidated financial statements reflect only the Company's proportionate share of the joint operation's controlled assets and liabilities it has incurred, its share of any liabilities jointly incurred with other joint interest partners, income from the sale or use of its share of the joint operation's output, together with its share of expenses incurred by the joint operation and any expenses it incurs in relation to its interest and its share of production in such activities. Segment Reporting The Company operates in a single operating and reportable segment. Operating segments are defined as components of a public entity for which separate financial information is regularly reviewed by the chief operating decision maker in deciding how to allocate resources and assess performance. The Company's chief operating decision maker allocates resources and assesses performance based upon financial information at the Company level. The Company's operations are primarily conducted in, and its assets are primarily located in, the United States of America. The Company's revenues are entirely generated in the United States of America. Functional and Presentation Currency These financial statements are presented in US dollars. The functional currency of the Company and its individual subsidiaries is the US dollar, which represents the primary economic environment in which the entities operate. Foreign currency transactions are those transactions whose terms are denominated in a currency other than the functional currency. Transactions denominated in foreign currencies are translated to the functional currency using the exchange rate prevailing at the date of the transactions. Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency using the exchange rate in effect as at the balance sheet date. Exchange gains and losses resulting for the remeasurement of monetary assets and liabilities are included in general and administrative expenses in the consolidated statements of operations and comprehensive income (loss) in the period in which they arise. Cash and Cash Equivalents Cash and cash equivalents include short-term investments with a term to maturity of three months or less when purchased (Note 18). Restricted Cash Cash and cash equivalents that are restricted as to the withdrawal or usage, in accordance with specific arrangements, are presented as restricted cash. The amount of restricted cash as of December 31, 2022 is $3,375,395 (December 31, 2021 - $nil), reflecting the interest reserve account maintained in connection with the asset backed securitization facility (Note 7). Accounts Receivable, Net The accounts receivable are primarily receivables from crude oil, natural gas, and natural gas liquids customers and joint interest owners. Oil and natural gas sales are normally collected by the Company between 30 and 60 days from deliveries. Joint interest receivables are typically collected within 30 to 90 days of the joint interest bill being issued to the partner. Accounts receivable, net are recorded at amortized cost. Management evaluates all accounts periodically and an allowance is established based on the best facts available. Management considers historical collection data, accounts receivable aging trends, other operational trends and reasonable forecasts to estimate the collectability of receivables. The Company's accounts receivable are subject to normal industry credit risk (Note 18). Derivatives The Company has entered into certain financial risk management contracts in order to manage the exposure to market risks from fluctuations in commodity prices and interest rates. The Company considers all risk management contracts to be economic hedges, but has not designated its financial risk management contracts as accounting hedges and, therefore, has not applied hedge accounting. As a result, all financial risk management contracts are measured at fair value with changes in fair value recognized in income (Note 17). Transaction costs are recognized in the consolidated statements of operations and comprehensive income (loss) as incurred. In the consolidated balance sheets, the fair values of the derivative instruments are presented as current and non-current assets or liabilities depending on the timing of settlements and the resulting cash flows associated with the instruments. Fair value amounts related to cash flows occurring beyond one year are classified as non-current (Note 18). Oil and Natural Gas Properties, Net Oil and Natural Gas Properties The Company uses the full-cost method of accounting for its oil and natural gas properties. Under this method, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing the Company's activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, and general and administrative expenses directly related to acquisition, exploration and development activities, but does not include any costs related to production, selling or general corporate administrative activities. Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between net capitalized costs and proved reserves of oil and gas. All costs related to production activities and maintenance and repairs are expensed as incurred. Significant workovers that increase the properties' reserves are capitalized. In the years ended December 31, 2022 and 2021, there were no property sales that resulted in a significant alteration. Depletion Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method. Under this method, depletion is calculated at the end of each period by multiplying total production for the period by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus estimates of future development costs by estimates of proved reserves quantities. Unproved and unevaluated property costs and related carrying costs are excluded from the depletion base until the properties associated with these costs are considered proved or impaired. The Company reviews its unproved and unevaluated properties at the end of each quarter to determine whether the costs incurred should be transferred to the full cost pool and thereby subject to amortization. Upon impairment, which includes leases that have expired or have been deemed uneconomic, the costs of the unproved properties are immediately included in the depletion base. The determination of depletion is significantly impacted by the proved reserves volumes and future development costs. Relative volumes of reserves and production are converted at the energy equivalent conversion ratio of six thousand cubic feet of natural gas to one barrel of oil. Impairment Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the net capitalized costs of oil and natural gas properties. The net capitalized costs are limited to the lower of unamortized costs less related deferred income taxes or the cost center ceiling. The cost center ceiling is defined as the sum of: (a) the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus (b) unproved and unevaluated property costs not being amortized, plus (c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less (d) any income tax effects related to the properties involved. Any excess of the Company's net capitalized costs above the cost center ceiling is expensed as a full-cost ceiling impairment. The Company's derivative instruments are not considered in the ceiling test computations as the Company does not designate these instruments as hedges for accounting purposes. The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent on the quantities of proved reserves, the estimation of which requires substantial judgement. The associated commodity prices and the applicable discount rate used in these estimates are in accordance with guidelines established by the United States Securities and Exchange Commission. Under these guidelines, oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost changes in future periods except by contractual arrangements. Future net revenues are calculated using prices that represent the arithmetic averages of the first-day-of-the-month oil and natural gas prices for the previous 12-month period, and a 10% discount factor is used to determine the present value of future net revenues. For the period from January through December 2022, these average oil and natural gas prices were $94.49 per Bbl and $6.25 per MMBtu, respectively. For the period from January through December 2021, these average oil and natural gas prices were $66.55 per Bbl and $3.64 per MMBtu, respectively. In estimating the present value of after-tax future net cash flows from proved oil and natural gas reserves, the average oil prices were further adjusted by property for quality, transportation and marketing fees and regional price differentials, and the average natural gas prices were further adjusted by property for energy content, transportation and marketing fees and regional price differentials. During the years ended December 31, 2022 and 2021, the Company's full-cost ceiling exceeded the net capitalized costs less related deferred income taxes. As a result, the Company recorded no impairment to its net capitalized costs for those periods. As a non-cash item, the full-cost ceiling impairment impacts the accumulated depletion and the net carrying value of the Company’s assets on its consolidated balance sheets, as well as the corresponding shareholders’ deficiency, but it has no impact on the Company’s net cash flows as reported. Changes in oil and natural gas production rates, oil and natural gas prices, reserves estimates, future development costs and other factors will determine the Company’s actual ceiling test computation and impairment analyses in future periods. Other Impairment Estimates Unproved and unevaluated properties are assessed periodically to determine whether they have been impaired, based on the Company's future development plans, the probability of successful development of properties and the length of time that the Company expects to hold the properties, amongst other factors. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the depletion base. Exploratory dry holes are included in the depletion base immediately upon determination that the well is not productive. During the year ended December 31, 2022 and 2021, no unproved and unevaluated properties were impaired and transferred to be included in the depletion base as part of evaluated properties. Reserves The assessment of reported recoverable quantities of proved reserves includes estimates regarding production volumes, commodity prices, remediation costs, timing and amount of future development costs, and production, transportation and marketing costs for future cash flows. It also requires interpretation of geological and geophysical models in anticipated recoveries. The economical, geological and technical factors used to estimate reserves may change from period to period. Changes in reported reserves can impact the carrying values of the Company's oil and natural gas properties, the calculation of depletion and depreciation, and the provision for asset retirement obligations. The reserve assessment was completed by an external third-party engineering firm for the years ended December 31, 2022 and 2021 and reserves are internally updated for interim periods. Asset Retirement Obligations The Company recognizes asset retirement obligations ("ARO") arising from regulatory, contractual or other legal requirements to perform certain property and asset reclamation activities at the end of the respective asset life when the fair value of this obligation is determinable. These obligations consist of estimated future costs associated with the plugging and abandonment of natural gas and oil wells, and land restoration in accordance with applicable local, state and federal laws. The Company estimates the expected cash flows associated with the obligation and discounts the amounts using a credit-adjusted risk-free interest rate. This discounted fair value of the ARO liability is recognized in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying cost of the related natural gas and oil asset in property, plant and equipment, net and depleted as the reserves are produced. In the estimation of the initial fair value of an ARO, the Company uses assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation, technical assessments of the assets, estimated amounts and timing of settlements including reserve lives, discount rates, and inflation rates. Given the significance of the unobservable nature of a number of the inputs, this measurement is considered Level 3 on the fair value hierarchy (Note 17). In periods subsequent to the initial measurement of an ARO, period-to-period changes are recognized in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the related asset. Accretion, reflecting the increases in the ARO liability due to the passage of time is recognized as part of operating expenses within the consolidated statements of operations and comprehensive income (loss) (Note 6). Leases The Company assesses whether a contract is or contains a lease, at the inception of a contract. A contract is, or contains, a lease if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. The Company recognizes a right-of-use ("ROU") asset and a corresponding lease liability with respect to lease arrangements in which it is the lessee, except for short-term leases (defined as leases with a lease term of 12 months or less). For such short-term leases, the Company recognizes the lease payments as an operating expense on a straight-line basis over the term of the lease unless another systematic basis is more representative of the time pattern in which economic benefits from the leased asset are consumed. The Company also made the accounting policy election to not separate lease and non-lease components for its real estate leases. The lease liability is initially measured at the present value of the unpaid lease payments at the commencement date, discounted by using the rate implicit in the lease. If this rate cannot be readily determined, the Company uses its incremental borrowing rate. Subsequently, the lease liability is measured using the effective interest method, by increasing the carrying amount to reflect accretion on the lease liability and by reducing the carrying amount to reflect the lease payments made. The ROU asset is initially measured at cost, which comprises the initial amount of the lease liability adjusted for lease payments made at or before the lease commencement date, plus any initial direct costs incurred less any lease incentives received. For operating leases, the Company records the amortization of the ROU assets and the accretion of the lease liabilities as a single lease cost on a straight-line basis over the lease term. The measurement of the lease liabilities and ROU assets requires the use of judgment and estimates which are applied in determining whether an arrangement contains a lease, determining the lease term, appropriate discount rate, and whether there are any indicators of impairment for ROU assets. Revenue from Contracts with Customers The Company enters into contracts with customers to sell its oil, natural gas and natural gas liquids. Revenue from these contracts is recognized when the Company's performance obligations are satisfied, which generally occurs with the transfer of the control to the customer, and when collectability is reasonably assured. The transfer of control usually occurs when the product is physically transferred at the delivery point agreed upon in the contract and legal title to the product passes to the customer (often at terminals, pipelines, or other transportation methods). The Company evaluates creditworthiness on an individual customer basis prior to entering into a sales contract and throughout the contract duration (Note 18) . The sales contracts range from short term to long term contracts that are variable-priced and based on actual quantities delivered each period. The transaction price includes variable consideration as product pricing is based on published market prices and adjusted for contract specified differentials such as quality, energy content and transportation. Determining the variable consideration does not require significant judgment and the Company engages third party sources to validate the estimates. 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 – Revenue from Contracts with Customers (“ASC 606”). The expedient applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. The Company evaluates its arrangements with third parties and partners to determine if the Company acts as the principal or as an agent. In making this evaluation, the Company considers if it obtains control of the product delivered or services provided, which is indicated by the Company having the primary responsibility for the delivery of the product or rendering of the service, having the ability to establish prices or having inventory risk. If the Company acts in the capacity of an agent rather than as a principal in a transaction, then the revenue is recognized on a net-basis. Revenue is recognized net of royalties due to third parties in an amount that reflects the consideration the Company expects to receive in exchange for those products. Share Based Compensation The Company grants share purchase options, which are classified as equity settled awards. The fair value of each option granted by the Company are estimated using the Black-Scholes option pricing model and are recognized into general and administrative expense over the vesting period of the options. The Company has also issued restricted share units (“RSUs”) and deferred share units (“DSUs”) which are both accounted for as equity classified awards. The Company’s RSUs and DSUs grants are valued using the intrinsic value method, utilizing the closing share price on the day before the grant and are recognized into general and administrative expense over the vesting period for each grant (Note 12). In all cases for these awards, the Company estimates forfeitures and updates this estimate over the vesting period of the awards. Income Taxes Income tax expense comprises current and deferred tax. The expense is recognized in net income (loss) except to the extent that it relates to a business combination, or items recognized directly in equity or in other comprehensive income (loss). Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Each reporting period, the Company reviews its deferred tax assets for the possibility they will not be realized. A valuation allowance will be recorded if it is more likely than not that a deferred tax asset will not be realized. The benefits of uncertain tax positions that the company has taken or expects to take in its income tax returns are recognized in the financial statements if management concludes that it is more likely than not that the position will be sustained with the tax authorities. Significant judgment is required in the accounting for income tax contingencies and tax disputes because the outcomes are often difficult to predict. The Company did not have any uncertain tax positions during the periods presented in these financial statements. Interest and penalties are recognized in finance expense and income tax expense, respectively. For the fiscal years ended December 31, 2022 and 2021, the Company did not incur interest and penalties related to income taxes. Non-Controlling Interests Non-controlling interests ("NCI") represent ownership interest in consolidated subsidiaries which are not owned, directly or indirectly, by the Company. The portion of equity not owned by the Company in such entities is reflected as NCI within the equity section of the consolidated balance sheets, and the share of income/(loss) attributable to NCI is shown as a component of net income/(loss) in the consolidated statements of operations and comprehensive income (loss). Changes to the parent company's ownership that do not result in a loss of control are accounted for as equity transactions. Redeemable Non-controlling Interests Non-controlling interests with redemption features that are not solely within the control of the Company are considered redeemable non-controlling interests. The Company's redeemable non-controlling interests ("Redeemable NCI") reflects the development partnership units that are not held by the Company either directly or indirectly, and which contain certain redemption rights, as described in Note 9. The Redeemable NCI is classified in temporary equity that is reported between liabilities and shareholders’ deficiency on the consolidated balance sheets and is initially recognized at its issuance date fair value. Subsequently, the Redeemable NCI is adjusted each reporting period for the net income (or loss) attributable to the Redeemable NCI interests. Further measurement adjustments are made to adjust the Redeemable NCI to the higher of the redemption value or the carrying value each reporting period. The measurement adjustments to the redemption value are recognized through accumulated deficit and are reflected in the attribution of net income (loss) between the NCI holders, the common shareholders of the Company and the Redeemable NCI holders, such that an increase in the redemption value over the carrying value would increase the net income attributed to the Redeemable NCI. The redemption value is calculated based on future net present values of the oil and gas reserves of the related development partnership, subject to a fixed discount rate. Adoption of New Accounting Standards Accounting Standards Update ("ASU") 2019-12, Income Taxes (Topic 740) - Simplifying the Accounting for Income Taxes ASU 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity's Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity's Own Equity ASU 2020-04, Reference Rate Reform (Topic 848) - Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848 Future Accounting Standard Changes ASU 2021-08 - Business Combinations (Topic 805): Accounting for Co |
ACCOUNTS RECEIVABLE, NET
ACCOUNTS RECEIVABLE, NET | 12 Months Ended |
Dec. 31, 2022 | |
Receivables [Abstract] | |
ACCOUNTS RECEIVABLE, NET [Text Block] | 3. ACCOUNTS RECEIVABLE, NET The accounts receivable, net balances consist of: December 31, 2022 2021 Trade receivables from sales of crude oil and natural gas $ 24,097,294 $ 18,110,135 Joint interest billing receivables and other 2,368,914 687,500 Accounts receivable, net $ 26,466,208 $ 18,797,635 The Company has not had significant credit losses in the past and believes its accounts receivables are fully collectible. As such, no allowance for expected losses has been made as of December 31, 2022 and 2021, and no bad debt expense was recognized in the years presented in these financial statements. |
OIL AND NATURAL GAS PROPERTIES
OIL AND NATURAL GAS PROPERTIES | 12 Months Ended |
Dec. 31, 2022 | |
Oil and Gas Property [Abstract] | |
OIL AND NATURAL GAS PROPERTIES [Text Block] | 4. OIL AND NATURAL GAS PROPERTIES The property, plant and equipment, net balances consist of: December 31, 2022 2021 Oil and natural gas properties: Evaluated (subject to depletion) $ 347,541,801 $ 110,155,103 Unproved and unevaluated (not subject to depletion) 42,866,767 24,987,312 Total oil and gas properties 390,408,568 135,142,415 Accumulated depreciation, depletion, and amortization (87,993,495 ) (25,911,025 ) Oil and gas properties, net $ 302,415,073 $ 109,231,390 The Company recognized depletion and depreciation of $62,082,471 during the year ended December 31, 2022 (December 31, 2021 - $23,497,715). The depletion per barrel of oil equivalent ("BOE") produced was an average of $16.18 for the year ended December 31, 2022 (December 31, 2021 - $15.66). The unproved and unevaluated property costs not subject to depletion as of December 31, 2022 and the year in which these costs were incurred, are as follows: Description 2022 2021 2020 2019 and Total Costs incurred for: Property acquisition $ 2,244,517 $ 4,300,745 $ - $ 1,243,615 $ 7,788,877 Exploration 1,635,842 1,222,509 - - 2,858,351 Development 32,219,539 - - - 32,219,539 Total unproved and unevaluated (not subject to depletion) $ 36,099,898 $ 5,523,254 $ - $ 1,243,615 $ 42,866,767 Property acquisition costs are costs incurred to purchase, lease or otherwise acquire oil and natural gas properties, but may also include broker and legal expenses, geological and geophysical expenses and capitalized internal costs associated with developing oil and natural gas prospects on these properties. Property acquisition costs incurred that remain in unproved and unevaluated property as at December 31, 2022 are mainly related to the Company's in progress development of wells in both the Giddings and the Hawkville fields. The Company believes that the majority of these unproved costs will become subject to depletion within the next two to three years by proving up reserves relating to the acreage through exploration and development activities, by impairing the acreage that will expire before the Company can explore or develop it further or by determining that further exploration and development activity will not occur. Costs excluded from depletion also include those costs associated with exploration and development wells in progress or awaiting completion at year-end. These costs are transferred into the depletion base on an ongoing basis as these wells are completed and proved reserves are established or confirmed. The Company anticipates that the majority of the costs associated with these wells in progress at December 31, 2022 will be transferred to the amortization base during 2023. Unproved and unevaluated property costs for exploration and development wells incurred in years prior to 2022 are costs related to the advanced preparation for wells that the Company intends to drill in the future. |
LEASES
LEASES | 12 Months Ended |
Dec. 31, 2022 | |
Leases [Abstract] | |
LEASES [Text Block] | 5. LEASES The Company's leases consist of leases for office space, which are classified as operating leases. The Company incurred total operating lease costs of $137,782 during the year ended December 31, 2022 (December 31, 2021 - $74,101), and total variable lease costs of $77,705 during the year ended December 31, 2022 (December 31, 2021 - $1,069). These costs are included within general and administrative expenses on the consolidated statements of operations and comprehensive income (loss). The cash paid for amounts included in the measurement of lease liabilities were $144,539 during the year ended December 31, 2022 (December 31, 2021 - $nil). This amount is included in operating activities in the consolidated statements of cash flows. As at December 31, 2022, the operating lease liabilities are expected to mature as follows: Operating Leases 2023 $ 234,092 2024 237,524 2025 181,363 Total undiscounted lease payments 652,979 Less: effect of discounting (41,088 ) Total lease liability $ 611,891 The Company has also entered into an agreement for the lease of new office space, which has not commenced as at December 31, 2022, and has thereby not yet been recognized. The lease is expected to commence in the fall of 2023. The initial non-cancellable term of this lease is for 10 years, with the undiscounted lease payments over the non-cancellable term equal to $2,226,432, plus variable lease costs for operating costs. |
ASSET RETIREMENT OBLIGATIONS
ASSET RETIREMENT OBLIGATIONS | 12 Months Ended |
Dec. 31, 2022 | |
Asset Retirement Obligation Disclosure [Abstract] | |
ASSET RETIREMENT OBLIGATIONS [Text Block] | 6. ASSET RETIREMENT OBLIGATIONS 2022 2021 Balance as at January 1 $ 431,704 $ 219,937 Liabilities incurred and acquired 89,636 121,553 Liabilities settled (127,862 ) (29,913 ) Revision of estimates 20,844 95,918 Accretion expense 43,756 24,209 Balance as at December 31 $ 458,078 $ 431,704 The total future AROs were estimated based on the Company's net ownership interest in petroleum and natural gas assets including well sites, the estimated costs to abandon and reclaim the petroleum and natural gas assets and the estimated timing of the costs to be incurred in future periods. As at December 31, 2022, the Company estimated the total undiscounted amount of cash flows required to settle its ARO to be approximately $2,634,225 (December 31, 2021 – $ 1,340,178) which will be incurred between 2023 and 2054. As at December 31, 2022, a weighted average credit-adjusted risk-free interest rate of 10.32% (December 31, 2021 – 9.73%) and an inflation rate of 2.28% (December 31, 2021 – 2.42%) were used to calculate the ARO. The Company has no assets that are legally restricted for purposes of settling AROs. |
DEBT
DEBT | 12 Months Ended |
Dec. 31, 2022 | |
Debt Disclosure [Abstract] | |
DEBT [Text Block] | 7. DEBT Asset Backed Securitization Facility In 2022, the Company entered into an asset backed securitization of certain producing oil and gas wells (the "ABS Facility"). The ABS Facility is led by an insurance company, and all borrowings under the ABS Facility are secured by working interests in a subset of the Company's producing assets, which are held by a subsidiary of its operating subsidiary, Origination. The ABS Facility consists of the following tranches: • On April 27, 2022 the ABS Facility had an initial size of $80,000,000 ("Tranche 1") with additional capacity to expand up to $150,000,000 in total based on the underlying collateral. Tranche 1 of the ABS Facility carries an interest rate of LIBOR+6% (with a 1% LIBOR floor) for the initial year, LIBOR +12% (with a 1% LIBOR floor) for the second year. Tranche 1 has an initial maturity date of one year, with the Company having the option to extend an additional year to an ultimate maturity date of April 2024. Interest payments are required monthly. • On September 12, 2022 the ABS Facility was increased by $55,000,000 ("Tranche 2"), to a total size of $135,000,000. Tranche 2 of the ABS Facility carries an interest rate of LIBOR+8% (with a 1% LIBOR floor) for the initial year, LIBOR +14% (with a 1% LIBOR floor) for the second year. Tranche 2 has an initial maturity date of one year, with the Company having the option to extend an additional year to an ultimate maturity date of September 2024. Interest payments are required monthly. The Company's subsidiaries have certain financial covenants under the ABS Facility, including maintaining a debt service coverage ratio of no less that 1.1 to 1.0. Under the terms of the ABS Facility, the Company is also required to: (i) As of the initial borrowing date, enter into certain forward commodity swap contracts included in Note 18 which it has done. (ii) Maintain an interest reserve account that will hold a cash balance sufficient to cover three months of scheduled interest payments (Note 2 - restricted cash). Repayments of the undiscounted principal required under the ABS Facility for each year noted are as follows: 2023 $ 61,630,567 2024 48,352,110 2025 and thereafter - Total $ 109,982,677 In addition to the required principal repayments outlined above, the Company's subsidiaries could also be required to make additional payments: (i) (ii) (iii) At December 31, 2022, the Company was not subject to any other additional principal prepayments. The carrying value of the outstanding loan balances is composed of: December 31, 2022 Current Long-term Total (net) Principal drawn $ 61,630,567 $ 48,352,110 $ 109,982,677 Unamortized discount and interest at the imputed rate 680,615 842,926 1,523,541 Unamortized debt issuance costs (2,084,263 ) (516,328 ) (2,600,591 ) Total (net) $ 60,226,919 $ 48,678,708 $ 108,905,627 As the ABS Facility is an increasing rate debt, finance expense is recognized based on the imputed effective interest rate of 12.2% and 13.6% for Tranche 1 and 2 over the expected two-year term of each tranche, respectively, plus the LIBOR interest rate component. As a result, interest expense recognized in the first year of each tranche will exceed interest paid, and effectively result in an interest accrual, shown as unamortized discount and interest at the imputed rate above. For the year ended December 31, 2022, the Company incurred $8,968,929 of finance expense (December 31, 2021 - $nil), and interest paid on the ABS Facility was $5,808,996. Goldman Facility On December 22, 2020, the Company entered into a credit facility with Goldman Sachs (the "Goldman Facility"). All borrowings under the Goldman Facility were secured by the Company's oil and gas producing wells and the assets of three of the Company's subsidiaries. The Goldman Facility carried an interest rate of LIBOR+6% (with a 1% LIBOR floor) and had a maturity date of December 2031. Interest payments were required quarterly. In April 2022, in connection with the ABS Facility, the Company repaid the Goldman Facility in full and amortized the remaining unamortized borrowing costs. The outstanding balances under this facility were as follows: December 31, 2022 Current Long-term Total (net) Principal drawn - - - Unamortized discount and debt issuance costs - - - Total (net) - - - December 31, 2021 Current Long-term Total (net) Principal drawn $ 7,722,206 $ 17,515,203 $ 25,237,409 Unamortized discount and debt issuance costs (662,372 ) (1,375,896 ) (2,038,268 ) Total (net) $ 7,059,834 $ 16,139,307 $ 23,199,141 For the year ended December 31, 2022, the Company incurred $2,420,486 of finance expense related to the facility (December 31, 2021 - $3,612,927). Corporate Credit Facility In October 2021, the Company's operating subsidiary Origination closed on a corporate credit facility (the "Corporate Credit Facility"). The Corporate Credit Facility had a maximum borrowing capacity of $12,500,000, subject to quarterly borrowing base determinations by the lender. The loan charged interest at prime +2.25% and had a one-year maturity. A subset of certain Company working interests in producing assets were secured in connection with the Corporate Credit Facility. During the first quarter of 2022, Origination closed a new Corporate Credit Facility to replace the previous facility. The new Corporate Credit Facility had a maximum borrowing capacity of $30,000,000, which was subsequently increased in October 2022 to $65,000,000, subject to quarterly borrowing base determinations by the lender. The Corporate Credit Facility is secured by working interests in a subset of the Company's producing assets and charges interest at the greater of 5.00% and prime +1.75% and has a one-year maturity. As of December 31, 2022, the Company had drawn $41,500,000 under the Corporate Credit Facility (December 31, 2021 - $2,200,000), and for the year ended December 31, 2022, incurred $1,736,868 of interest expense related to the facility (December 31, 2021 - $nil). The borrowing base as of December 31, 2022 was $64,435,764 (December 31, 2021- $6,579,750). |
OTHER DEBT INSTRUMENTS
OTHER DEBT INSTRUMENTS | 12 Months Ended |
Dec. 31, 2022 | |
Disclosure of Securitized or Asset-Backed Financing Arrangement Assets and Other Financial Assets Managed Together [Abstract] | |
OTHER DEBT INSTRUMENTS [Text Block] | 8. OTHER DEBT INSTRUMENTS Asset Backed Preferred Instruments On March 5, 2021, Origination executed an Origination Member Units buy-back structure, in which a member exchanged 100% of their holdings (3,992,629 Origination Member Units representing approximately 23.4% of the outstanding Origination Member Units at the time) along with a $1,000,000 promissory note for 23,500,000 mandatorily redeemable units in a newly created limited partnership controlled by Origination (the "LP Units"). The redemption terms of these LP Units required: 6,670,000 of the LP Units were required to be redeemed at the following prices per unit, depending on when the redemption was made: before May 1, 2021 at $0.71 per LP Unit, or thereafter but before June 1, 2021 at $0.8809 per LP Unit, or thereafter but before September 1, 2021 at $1.00 per LP Unit. If not paid by September 1, 2021, the LP Units would be considered in default. The remaining 16,830,000 LP Units were required to be redeemed at $1.00 per LP Unit by March 5, 2024. If not redeemed by that date, the redemption price would increase to $1.35 per LP Unit and the Company would be considered to be in default. While outstanding, all LP Units earned a fixed rate of return of 12% per annum, which increased to 17% in any event of default. The LP Units were determined to be mandatorily redeemable instruments, classified as a liability, initially measured at fair value and subsequently at amortized cost. As a result of the buy-back, the Company recorded a reduction to Origination Member Units of $8,680,786 (weighted average issue price of $21.7/unit) a reduction in promissory note liability of $1,000,000, a liability for the LP Units at an initial fair value of $21,565,702 and a reduction to accumulated deficit of $11,884,916. The fair value of the LP Units was determined by discounting the expected cash flows related to the instrument at the market-based rate of 12% per annum at that time. In the second quarter of 2021, the Company redeemed 6,670,000 LP Units at $0.71 per LP Unit for a total amount of $4,735,700. In 2022, the Company redeemed the remaining LP Units for $16,830,000, plus accrued interest of $2,515,398, using the proceeds from the ABS Facility (Note 7). For the year ended December 31, 2022, the Company recorded finance expense related to the outstanding LP Units in the amount $658,047 (December 31, 2021 - $1,857,351). Promissory and Convertible Promissory Notes The Company did not have promissory and convertible promissory notes outstanding during the year ended December 31, 2022. 2022 2021 Balance as at January 1 - $ 5,425,000 Issued for cash - 3,375,000 Converted to Origination Member Units - (3,475,000 ) Converted to LP Units - (1,000,000 ) Repayment of notes - (2,025,000 ) Converted to Origination Member Units - (2,300,000 ) Balance as at December 31 - - During the year ended December 31, 2021, Origination issued $3,375,000 in promissory and convertible promissory notes for cash, some of which were held by officers of the Company. The outstanding promissory notes were settled as follows in the year ended December 31, 2021: $3,475,000 in promissory notes were settled via the issuance of 353,870 Origination Member Units, and $1,000,000 in promissory notes was exchanged and settled as part of the receipt of LP Units, in connection with the Asset Backed Preferred Instrument. $1,755,000 in promissory notes was paid in cash, and $270,000 in promissory notes was offset with agreed upon overhead expenses paid by the Company on behalf of the note holders, which was shown as a reduction of general and administrative expenses. $2,300,000 of the convertible promissory notes were converted into 234,216 Origination Member Units. For the year ended December 31, 2022, the Company recorded finance expense related to the promissory and convertible promissory notes in the amount of $nil (December 31, 2021 - $300,685). |
REDEEMABLE NON-CONTROLLING INTE
REDEEMABLE NON-CONTROLLING INTERESTS | 12 Months Ended |
Dec. 31, 2022 | |
Temporary Equity Disclosure [Abstract] | |
REDEEMABLE NON-CONTROLLING INTERESTS [Text Block] | 9. REDEEMABLE NON-CONTROLLING INTERESTS The following table outlines the movement in redeemable non-controlling interests in the years presented. 2022 2021 Balance as at January 1 $ 46,552,839 $ - Redeemable non-controlling interests issued 154,456,707 55,138,395 Net loss and comprehensive loss attributed 10,598,514 12,851,005 Revaluation to redemption value, net 23,197,507 240,903 Distributions (3,340,254 ) (6,388,870 ) Settlement (123,881,576 ) (15,288,594 ) Balance as at December 31 $ 107,583,737 $ 46,552,839 The Company has established the Development Partnerships as a mechanism to partially finance its development projects and activities. The redeemable non-controlling interest reflects the development partnership units that are not held by the Company either directly or indirectly. These external units consist of: (a) the Flat Payout Units, and (b) the IRR Payout Units. The Flat Payout Units and the IRR Payout Units are entitled to 75% of the distributions of the related development partnership, until the "Base Payout" amount is received. The Base Payout is: (a) (b) After the Base Payout has been achieved, the participation in subsequent distribution will reduce to 20% of the Flat Payout Units held and 6% of the IRR Payout Units held. At that time, the unit holders also have the right to redeem (the "Put Right") the units for either (i) Class B non-voting units of Origination (which are exchangeable on a one-for-one basis for SVS shares of the Company), or (ii) cash, subject to certain restrictions, and with the number of shares or cash to be distributed to be calculated based on future net present values of the oil and gas reserves of the related development partnership. Development Partnership 1 ("DP1") During the first quarter of 2021, the Company formed DP1 with 13 external limited partners and Origination as a limited partner and the general partner. The intention of the DP1 was to partially finance the drilling and completion of five wells, with the external partners funding approximately 60% and the Company funding 40%. The Company raised $13,140,240 from external limited partners of which $1,366,709 was raised from officers and directors of the Company at that time. Investors participated $3,252,132 in Flat Payout Units and $9,888,108 in IRR Payout Units. During the year ended December 31, 2022, the Company distributed $nil to external partners (2021 - $1,853,127). On October 7, 2021, on completion of the DP1 program, the Company liquidated DP1 and redeemed the associated redeemable non-controlling interests with a redemption value of $15,288,594. As part of this redemption, DP1 units with a redemption value of $1,192,893 were exchanged for 339,372 Class B non-voting units of Origination via the Put Right. As at December 31, 2022 both the redemption value and carrying value of the Redeemable NCI in DP1 was $nil (December 31, 2021 - $15,288,594). Development Partnership 2 ("DP2") During the third quarter of 2021, the Company formed DP2 with 25 external limited partners and Origination as a limited partner and the general partner. The intention of the DP2 was to partially finance the drilling and completion of five wells, with the external partners funding approximately 60% and the Company funding 40%. The Company raised $20,815,329 from external limited partners of which $1,724,967 was raised from officers and directors of the Company at that time. Investors participated $7,390,362 in Flat Payout Units and $13,424,967 in IRR Payout Units. During the year ended December 31, 2021, the Company distributed $4,535,743 to external partners. In January 2022, on completion of the DP2 program, the Company liquidated DP2 and redeemed the associated redeemable non-controlling interests with a redemption value of $23,511,818. As part of this redemption, DP2 units with a redemption value of (a) $3,159,695 were exchanged for 826,063 Class B non-voting units of Origination via the Put Right, and (b) $84,300 retained the ongoing rights of working interest in the DP2 wells and as a result, the fair value of the units was settled with a disposition from PP&E, reflecting the disposition of the associated working interest. As at December 31, 2022 both the redemption value and carrying value of the Redeemable NCI in DP2 was $nil (December 31, 2021 - redemption value of $23,511,818 and carrying value of $25,370,013, respectively). Development Partnership 3 ("DP3") During the fourth quarter of 2021, the Company formed DP3 with 23 external limited partners and Origination as a limited partner and the general partner. The intention of the DP3 was to partially finance the drilling and completion of five wells, with the external partners funding approximately 60% and the Company funding 40%. The Company raised $21,182,826 from external limited partners of which $4,032,672 was raised from officers and directors of the Company. Investors participated $10,413,322 in Flat Payout Units and $10,769,504 in IRR Payout Units. During the year ended December 31, 2022, the Company distributed $nil to external partners (2021 - $nil). In April 2022, on completion of the DP3 program, the Company liquidated DP3 and redeemed the associated redeemable non-controlling interests with a redemption value of $30,171,337. As part of this redemption, DP3 units with a redemption value of $5,102,229 were exchanged for 894,929 Class B non-voting units of Origination via the Put Right. As at December 31, 2022 both the redemption value and carrying value of the Redeemable NCI in DP3 was $nil (December 31, 2021 - $21,182,826). Development Partnership 4 ("DP4") During the first quarter of 2022, the Company formed DP4 with 29 external limited partners and Origination as a limited partner and the general partner. The intention of DP4 was to partially finance the drilling and completion of five wells, with the external partners funding approximately 60% and the Company funding 40%. The Company has raised $25,225,079 from external limited partners of which $1,484,256 was raised from officers and directors of the Company. Investors participated $11,638,948 in Flat Payout Units and $13,586,130 in IRR Payout Units. During the year ended December 31, 2022, the Company distributed $2,747,270 to external partners. In July 2022, on completion of the DP4 program, the Company liquidated DP4 and redeemed the associated redeemable non-controlling interests with a redemption value of $31,734,290. As part of this redemption, DP4 units with a redemption value of (a) $4,135,797 were exchanged for 706,975 Class B non-voting units of Origination via the Put Right, and (b) $291,599 retained the ongoing rights of working interest in the DP4 wells and as a result, the fair value of the units was settled with a disposition from PP&E, reflecting the disposition of the associated working interest. As at December 31, 2022 both the redemption value and carrying value of the Redeemable NCI in DP4 was $nil (December 31, 2021 - $nil). Development Partnership Red Dawn 1 ("Red Dawn 1") During the first quarter of 2022, the Company formed Red Dawn 1 with 37 external limited partners and Origination as a limited partner and the general partner. The intention of Red Dawn 1 is to partially finance the drilling and completion of five wells, with the external partners funding approximately 60% and the Company funding 40%. The Company has raised $30,269,097 from external limited partners of which $773,836 was raised from officers and directors of the Company. Investors participated $16,692,200 in Flat Payout Units and $13,576,895 in IRR Payout Units. During the year ended December 31, 2022, the Company distributed $nil to external partners. In November 2022, on completion of the Red Dawn 1 program, the Company liquidated Red Dawn 1 and redeemed the associated redeemable non-controlling interests with a redemption value of $38,464,144. As part of this redemption, Red Dawn 1 units with a redemption value of (a) $3,184,247 were exchanged for 617,103 Class B non-voting units of Origination via the Put Right, and (b) $166,684 retained the ongoing rights of working interest in the Red Dawn 1 wells and as a result, the fair value of the units was settled with a disposition from PP&E, reflecting the disposition of the associated working interest. As at December 31, 2022 both the redemption value and carrying value of the Redeemable NCI in Red Dawn 1 was $nil (December 31, 2021 - $nil). Development Partnership 5 ("DP5") During the second quarter of 2022, the Company formed DP5 with 25 external limited partners and Origination as a limited partner and the general partner. The intention of DP5 is to partially finance the drilling and completion of six wells, with the external partners funding approximately 60% and the Company funding 40%. The Company has raised $30,171,345 from external limited partners of which $4,308,462 was raised from officers and directors of the Company. Investors participated $19,657,921 in Flat Payout Units and $10,513,413 in IRR Payout Units. During the year ended December 31, 2022, the Company distributed $450,668 to external partners. As at December 31, 2022 both the redemption value and carrying value of the Redeemable NCI in DP5 was $36,354,869 (December 31, 2021 - $nil). Development Partnership 6 ("DP6") During the third quarter of 2022, the Company formed DP6 with 38 external limited partners and Origination as a limited partner and the general partner. The intention of DP6 is to partially finance the drilling and completion of ten wells, with the external partners funding approximately 60% and the Company funding 40%. The Company has raised $34,157,892 from external limited partners of which $2,215,096 was raised from officers and directors of the Company. Investors participated $21,176,246 in Flat Payout Units and $12,981,645 in IRR Payout Units. During the year ended December 31, 2022, the Company distributed $142,316 to external partners. As at December 31, 2022 both the redemption value and carrying value of the Redeemable NCI in DP6 was $36,595,572 (December 31, 2021 - $nil). Development Partnership Red Dawn II ("Red Dawn 2") During the fourth quarter of 2022, the Company formed Red Dawn 2 with 36 external limited partners and Origination as a limited partner and the general partner. The intention of Red Dawn 2 is to partially finance the drilling and completion of five wells, with the external partners funding approximately 60% and the Company funding 40%. The Company has raised $34,633,295 from external limited partners of which $872,944 was raised from officers and directors of the Company. Investors participated $20,645,955 in Flat Payout Units and $13,987,340 in IRR Payout Units. During the year ended December 31, 2022, the Company distributed $nil to external partners. The Red Dawn 2 program has not been completed as at December 31, 2022. As at December 31, 2022 both the redemption value and carrying value of the Redeemable NCI in Red Dawn 2 was $34,633,295 (December 31, 2021 - $nil). |
NON-CONTROLLING INTERESTS
NON-CONTROLLING INTERESTS | 12 Months Ended |
Dec. 31, 2022 | |
Noncontrolling Interest [Abstract] | |
NON-CONTROLLING INTERESTS [Text Block] | 10. NON-CONTROLLING INTERESTS The NCI reflects the Class B non-voting units of Origination that are not held by the Company either directly or indirectly. There are 19,552,864 outstanding Class B non-voting units of Origination held by external holders, reflecting a 35.967% economic interest in Origination as of December 31, 2022 (December 31, 2021 - 32.954%). 2022 Activities In 2022, the following development partnership units were exchanged for Class B non-voting units of Origination (Note 9), as follows: a. DP2: 826,063 Class B non-voting units of Origination were issued, with a value of $3,159,695. b. DP3: 894,929 Class B non-voting units of Origination were issued, with a value of $5,102,229. c. DP4: 706,975 Class B non-voting units of Origination were issued, with a value of $4,135,797. d. Red Dawn 1: 617,103 Class B non-voting units of Origination were issued, with a value of $3,184,247. The issuance of these Class B units is reflected as a reduction to Redeemable NCI for the value at which these units were issued, an increase to NCI for the change in the Company's share in Origination's net assets, and an increase to additional paid-in capital for the difference. During the year ended December 31, 2022, Origination: a. b. The change in these Class A units resulted in a change to the NCI ownership, triggering an adjustment to the carrying value of NCI, with a corresponding offset to additional paid-in capital. Origination declared and paid dividends to its Class B non-voting units of Origination totaling $6,552,683, for the year ended December 31, 2022, resulting in a decrease of non-controlling interest. 2021 Activities On closing the BCA, Origination's consolidated book value of net liabilities was $35,344,612, which results in an opening NCI balance of $11,486,999. This NCI balance along with the weighted average stated capital of the equity interests surrendered by the NCI holder of $18,721,276, for a total of $30,208,275, has been credited to additional paid in-capital. In October 2021, development partnership units of DP1 were exchanged for 339,372 Class B non-voting units of Origination at a value of $1,192,893 (Note 9), reflecting a reduction to Redeemable NCI for the value at which these units were issued, an increase to NCI for the change in the Company's share in Origination's net assets, and an increase to additional paid-in capital for the difference |
EQUITY
EQUITY | 12 Months Ended |
Dec. 31, 2022 | |
Equity [Abstract] | |
EQUITY [Text Block] | 11. EQUITY Authorized Share capital The Company is authorized to issue an unlimited number of SVS, MVS, and PVS, with no par value. Subject to certain restrictions set out in the Company's articles, each SVS is entitled to one vote per share, each MVS is convertible, at the option of the holder, into 100 SVS and entitles the holder to 100 votes per share and each PVS is convertible into one SVS and entitles the holder to 1,000 votes per share. Each PVS will automatically convert to one SVS upon the holder's equity interest in Origination reducing to less than 75% of the interest held on the date of the closing of the BCA. The following table summarizes the movements in the Company's common shares: Origination Member Units SVS Shares MVS Shares PVS Shares Total Share Capital Shares Amount Shares Amount Shares Amount Shares Amount Balance as at January 1, 2021 17,083,501 $ 37,097,376 - $ - - $ - - $ - $ 37,097,376 Issuance of member units for cash 819,215 8,044,700 - - - - - - 8,044,700 Issuance of member units exchanged for notes 353,870 3,475,000 - - - - - - 3,475,000 Issuance of member units for oil and gas properties 356,415 3,499,995 - - - - - - 3,499,995 Issuance of member units to contractors 923,954 9,073,228 - - - - - - 9,073,228 Redemption of member units (3,992,629 ) (8,680,786 ) - - - - - - (8,680,786 ) Issuance of member units exchanged for notes 234,216 2,300,000 - - - - - - 2,300,000 Origination Member Units split 1:3 31,557,084 - - - - - - - - Allocation of opening non-controlling interest (16,168,422 ) (18,721,276 ) - - - - - - (18,721,276 ) Exchange of units for SVS and MVS (31,167,204 ) (36,088,237 ) 1,427,421 1,652,798 297,398 34,435,439 - - - Shares issued for cash, net of share issuance costs of $247,218 - - 161,976 476,978 17,057 5,022,854 - - 5,499,832 PVS issued for cash - - - - - - 15,947 128,213 128,213 Shares issued on reverse recapitalization - - 534,384 1,697,865 - - - - 1,697,865 Conversion of MVS to SVS - - 30,411,950 38,161,379 (304,120 ) (38,161,379 ) - - - Balance as at December 31, 2021 - $ - 32,535,731 $ 41,989,020 10,335 $ 1,296,914 15,947 $ 128,213 $ 43,414,147 Exchange of units for SVS and MVS - - 195,541 245,368 (1,955 ) (245,368 ) - - - Settlement of RSUs - - 2,024,401 9,685,555 - - - - 9,685,555 Repurchase of SVS for cancellation - - (799,600 ) (4,324,915 ) - - - - (4,324,915 ) Balance as at December 31, 2022 - $ - 33,956,073 $ 47,595,028 8,380 $ 1,051,546 15,947 $ 128,213 $ 48,774,787 2022 Activity On June 10, 2022, the TSX Venture Exchange ("TSXV") approved the Company's normal course issuer bid ("NCIB"). Under the NCIB, the Company may purchase, for cancellation, up to 1,648,783 SVS of the Company (representing approximately 5% of its issued and outstanding SVS as of June 6, 2022) over a 12-month period commencing on June 10, 2022. The NCIB will expire no later than June 9, 2023. On September 27, 2022, the TSXV approved an amendment to the Company's NCIB, which permits the Company to enter into an automatic share purchase plan ("ASPP") to facilitate the purchase of SVS under the NCIB during times when the Company would not ordinarily be permitted to purchase such shares due to regulatory restrictions of self-imposed black-out periods. In connection with the NCIB, during 2022 the Company purchased and cancelled 799,600 SVS at an average price of $5.41/share for an aggregate value of $4,324,915, and as at December 31, 2022, recorded a liability of $4,670,507, representing the contractual maximum share purchases remaining under the ASPP at an amended maximum purchase price of $5.50 per share. During 2022, 1,955 MVS were converted into 195,541 SVS on a 100 to 1 basis, and 2,024,401 SVS were issued as a result of settling certain RSUs (Note 12). Previously recorded stock-based compensation of $9,685,555 has been removed from additional paid-in capital and has been reclassified to share capital to reflect the impact of settlement (Note 12). 2021 Activity During the year ended December 31, 2021, the Company issued 819,215 Origination Member Units for aggregate cash of $8,044,700 ($9.82/unit) and issued 353,870 Origination Member Units in exchange for the retirement of $3,475,000 in promissory notes ($9.82/unit). The Company entered into an agreement, with a third party, to acquire 16,201 net acres in the Eagle Ford formation, located in the Austin, Fayette, Lee and Washington counties of Texas. In exchange for the acreage, the Company issued 203,666 Origination Member Units valued at $2,000,000 ($9.82/unit). In addition, the Company issued 152,749 Origination Member Units, valued at $1,499,995 ($9.82/unit) in exchange for an approximately 630 net mineral acreage in Washington County, Texas. In May of 2021, the Company issued 923,954 Origination Member Units to officers and consultants of the Company for services at an estimated value of $9.82 per Origination Member Unit for total consideration of $9,073,228 in connection with the listing application. On July 2, 2021, the Company exercised its option to convert all the existing convertible promissory notes with a principal of $2,300,000 into 234,216 Origination Member Units ($9.82/unit) effective as of July 7, 2021. During the year ended December 31, 2021, 304,120 MVS shares were converted into 30,411,950 SVS. Dividends The Company implemented a dividend distribution policy, starting January 2022, where monthly dividends of $0.03 per SVS and PVS and $3.00 per MVS were declared each month, with aggregate dividends declared and paid in 2022 of $12,416,759 (2021 - $nil). There are no restrictions that limit the payment of dividends by the Company. The total dividends declared and paid during the year ended December 31, 2022 by class of shares was $12,092,734, $318,284, and $5,741 for shares of SVS, MVS, and PVS, respectively (2021 - $nil). |
SHARE BASED COMPENSATION
SHARE BASED COMPENSATION | 12 Months Ended |
Dec. 31, 2022 | |
Share-Based Payment Arrangement, Noncash Expense [Abstract] | |
SHARE-BASED COMPENSATION [Text Block] | 12. SHARE BASED COMPENSATION The Company has granted share-based compensation consisting of share purchase options and restricted share units ("RSUs") under the terms of the 2021 Stock and Incentive Plan, which was approved by shareholders in May 2021 and adopted by the Board in September 2021. The options and RSUs have been granted with time-based vesting provisions over a period of 0 to 3 years. Vested RSUs will settle in Subordinate Voting Shares on a one-to-one basis as soon as practicable following the vesting date, and vested options will settle in Subordinate Voting Shares on a one-to-one basis as soon as practicable following the exercise date. Additionally, the Company awarded deferred share units ("DSUs") to directors as compensation for service under the terms of the Deferred Share Unit Plan, which was approved by shareholders in May 2021 and adopted by the Board in September 2021. The initial tranche of DSUs vested on June 1, 2022, and subsequent awards vest twelve months following the date of grant. Vested DSUs will settle in Subordinate Voting Shares on a one-to-one basis as soon as practicable following the termination of service of an eligible director. Compensation expense for share-based awards was $10,197,720 during year ended December 31, 2022 (December 31, 2021 - $5,405,548). These amounts are included in general and administrative expense in the consolidated statements of operations and comprehensive income (loss). The activity and assumptions for the share-based compensation plans are included below. Share Purchase Options The options outstanding under this plan are as follows: Stock options Weighted- Weighted Aggregate Outstanding, January 1, 2022 2,834,288 $ 3.56 Granted - - Forfeited - - Expired - - Exercised 1 - - Outstanding, December 31, 2022 2,834,288 $ 3.56 8.95 $ 4,166,403 Exercisable, December 31, 2022 1,803,985 $ 3.56 8.95 $ 2,651,858 1 No options were exercised during the years ended December 31, 2022 or 2021 The weighted average assumptions used to determine the fair value of the options granted, using the Black-Scholes options pricing model are as follows: For the year ended, December 31, 2022 2021 Fair value of options granted N/A 2.21 Valuation assumptions: Expected life (years) 5.55 5.72 Risk-free interest rate 1.27% 1.27% Average forfeiture rate 0.00% 0.00% Expected dividend yield 0.00% 0.00% Expected volatility 71.62% 71.62% The Company incurred share-based compensation expense related to the stock options of $2,046,166 during the year ended December 31, 2022 (December 31, 2021 - $2,858,702). As of December 31, 2022, the Company had $1,293,484 of unrecognized compensation expense related to non-vested stock options. The remaining expense is expected to be recognized over a weighted average period of approximately 1.4 years. Restricted Share Units As of December 31, 2022, the Company's nonvested RSUs outstanding are as follows: Restricted Weighted- Weighted average Aggregate Nonvested, January 1, 2022 892,580 $ 3.56 Granted 1 1,214,321 5.75 Forfeited - - Vested and settled 2 (2,024,401 ) 4.78 Nonvested, December 31, 2022 82,500 $ 5.75 0.67 $ 414,975 1 The weighted-average grant-date fair value of the RSUs granted in 2021 was $3.56 per unit. 2 The settlement date fair value of the RSUs that vested and settled during the years ended December 31, 2022 and 2021 was $11,609,135 and $nil, respectively. The Company incurred share-based compensation expense related to the RSUs of $7,415,252 during the year ended December 31, 2022 (December 31, 2021 - $2,488,955). As of December 31, 2022, the Company had $252,724 of unrecognized compensation expense related to non-vested RSUs. The expense is expected to be recognized over a weighted average period of approximately 0.67 years. Deferred Share Units As of December 31, 2022, the Company's DSUs outstanding are as follows: Deferred Weighted- average grant Weighted average Aggregate Outstanding, January 1, 2022 137,641 $ 3.56 Granted 1 88,694 5.75 Forfeited - - Settled - - Outstanding, December 31, 2022 226,335 $ 4.42 0.42 $ 1,138,465 Vested 2 , December 31, 2022 137,641 $ 3.56 N/A $ 692,334 1 The weighted-average grant-date fair value of the DSUs granted in 2021 was $3.56 per unit. 2 The fair value of the DSUs that vested during the years ended December 31, 2022 and 2021 was $490,002 and $nil, respectively. The Company incurred share-based compensation expense related to the DSUs of $736,302 during the year ended December 31, 2022 (December 31, 2021 - $51,891). As of December 31, 2022, the Company had $211,800 of unrecognized compensation expense related to non-vested DSUs. The expense is expected to be recognized within one year of grant. |
EARNINGS PER SHARE
EARNINGS PER SHARE | 12 Months Ended |
Dec. 31, 2022 | |
Earnings Per Share [Abstract] | |
EARNINGS PER SHARE [Text Block] | 13. EARNINGS PER SHARE The Company's common shares consist of SVS, MVS, and PVS. Subject to certain restrictions set out in the Company's articles, the SVS, MVS, and PVS rank equally and are entitled to equal distributions, except for the MVS which receives 100 times the distribution entitlement. As all three classes of common shares were determined to individually have the same entitlement to income (loss) per share on a basic and diluted basis, the below summarizes the amounts on an as-converted basis. The as-converted basis assumes the conversion of the PVS on a 1:1 basis into SVS, and the MVS on a 1:100 basis into SVS. Basic EPS The basic net income (loss) per share attributable to common shareholders for SVS, MVS, and PVS is determined using the two-class method. The basic income (loss) per share on an as-converted basis to SVS is as follows: For the year ended, December 31, 2022 2021 Net income (loss) attributable to common shareholders $ 7,428,135 $ ( 32,344,428 ) Weighted average number of common shares outstanding (as-converted) 34,453,696 42,596,264 Income (loss) per share - basic $ 0.22 $ (0.76 ) Diluted EPS Diluted net income (loss) per share attributable to SVS shareholders is computed using the more dilutive of the if-converted or treasury stock method, whereas diluted net income (loss) per share attributable to MVS and PVS shareholders is computed using the two-class method. The diluted income (loss) per share on an as-converted basis to SVS is as follows: For the year ended, December 31, 2022 2021 Net income (loss) attributable to common shareholders $ 7,428,135 $ (32,344,428 ) Plus: Effect of dilutive items 3,189,196 - $ 10,617,331 $ (32,344,424 ) Weighted average number of common shares outstanding (as-converted) 34,453,696 42,596,264 Plus: Effect for conversion of Origination Class B into SVS 18,203,421 - Plus: Effect for dilutive share-based compensation awards 929,210 - 53,586,327 42,596,264 Income (loss) per share - diluted $ 0.20 $ (0.76 ) As for the year ended December 31, 2021 the Company reported a net loss, the potentially dilutive securities are antidilutive and accordingly, basic net loss per share equals diluted net loss per share for the year ended December 31, 2021. |
REVENUE FROM CONTRACTS WITH CUS
REVENUE FROM CONTRACTS WITH CUSTOMERS | 12 Months Ended |
Dec. 31, 2022 | |
Revenue from Contract with Customer [Abstract] | |
REVENUE FROM CONTRACTS WITH CUSTOMERS [Text Block] | 14. REVENUE FROM CONTRACTS WITH CUSTOMERS The amount of each significant category of revenue is as follows: For the year ended, December 31, 2022 2021 Crude oil $ 97,438,790 $ 50,868,794 Natural gas 77,966,801 10,286,929 Natural gas liquids 20,243,366 9,641,067 Total operating revenues $ 195,648,957 $ 70,796,790 |
INCOME TAX
INCOME TAX | 12 Months Ended |
Dec. 31, 2022 | |
Income Tax Disclosure [Abstract] | |
INCOME TAX [Text Block] | 15. INCOME TAX Prior to the RTO, Origination was not subject to U.S. income taxes because, as a limited liability company classified as a partnership for U.S. federal income tax purposes, it was treated as a pass-through entity for income tax purposes. As such the members of Origination were subject to income tax with respect to each such member’s allocable share of Origination’s taxable income. Subsequent to the RTO, while Origination remains classified as a partnership for U.S. federal income tax purposes, the Company is taxed as a United States corporation and is subject to U.S. federal (and applicable state) income tax on its allocable share of pass-through taxable income from Origination. Thus, any tax effects related to the Company, together with its share of Origination’s activity, are included in these consolidated financial statements. Any taxable income or loss of Origination that is attributed to its other members is not taxable by the Company. The Company is also taxed as a Canadian corporation and is subject to Canada federal and provincial income tax for its share of Origination’s taxable income combined with its own activity. The Company's effective income tax rates (benefits) were (4.5%) and 5.9% for the years ended December 31, 2022, and 2021, respectively. The overall change in the Company's effective tax rate for the year ended December 31, 2022, from the previous year is primarily due to: (i) changes in amounts of income (loss) not subject to corporate tax and, (ii) current year activity causing the reversal of a previously recorded deferred tax expense resulting from temporary differences in items related to cost recovery of oil and natural gas properties. For the years ended December 31, 2022, and 2021, the Company recorded income tax expense (benefit) of ($1,928,319) and $1,928,319, respectively. The Company’s provision for income taxes is comprised of the following items for the period indicated. Year ended December 31, 2022 2021 Current income tax expense: United States federal $ - $ - State - - Total current income tax expense - - Deferred income tax expense (benefit): United States federal $ (1,928,319 ) $ 1,928,319 State - - Total deferred income tax expense (benefit) $ (1,928,319 ) $ 1,928,319 Total income tax expense (benefit) $ (1,928,319 ) $ 1,928,319 The difference in the Company's income tax provision calculated using its effective tax rates (benefits) of (4.5%) and 5.9% for the years ended December 31, 2022, and 2021, respectively, from the amounts calculated by applying the U.S. federal income tax rate of 21% to its pretax income (loss) from continuing operations were due to the following items for the periods indicated: Year ended December 31, 2022 2021 Net income (loss) before taxes $ 42,485,033 $ (30,654,438 ) U. S. federal statutory income tax rate 21% 21% Expected federal taxes at statutory rate 8,921,857 (6,437,432 ) Increase (decrease) resulting from: Canadian income tax - - Non-controlling interests (7,766,896 ) 54,250 Income (loss) not subject to corporate income taxes (1,154,961 ) 6,383,182 Change in tax status - 1,928,319 Change in valuation allowance - federal (1,928,319 ) - Income tax expense (recovery) $ (1,928,319 ) $ 1,928,319 Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The components of the Company's net deferred tax asset and liability were as follows for the periods indicated: Year ended December 31, 2022 2021 Deferred tax liabilities Investment in Origination $ - $ (3,437,344 ) Total deferred tax liabilities - (3,437,344 ) Deferred tax assets Investment in Origination $ 10,518,502 $ 1,509,025 Canadian federal tax loss carryforwards 339,501 334,198 US federal tax loss carryforwards 9,361,332 - Total deferred tax assets, gross 20,219,335 1,843,223 Less: Valuation allowance (20,219,335 ) (334,198 ) Total deferred tax assets, net - 1,509,025 Net deferred tax assets (liabilities) - (1,928,319 ) Presented as follows: Total deferred tax assets - - Total deferred tax liabilities - (1,928,319 ) Net deferred tax assets (liabilities) $ - $ (1,928,319 ) The tax years ended December 31, 2019, through December 31, 2022, remain open to examination under the applicable statute of limitations in the United States and other jurisdictions in which the Company and its subsidiaries file income tax returns. In some instances, state statutes of limitations are longer than those under United States federal tax law. The Company believes that it is more likely than not that the benefit from the investment in Origination and its federal loss carryforward will not be realized. In recognitions of this risk, the Company has provided a valuation allowance as of December 31, 2022 and 2021 of $20,219,335 and $334,198, respectively. The Canadian federal tax losses will expire after 20 years from the date incurred. The US federal tax loss carryforwards do not expire. |
RELATED PARTY TRANSACTIONS
RELATED PARTY TRANSACTIONS | 12 Months Ended |
Dec. 31, 2022 | |
Related Party Transactions [Abstract] | |
RELATED PARTY TRANSACTIONS [Text Block] | 16. RELATED PARTY TRANSACTIONS The Company's related parties consist of directors and officers of the Company, their immediate families, and companies that are controlled or significantly influenced by directors and officers of the Company. Management Services Agreements & Other Related Party Balances On December 22, 2020, the Company entered into a Management Services Agreement (the "MSA") with an entity related by virtue of common equity holders, directors and officers. Under this MSA, the related entity provided management, finance, operations and administrative services. The MSA had an initial period of 11 years with a 90 day cancellation notice. The Company was obligated to pay for these services on a quarterly basis amounting to the lesser of; i) $2.00 per produced barrel of oil equivalent (converting natural gas to BOE equivalent of 6:1), and ii) 0.375% of measured assets as defined in the credit agreement. During the year ended December 31, 2021, the Company incurred and paid fees of $287,126, recognized in in general and administrative expenses. In the second quarter of 2021, the MSA was effectively terminated, by assigning the MSA to one of the Company's subsidiaries. Therefore, no fees were incurred in connection with the MSA in the year ended December 31, 2022. As part of terminating the MSA, the Company entered into a new Letter Agreement (the "Letter") in the second quarter of 2021, with the same related entity by virtue of common equity holders, directors and officers. The Letter requires the Company to hire its own employees, obtain its own office lease and assume certain management obligations. In exchange, the Company is paid an annual fee of $1,000,000 on a quarterly basis. During the third quarter of 2022, the Letter was terminated by the Company. During the year ended December 31, 2022, the Company received $916,667 (December 31, 2021 - $416,666 in connection with the Letter, which is included in general and administrative expenses in the consolidated statements of operations and comprehensive income (loss). As at December 31, 2022, amounts receivable of $nil (December 31, 2021 - $120,501) were included in accounts receivable, net on the consolidated balance sheets. Other Related Party Balances As at December 31, 2022, accounts payable and accrued liabilities included $143,572 (December 31, 2021 -$120,501) due from a company related by virtue of common equity holders, officers and directors under normal credit terms. |
FAIR VALUE MEASUREMENTS
FAIR VALUE MEASUREMENTS | 12 Months Ended |
Dec. 31, 2022 | |
Fair Value Disclosures [Abstract] | |
FAIR VALUE MEASRUREMENTS [Text Block] | 17. FAIR VALUE MEASUREMENTS Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy levels 1, 2 and 3 are terms for the priority of inputs to valuation techniques used to measure fair value. The Company classifies fair values according to the following hierarchy based on the inputs used to value the instruments: Level 1: Reflects inputs that are based on unadjusted quoted prices in active markets for identical assets or liabilities that are accessible at the measurement date. Level 2: Reflects inputs, other than quoted prices included within Level 1, that are observable for the asset or liability, either directly or indirectly. Level 3: Reflects inputs that are both significant to the fair value measurement and less observable from objective sources. Financial Assets and Liabilities The Company's financial instruments are cash and cash equivalents, restricted cash, account receivable, net, derivative assets and liabilities, accounts payable and accrued liabilities, long term debt, corporate credit facility and the asset backed preferred instrument. As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The Company classifies its financial assets and liabilities as follows within the hierarchy: Derivatives: Derivatives are financial instruments measured at fair value on a recurring basis. Commodity derivatives The fair value of the commodity derivative instruments is determined using observable market data for similar instruments, which resulted in the Company reporting its commodity derivatives as Level 2 on the fair value hierarchy. This observable data includes the forward curves for commodity prices based on quoted market prices and implied volatility factors related to changes in the forward curves. Counterparty statements are utilized to determine the value of the commodity derivative instruments and are reviewed and corroborated using various methodologies and significant observable inputs. Interest rate derivatives The fair value of the interest rate derivative instruments is determined using observable market data for forward curves for the benchmark interest rates, as well as time to maturity, contractual notional amounts, amongst other factors. The Company reports its interest rate derivatives as Level 2 on the fair value hierarchy. Counterparty statements are utilized to determine the value of the interest rate derivative instruments and are reviewed and corroborated using various methodologies and significant observable inputs. Cash, cash equivalents and restricted cash: Accounts receivable, net, and accounts payable and accrued liabilities: Long term debt: Corporate Credit Facility: There were no transfers between levels of the fair value measurement hierarchy during the year. The following tables set forth by level within the fair value hierarchy the Company’s financial instruments, which were accounted for at fair value on a recurring basis as of December 31, 2022 and 2021: Fair Value Measurements as at December 31, 2022 using Level 1 Level 2 Level 3 Assets (liabilities): Commodity derivatives - $ 3,077,079 - Interest rate derivatives - - - Total - $ 3,077,079 - Fair Value Measurements as at December 31, 2021 using Level 1 Level 2 Level 3 Assets (liabilities): Commodity derivatives - $ (20,424,601 ) - Interest rate derivatives - 43,421 - Total - $ (20,381,180 ) - Non-Financial Assets and Liabilities Certain non-financial assets and liabilities are subject to fair value measurements. In those cases, the fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two as considered appropriate based on the circumstances. For the impairment assessment of evaluated oil and gas properties, the ceiling test requires an estimate of the fair value of the unevaluated and unproved properties that are included in costs being amortized (Note 2). The fair value may be estimated using comparable market data, forecasted cashflows, or a combination of both as considered appropriate based on the circumstances. Given the significance of the unobservable nature of a number of the inputs, these are considered Level 3 on the fair value hierarchy. Fair values are also estimated in connection with the initial measurement of ARO. Given the significance of the unobservable nature of a number of the inputs, this measurement is considered Level 3 on the fair value hierarchy (Note 2). While the Company believes the methods used to estimate fair value are consistent with those used by other market participants, the use of other methods or assumptions could result in a different estimate of fair value. |
RISK MANAGEMENT AND FINANCIAL I
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS | 12 Months Ended |
Dec. 31, 2022 | |
General Discussion of Derivative Instruments and Hedging Activities [Abstract] | |
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS [Text Block] | 18. RISK MANAGEMENT AND FINANCIAL INSTRUMENTS The future results of the Company's crude oil and natural gas operations will be affected by market prices of crude oil and natural gas which is affected by numerous factors beyond the control of the Company, including weather, imports, marketing of competitive fuels, proximity and capacity of crude oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of crude oil, natural gas and natural gas liquid products, economic disruptions, the regulatory environment, the economic environment, and other regional and political events, none of which can be predicted with certainty. The Company's operations are also subject to concentration risk due to the fact that all of its oil and natural gas revenue is sourced from its operations in the United States. Further, three of the Company’s customers reflect 91.25% of its oil and gas revenues, with each of these customers representing 49.8%, 31.4%, and 10.0% of the revenues, which represents further concentration risk in specific customers. Credit Risks Financial instruments which potentially subject the Company to credit risk consist principally of cash balances, accounts receivable, and derivatives. The Company maintains cash balances at financial institutions, which may at times exceed the federally insured limits. The Company has not experienced any significant losses from such investments, and the Company believes the credit quality of the financial institutions to be high. The Company's accounts receivables are subject to normal industry credit risk. The accounts receivables are mainly due from participants in the oil and gas industry, who may be affected by periodic downturns in the economy, in general, or in their specific segment of the crude oil or natural gas industry. The Company believes that its level of credit-related losses due to such economic fluctuations have been immaterial. The Company's derivative contracts are with established financial institutions with investment grade credit ratings which are believed to have minimal credit risk. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts; however, the Company does not anticipate such nonperformance. Commodity Price Risk and Interest Rate Risk The Company utilizes various commodity price derivative instruments to reduce commodity price risk being the risk that future cash flows will fluctuate as a result of changes in commodity prices. In addition, from time to time the Company utilizes interest rate swaps to mitigate exposure to changes in interest rates on the Company's variable rate indebtedness. All derivative instruments are recorded in the Company's consolidated balance sheet as either assets or liabilities measured at their fair value (Note 2). The Company has not designated any derivative instruments as hedges for accounting purposes and does not enter into such instruments for speculative trading purposes. The changes in the fair value are recognized in the Company's consolidated statements of operations and comprehensive income (loss). The location and amounts of the Company's realized and unrealized gains and losses on derivative contracts in the Company's consolidated statements of operations and comprehensive income (loss) are as follows: Year ended December 31, Statements of Operations Location 2022 2021 Commodity derivative contracts Unrealized gain (loss) Gain / (loss) on derivative instruments $ 26,246,351 $ (15,903,217 ) Realized gain (loss) Gain / (loss) on derivative instruments (36,269,846 ) (17,622,236 ) Total gain (loss), net $ (10,023,495 ) $ (33,525,453 ) Interest rate derivative contracts Unrealized gain Finance and interest expense $ - $ 43,421 Realized gain Finance and interest expense 623,579 - Total gain (loss), net $ 623,579 $ 43,421 Gains and losses on derivative instruments are included in the operating section of the consolidated statements of cash flows. The open commodity derivative positions as at December 31, 2022, are as follows, for the settlement periods presented: 2023 2024 2025 Total Volumes Crude Oil: WTI NYMEX - Swaps: Volumes (Bbl) 542,548 286,150 129,642 958,340 Weighted Average Price ($/Bbl) $ 69.79 $ 65.97 $ 58.98 Natural Gas and Natural Gas Liquids: Natural Gas NYMEX - Swaps: Volumes (MMBtu) 5,306,902 2,606,643 1,331,415 9,244,960 Weighted Average Price ($/MMBtu) $ 5.43 $ 5.43 $ 5.33 Natural Gas NYMEX vs. Houston Ship Channel - Basis Swaps: Volumes (MMBtu) 465,214 325,088 177,009 967,311 Weighted Average Price ($/MMBtu) $ (0.07 ) $ (0.07 ) $ (0.07 ) Mont Belvieu Natural Gas - Swaps: Volumes (Gal) 1,560,711 857,027 326,472 2,744,210 Weighted Average Price ($/Gal) $ 1.30 $ 1.57 $ 1.65 Mont Belvieu Ethane - Swaps: Volumes (Gal) 5,818,913 3,195,317 1,217,209 10,231,439 Weighted Average Price ($/Gal) $ 0.30 $ 0.34 $ 0.36 Mont Belvieu Propane - Swaps: Volumes (Gal) 3,466,691 1,903,650 725,170 6,095,511 Weighted Average Price ($/Gal) $ 0.80 $ 0.92 $ 0.95 Mont Belvieu Isobutane - Swaps: Volumes 673,486 369,828 140,880 1,184,194 Weighted Average Price ($/Gal) $ 0.89 $ 1.06 $ 1.10 Mont Belvieu N. Butane - Swaps Volumes 1,426,461 783,308 298,388 2,508,157 Weighted Average Price ($/Gal) $ 0.87 $ 1.04 $ 1.08 The Company uses interest rate swaps to effectively convert a portion of its variable rate indebtedness to fixed rate indebtedness. As of December 31, 2022, the Company had interest rate swaps with a total notional amount of $nil (December 31, 2021 - $25,237,409). The asset and liability fair values of the Company's derivative assets (liabilities), presented on the consolidated balance sheets is as follows: As at December 31, 2022 2021 Derivative Assets: Current assets $ 2,019,600 $ - Noncurrent assets 1,057,479 - Total Derivative Assets: $ 3,077,079 $ - Derivative Liabilities: Current liabilities $ - $ 6,479,508 Noncurrent liabilities - 13,901,672 Total Derivative Liabilities: $ - $ 20,381,180 Liquidity Risk Liquidity risk is the risk that the Company will encounter difficulty in meeting obligations associated with the financial liabilities as they become due. At December 31, 2022 the Company had negative working capital of $162,980,101. The Company expects to repay its financial liabilities in the normal course of operations and to fund future operational and capital requirements through operating cash flows and through issuance of debt and/or equity. The Company may need to conduct asset sales and/or issuances of debt and/or equity if liquidity risk increases in a given period. The Company believes it has sufficient funds to meet foreseeable obligations by actively monitoring its credit facilities through use of the loans, asset sales, and coordinating payment and revenue cycles. The Company is required to meet certain financial covenants under its debt facilities (Note 7). As at December 31, 2022, the Company was not in breach of financial covenants. |
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 12 Months Ended |
Dec. 31, 2022 | |
Commitments and Contingencies Disclosure [Abstract] | |
COMMITMENTS AND CONTINGENCIES [Text Block] | 19. COMMITMENTS AND CONTINGENCIES In the ordinary course of business, the Company may be involved in various legal proceedings and subject to claims that arise. Although the results of litigation and claims are inherently unpredictable and uncertain, we are not currently a party to any legal proceedings the outcome of which, if determined adversely to us, are believed to, either individually or taken together, have a material adverse effect on our business, financial condition or results of operations. The Company has certain commitments under leases as outlined in Note 5. The Company also entered into a transportation agreement in 2022 for the transport of natural gas on a take-or-pay basis for a minimum agreed on volume, reflecting fees of approximately $11,000 per day. |
FINANCE AND INTEREST EXPENSE
FINANCE AND INTEREST EXPENSE | 12 Months Ended |
Dec. 31, 2022 | |
Finance and Interest Expense [Abstract] | |
FINANCE EXPENSE [Text Block] | 20. FINANCE AND INTEREST EXPENSE The amount of each significant category of finance and interest expense recognized, are as follows: Year ended December 31, 2022 2021 Interest expense on long term debt $ 11,389,415 $ 3,612,929 Interest expense for Corporate Credit Facility 1,736,868 - Interest on asset back preferred 658,047 1,857,351 Interest on promissory notes - 300,685 Interest rate derivative loss (gain) (623,579 ) (43,421 ) Interest income (14,966 ) - Bank fees and other 282,548 - Total finance and interest expense $ 13,428,333 $ 5,727,544 |
GENERAL AND ADMINISTRATIVE EXPE
GENERAL AND ADMINISTRATIVE EXPENSE | 12 Months Ended |
Dec. 31, 2022 | |
General and Administrative Expense [Abstract] | |
GENERAL AND ADMINISTRATIVE EXPENSE [Text Block] | 21. GENERAL AND ADMINISTRATIVE EXPENSE The amount of each significant category of general and administrative expense recognized, are as follows: Year ended December 31, 2022 2021 Stock based compensation expense $ 10,197,720 $ 14,478,776 Employee salaries and benefits 10,193,583 6,483,720 Professional, legal, and advisory 4,672,072 3,629,525 Travel and accommodation 278,653 174,769 Software 462,754 344,577 Operating lease and variable lease costs 215,487 75,170 Office and administration 986,558 251,246 Recoveries (916,667 ) (416,666 ) Total general and administrative expense $ 26,090,160 $ 25,021,117 |
SUPPLEMENTAL CASH FLOW DISCLOSU
SUPPLEMENTAL CASH FLOW DISCLOSURES | 12 Months Ended |
Dec. 31, 2022 | |
Supplemental Cash Flow Information [Abstract] | |
SUPPLEMENTAL CASH FLOW DISCLOSURES [Text Block] | 22. SUPPLEMENTAL CASH FLOW DISCLOSURES Year ended December 31, 2022 2021 Supplementary cash flow information Cash paid for interest $ 7,903,446 $ 2,278,570 Cash paid for income taxes - - Non-Cash Investing Activities Property, plant and equipment non-cash accruals $ 43,487,444 $ 15,752,315 Capitalized asset retirement obligations 110,480 217,471 Acquisition of oil and natural gas properties via share issuance - 3,499,995 $ 43,597,924 $ 19,469,781 Non-Cash Financing Activities Redemption of Redeemable NCI via issuance of Redeemable NCI $ 100,727,774 $ 14,095,702 Redemption of Redeemable NCI via issuance of Origination Member Units 15,581,968 1,192,893 Redemption of Redeemable NCI via oil and gas property disposition 542,584 - Redemption of promissory notes vis equity issuance - 6,775,000 $ 116,852,326 $ 22,063,595 Changes in Operating Assets and Liabilities Accounts receivable, net $ (7,668,573 ) $ (12,675,672 ) Prepaid expenses (540,223 ) (510,063 ) Accounts payable and accrued liabilities 4,699,365 19,986,246 Asset backed preferred instrument accrued interest - 1,857,351 Asset retirement obligation settlements (127,862 ) - Operating lease asset (235,564 ) - Operating leases liability 103,302 9,542 $ ( 3,769,555 ) $ 8,667,404 |
SUBSEQUENT EVENTS
SUBSEQUENT EVENTS | 12 Months Ended |
Dec. 31, 2022 | |
Subsequent Events [Abstract] | |
SUBSEQUENT EVENTS [Text Block] | 23. SUBSEQUENT EVENTS Completion of DP5 and Creation of Development Partnership 7 ("DP7") On January 20, 2023, the Company redeemed redeemable non-controlling interests with a redemption value of $36,354,869. In connection with this redemption, DP5 units with a redemption value of $2,505,631 were exchanged for 499,794 Class B non-voting units of Origination. On January 20, 2023, the Company also formed DP7, with 24 external limited partners and Origination as a limited partner and the general partner. The intention of the DP7 is to finance the drilling and completion of five wells, with external partners funding approximately 60% and the Company funding 40%. The Company raised $34,262,236 from external limited partners of which $4,946,981 was raised from officers and directors of the Company. Investors participated $20,478,084 in Flat Payout Units and $13,784,152 in IRR Payout Units. Dividends: On January 3, 2023, the Company’s board of directors declared a dividend of $0.0315 per SVS and PVS, and $3.15 per MVS. Payable on January 31, 2023, to shareholders of record on the close of business on January 17, 2023. On February 1, 2023, the Company’s board of directors declared a dividend of $0.0315 per SVS and PVS, and $3.15 per MVS. Payable on February 28, 2023, to shareholders of record on the close of business on February 14, 2023. Corporate Credit Facility Covenant Waiver In March 2023, the Company received a waiver of all covenants on the Corporate Credit Facility until July 1, 2023, and received a waiver on certain covenants on the ABS Facility until July 1, 2023. The Company also received an extension on the initial maturity date of Tranche 1 under the ABS Facility until July 1, 2023. In the absence of a covenant waiver, a breach of the covenant would result in the Corporate Credit Facility and/or ABS Facility to be due on demand. |
SUPPLEMENTAL OIL AND GAS INFORM
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) | 12 Months Ended |
Dec. 31, 2022 | |
Extractive Industries [Abstract] | |
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) [Text Block] | SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) Results of Operations Oil and natural gas sales reflect the market prices of net production sold or transferred with appropriate adjustments for royalties, net profits interest, and other contractual provisions. Production expenses include lifting costs incurred to operate and maintain productive wells and related equipment including such costs as operating labor, repairs and maintenance, materials, supplies, and fuel consumed. Production taxes include production and severance taxes. Depletion of crude oil and natural gas properties relates to capitalized costs incurred in acquisition, exploration, and development activities. Results of operations do not include interest expense and general corporate amounts. The results of operations for the Company’s oil and natural gas production activities are provided in the Company’s related statements of operations and comprehensive income (loss). Costs Incurred and Capitalized Costs The costs incurred in oil, natural gas, and NGL acquisition, exploration and development activities are as follows: For the year ended December 31, 2022 2021 Unevaluated property acquisition $ 2,244,517 $ 6,200,745 Development 248,185,340 68,323,942 Exploration costs 5,179,046 1,406,101 Total $ 255,608,903 $ 75,930,788 Capitalized costs for unproved and unevaluated properties that are excluded from depletion is disclosed in Financial Statement Note 4 Oil and Natural Gas Properties, Net. Oil and Natural Gas Reserves Data Information with respect to the Company's oil and natural gas producing activities is presented in the following tables. Reserve quantities, as well as certain information regarding future production and discounted cash flows, were determined by W.D. Von Gonten Engineering LLC as of January 1, 2023, the Company's third-party independent reserve engineers, based on information provided by the Company. The following tables present the Company's estimates of its proved oil and natural gas reserves, net of royalties. The Company emphasizes that reserves are approximations and are expected to change as additional information becomes available. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Oils Natural Gas NGLs Total (Mbbl) (MMcf) (Mbbl) MBOE Total proved reserves at December 31, 2020 5,209 23,505 5,156 14,283 Revisions of previous estimates, and other (2,445 ) 5,415 (3,550 ) (5,093 ) Improved recovery 1,715 6,201 1,220 3,969 Production (743 ) (2,398 ) (358 ) (1,501 ) Total proved reserves at December 31, 2021 3,735 32,724 2,469 11,658 Revisions of previous estimates, and other (1,850 ) (27,505 ) (1,271 ) (7,705 ) Extensions, discoveries and other additions 2,281 93,381 1,930 19,775 Improved recovery 1,111 14,069 671 4,127 Production (1,030 ) (13,317 ) (588 ) (3,838 ) Total proved reserves at December 31, 2022 4,247 99,352 3,211 24,017 Proved Developed Reserves: December 31, 2020 2,275 6,672 1,692 5,079 December 31, 2021 2,137 7,468 1,041 4,423 December 31, 2022 3,973 70,480 2,962 18,682 Proved Undeveloped Reserves: December 31, 2020 2,934 16,833 3,464 9,204 December 31, 2021 1,598 25,256 1,428 7,235 December 31, 2022 274 28,872 249 5,335 Proved reserves are estimated quantities of crude oil and natural gas, which geological and engineering data indicate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are included for reserves for which there is a high degree of confidence in their recoverability and they are scheduled to be drilled within the next five years. Notable changes in proved reserves for the year ended December 31, 2022 included the following: Extensions and Discoveries: In 2022, total extensions and discoveries of 19.78 million BOE were primarily attributable to successful drilling in the Giddings Field, Austin Chalk and Hawkville Field, Austin Chalk, as well as the addition of proved locations. Included in these discoveries were 5.60 million BOE as a result of successful drilling in the Giddings Austin Chalk, the addition of 1.16 million BOE of additional proved locations and 7.25 million BOE attributable to the successful drilling in the Hawkville Austin Chalk and Eagle Ford and the addition of 5.70 million BOE as a result of additional proved locations. Improved Recoveries: In 2022, additions of proved reserves of 3.97 million BOE were primarily due to the managing of existing proved developed locations and an increase of projected recoverable volumes. Notable changes in proved reserves for the year ended December 31, 2021 included the following: Revisions to Previous Estimates - In 2021, revisions to previous estimates decreased proved reserves. These revisions were adjusted downward caused by the removal of undeveloped locations from the previous year's development schedule in the Giddings Austin Chalk area. Improved Recovery - In 2021, additions to proved reserves of 4.13 million BOE were primarily due to the optimization of existing proved developed locations, via additional improvement projects, and an increase of projected recoverable volumes. Standardized Measure of Discounted Future Cash Flows The following table presents a standardized measure of discounted future net cash flows relating to proved crude oil and natural gas reserves. The changes in the standardized measure of discounted future net cash flows relating to proved crude oil and natural gas were prepared in accordance with the provisions of ASC 932 Extractive Activities - Oil and Gas The standardized measure of discounted future net cash flows is computed by applying average prices for the last 12 months to estimated future production, year-end costs and legislated tax rates and a discount factor of 10 percent to net proved reserves. The Company believes the standardized measure does not provide a reliable estimate of the Company's expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. Actual future cash inflows may vary considerably. For the year ended December 31, 2022 2021 Future cash inflows $ 1,092,307,120 $ 247,313,824 Future production costs (136,423,094 ) (53,266,494 ) Future development and abandonment costs (75,501,920 ) (3,124,700 ) Future income tax expense (98,092,314 ) (24,496,630 ) Future net cash inflows $ 782,289,792 $ 166,426,000 10% annual discount for estimated timing of cash flows (303,833,120 ) (55,888,400 ) Standardized measure of discounted future net cash flows $ 478,456,672 $ 110,537,600 The twelve-month average prices were adjusted to reflect applicable transportation and quality differentials on a well-by-well basis to arrive at realized sales prices used to estimate the Company's reserves. The price of other liquids is included in natural gas. The prices for the Company's reserve estimates were as follows: Oil Natural Gas NGLs (Mbbl) (MMcf) (Mbbl) December 31, 2022 $ 94.49 $ 6.25 $ 32.62 December 31, 2021 $ 66.55 $ 3.64 $ 27.29 Changes in the standardized measure of discounted future net cash flows at 10% per annum are estimated as follows: For the year ended December 31, 2022 2021 Beginning of period $ 110,537,600 $ 82,028,564 Sales of oil and natural gas produced, net of production costs (81,065,058 ) (26,623,743 ) Extensions, discoveries and other additions 200,494,177 (12,803,556 ) Previously estimated development cost incurred during the period (3,124,700 ) 14,038,000 Net change of prices and production costs 139,967,308 114,050,543 Change in future development and abandonment costs (57,466,319 ) 48,932,984 Revisions of quantity and timing estimates 225,544,516 (120,961,889 ) Accretion of discount (760,264 ) 18,575,522 Change in income taxes (55,419,410 ) 8,768,285 Other (251,178 ) (15,467,110 ) End of period $ 478,456,672 $ 110,537,600 |
SUMMARY OF SIGNIFICANT ACCOUN_2
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies) | 12 Months Ended |
Dec. 31, 2022 | |
Accounting Policies [Abstract] | |
Basis of Measurement [Policy Text Block] | Basis of Measurement The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities in the financial statements. In determining these estimates, management makes subjective and complex judgments that may require assumptions about matters that are inherently uncertain. The estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimate is revised if the revision affects only that period, or in the period of the revision and future periods if the revision affects both current and future periods. Estimates and assumptions that, in the opinion of the Company’s management, are significant include the estimation of oil and natural gas reserves and depletion (Note 2 below), the redemption value of redeemable non-controlling interests (Note 2 below and Note 9), determination of whether long-lived assets are impaired (Note 2 below), valuation of asset retirement obligations (Note 2 below and Note 6), and deferred tax assets/liabilities (Note 2 below and Note 15). The Company bases its estimates and judgments on historical experience and on various other assumptions and information believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be predicted with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained, or if the Company’s operating environment changes. Actual results may differ from the estimates and assumptions used in the preparation of these financial statements. |
Going Concern [Policy Text Block] | Going Concern The financial statements have been prepared assuming that the Company will continue as a going concern, which contemplates continuity of operations, realization of assets, and liquidation of liabilities in the normal course of business. As at December 31, 2022 the Company had a working capital deficit of $162,980,101, reflecting a significant increase in outstanding accounts payable and accrued liabilities as well as borrowings, due to the Company’s increased capital expenditures on oil and natural gas properties. As a result, the Company does not currently have the cash resources to meet its current liabilities for the next twelve months. These factors raise substantial doubt about the Company’s ability to continue as a going concern. The Company’s ability to continue as a going concern is dependent on its ability to generate sufficient cash flows from operations, as well as its ability to obtain financing via an asset sale and/or the issuances of debt and/or equity in the short term. While the Company believes it has sufficient forecasted funds to meet foreseeable obligations, there can be no assurance that the Company will be successful in its efforts to raise additional funds in the short term and its ability to generate sufficient operating cash flows. Due to these factors, the Company may be unable to continue as a going concern. The financial statements do not include any adjustments related to the recoverability and classification of recorded asset amounts or the amounts and classification of liabilities that might be necessary should the Company be unable to continue as a going concern, and such adjustments could be material. |
Basis of Consolidation [Policy Text Block] | Basis of Consolidation Subsidiaries The financial statements include the accounts of the Company and its consolidated subsidiaries, after the elimination of intercompany transactions and balances. The Company consolidates all entities that it controls either through a majority voting interest or as the primary beneficiary of variable interest entities ("VIEs"). The Company evaluates (1) whether it holds a variable interest in an entity, (2) whether the entity is a VIE, and (3) whether the Company's involvement would make it the primary beneficiary. The assessment of whether the entity is a VIE is generally performed qualitatively, which requires judgment. These judgments include: (a) determining whether the equity investment at risk is sufficient to permit the entity to finance its activities without additional subordinated financial support, (b) evaluating whether the equity holders, as a group, have the characteristics of a controlling financial interest, (c) determining whether two or more parties' equity interests should be aggregated, (d) determining whether the equity investors have proportionate voting rights to their obligations to absorb losses or rights to receive returns from the entity, and (e) if disproportionate voting rights are identified, whether substantially all of the investee's activities are on behalf of an investor that has disproportionately few voting rights. Significant judgements involve the analysis of the risks and rewards that the VIE's operations generate and the nature of the Company's involvement with and interest in the VIE, including the form of the Company's ownership interest, representation in an entity's governance, and ability to participate in making decisions. For entities that are determined to be VIEs, the Company consolidates those entities where it has concluded it is the primary beneficiary. The primary beneficiary is defined as the variable interest holder with (a) the power to direct the activities of a VIE that most significantly impact the entity's economic performance and (b) the obligation to absorb losses or the right to receive benefits from the entity that could potentially be significant to the VIE. In evaluating whether the Company is the primary beneficiary, the Company evaluates its economic interests in the entity held either directly or indirectly by the Company, and its ability to control the VIEs through arrangements such as general partnership interests or contracts. The Company's consolidated VIEs consist of its controlled subsidiary, Origination, as its control over Origination is contractually provided and not granted via the equity interest. Origination, through its subsidiaries, holds the Company's main operations, including external financing. Some of Origination's drilling programs are structured through limited partnerships (the "Development Partnerships"), which are consolidated VIEs of Origination (see Note 9). Under the contractual agreements with the VIEs, the Company has the power to direct activities of the VIEs and can have assets transferred out of the VIEs under its control. Therefore, the Company considers that there is no asset in any of the VIEs that can be used only to settle obligations of the VIE, except for certain assets that are designated as collateral for long term debt (Note 7). If an entity is determined to not be a VIE, the voting interest entity model is applied, where an investor holding the majority voting rights consolidates the entity. Ownership interests in subsidiaries represented by other parties that do not control the entity are presented in the consolidated financial statements as activities and balances attributable to noncontrolling interests. Joint Arrangements A portion of the Company's oil and natural gas business activities involve jointly controlled assets and are conducted under joint operating agreements. These consolidated financial statements reflect only the Company's proportionate share of the joint operation's controlled assets and liabilities it has incurred, its share of any liabilities jointly incurred with other joint interest partners, income from the sale or use of its share of the joint operation's output, together with its share of expenses incurred by the joint operation and any expenses it incurs in relation to its interest and its share of production in such activities. |
Segment Reporting [Policy Text Block] | Segment Reporting The Company operates in a single operating and reportable segment. Operating segments are defined as components of a public entity for which separate financial information is regularly reviewed by the chief operating decision maker in deciding how to allocate resources and assess performance. The Company's chief operating decision maker allocates resources and assesses performance based upon financial information at the Company level. The Company's operations are primarily conducted in, and its assets are primarily located in, the United States of America. The Company's revenues are entirely generated in the United States of America. |
Functional and Presentation Currency [Policy Text Block] | Functional and Presentation Currency These financial statements are presented in US dollars. The functional currency of the Company and its individual subsidiaries is the US dollar, which represents the primary economic environment in which the entities operate. Foreign currency transactions are those transactions whose terms are denominated in a currency other than the functional currency. Transactions denominated in foreign currencies are translated to the functional currency using the exchange rate prevailing at the date of the transactions. Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency using the exchange rate in effect as at the balance sheet date. Exchange gains and losses resulting for the remeasurement of monetary assets and liabilities are included in general and administrative expenses in the consolidated statements of operations and comprehensive income (loss) in the period in which they arise. |
Cash and Cash Equivalents [Policy Text Block] | Cash and Cash Equivalents Cash and cash equivalents include short-term investments with a term to maturity of three months or less when purchased (Note 18). |
Restricted Cash [Policy Text Block] | Restricted Cash Cash and cash equivalents that are restricted as to the withdrawal or usage, in accordance with specific arrangements, are presented as restricted cash. The amount of restricted cash as of December 31, 2022 is $3,375,395 (December 31, 2021 - $nil), reflecting the interest reserve account maintained in connection with the asset backed securitization facility (Note 7). |
Accounts Receivable, Net [Policy Text Block] | Accounts Receivable, Net The accounts receivable are primarily receivables from crude oil, natural gas, and natural gas liquids customers and joint interest owners. Oil and natural gas sales are normally collected by the Company between 30 and 60 days from deliveries. Joint interest receivables are typically collected within 30 to 90 days of the joint interest bill being issued to the partner. Accounts receivable, net are recorded at amortized cost. Management evaluates all accounts periodically and an allowance is established based on the best facts available. Management considers historical collection data, accounts receivable aging trends, other operational trends and reasonable forecasts to estimate the collectability of receivables. The Company's accounts receivable are subject to normal industry credit risk (Note 18). |
Derivatives [Policy Text Block] | Derivatives The Company has entered into certain financial risk management contracts in order to manage the exposure to market risks from fluctuations in commodity prices and interest rates. The Company considers all risk management contracts to be economic hedges, but has not designated its financial risk management contracts as accounting hedges and, therefore, has not applied hedge accounting. As a result, all financial risk management contracts are measured at fair value with changes in fair value recognized in income (Note 17). Transaction costs are recognized in the consolidated statements of operations and comprehensive income (loss) as incurred. In the consolidated balance sheets, the fair values of the derivative instruments are presented as current and non-current assets or liabilities depending on the timing of settlements and the resulting cash flows associated with the instruments. Fair value amounts related to cash flows occurring beyond one year are classified as non-current (Note 18). |
Oil and Natural Gas Properties, Net [Policy Text Block] | Oil and Natural Gas Properties, Net Oil and Natural Gas Properties The Company uses the full-cost method of accounting for its oil and natural gas properties. Under this method, all costs associated with the acquisition, exploration and development of oil and natural gas properties and reserves, including unproved and unevaluated property costs, are capitalized as incurred and accumulated in a single cost center representing the Company's activities, which are undertaken exclusively in the United States. Such costs include lease acquisition costs, geological and geophysical expenditures, lease rentals on undeveloped properties, costs of drilling both productive and non-productive wells, and general and administrative expenses directly related to acquisition, exploration and development activities, but does not include any costs related to production, selling or general corporate administrative activities. Sales of oil and natural gas properties are accounted for as adjustments to net capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between net capitalized costs and proved reserves of oil and gas. All costs related to production activities and maintenance and repairs are expensed as incurred. Significant workovers that increase the properties' reserves are capitalized. In the years ended December 31, 2022 and 2021, there were no property sales that resulted in a significant alteration. Depletion Capitalized costs of oil and natural gas properties are amortized using the unit-of-production method. Under this method, depletion is calculated at the end of each period by multiplying total production for the period by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus estimates of future development costs by estimates of proved reserves quantities. Unproved and unevaluated property costs and related carrying costs are excluded from the depletion base until the properties associated with these costs are considered proved or impaired. The Company reviews its unproved and unevaluated properties at the end of each quarter to determine whether the costs incurred should be transferred to the full cost pool and thereby subject to amortization. Upon impairment, which includes leases that have expired or have been deemed uneconomic, the costs of the unproved properties are immediately included in the depletion base. The determination of depletion is significantly impacted by the proved reserves volumes and future development costs. Relative volumes of reserves and production are converted at the energy equivalent conversion ratio of six thousand cubic feet of natural gas to one barrel of oil. Impairment Under the full cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the net capitalized costs of oil and natural gas properties. The net capitalized costs are limited to the lower of unamortized costs less related deferred income taxes or the cost center ceiling. The cost center ceiling is defined as the sum of: (a) the present value, discounted at 10%, of future net revenues of proved oil and natural gas reserves, reduced by the estimated costs of developing these reserves, plus (b) unproved and unevaluated property costs not being amortized, plus (c) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less (d) any income tax effects related to the properties involved. Any excess of the Company's net capitalized costs above the cost center ceiling is expensed as a full-cost ceiling impairment. The Company's derivative instruments are not considered in the ceiling test computations as the Company does not designate these instruments as hedges for accounting purposes. The estimated present value of after-tax future net cash flows from proved oil and natural gas reserves is highly dependent on the quantities of proved reserves, the estimation of which requires substantial judgement. The associated commodity prices and the applicable discount rate used in these estimates are in accordance with guidelines established by the United States Securities and Exchange Commission. Under these guidelines, oil and natural gas reserves are estimated using then-current operating and economic conditions, with no provision for price and cost changes in future periods except by contractual arrangements. Future net revenues are calculated using prices that represent the arithmetic averages of the first-day-of-the-month oil and natural gas prices for the previous 12-month period, and a 10% discount factor is used to determine the present value of future net revenues. For the period from January through December 2022, these average oil and natural gas prices were $94.49 per Bbl and $6.25 per MMBtu, respectively. For the period from January through December 2021, these average oil and natural gas prices were $66.55 per Bbl and $3.64 per MMBtu, respectively. In estimating the present value of after-tax future net cash flows from proved oil and natural gas reserves, the average oil prices were further adjusted by property for quality, transportation and marketing fees and regional price differentials, and the average natural gas prices were further adjusted by property for energy content, transportation and marketing fees and regional price differentials. During the years ended December 31, 2022 and 2021, the Company's full-cost ceiling exceeded the net capitalized costs less related deferred income taxes. As a result, the Company recorded no impairment to its net capitalized costs for those periods. As a non-cash item, the full-cost ceiling impairment impacts the accumulated depletion and the net carrying value of the Company’s assets on its consolidated balance sheets, as well as the corresponding shareholders’ deficiency, but it has no impact on the Company’s net cash flows as reported. Changes in oil and natural gas production rates, oil and natural gas prices, reserves estimates, future development costs and other factors will determine the Company’s actual ceiling test computation and impairment analyses in future periods. Other Impairment Estimates Unproved and unevaluated properties are assessed periodically to determine whether they have been impaired, based on the Company's future development plans, the probability of successful development of properties and the length of time that the Company expects to hold the properties, amongst other factors. Upon impairment, the costs of the unproved and unevaluated properties are immediately included in the depletion base. Exploratory dry holes are included in the depletion base immediately upon determination that the well is not productive. During the year ended December 31, 2022 and 2021, no unproved and unevaluated properties were impaired and transferred to be included in the depletion base as part of evaluated properties. Reserves The assessment of reported recoverable quantities of proved reserves includes estimates regarding production volumes, commodity prices, remediation costs, timing and amount of future development costs, and production, transportation and marketing costs for future cash flows. It also requires interpretation of geological and geophysical models in anticipated recoveries. The economical, geological and technical factors used to estimate reserves may change from period to period. Changes in reported reserves can impact the carrying values of the Company's oil and natural gas properties, the calculation of depletion and depreciation, and the provision for asset retirement obligations. The reserve assessment was completed by an external third-party engineering firm for the years ended December 31, 2022 and 2021 and reserves are internally updated for interim periods. |
Asset Retirement Obligations [Policy Text Block] | Asset Retirement Obligations The Company recognizes asset retirement obligations ("ARO") arising from regulatory, contractual or other legal requirements to perform certain property and asset reclamation activities at the end of the respective asset life when the fair value of this obligation is determinable. These obligations consist of estimated future costs associated with the plugging and abandonment of natural gas and oil wells, and land restoration in accordance with applicable local, state and federal laws. The Company estimates the expected cash flows associated with the obligation and discounts the amounts using a credit-adjusted risk-free interest rate. This discounted fair value of the ARO liability is recognized in the period in which it is incurred, with the associated asset retirement cost capitalized as part of the carrying cost of the related natural gas and oil asset in property, plant and equipment, net and depleted as the reserves are produced. In the estimation of the initial fair value of an ARO, the Company uses assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation, technical assessments of the assets, estimated amounts and timing of settlements including reserve lives, discount rates, and inflation rates. Given the significance of the unobservable nature of a number of the inputs, this measurement is considered Level 3 on the fair value hierarchy (Note 17). In periods subsequent to the initial measurement of an ARO, period-to-period changes are recognized in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the related asset. Accretion, reflecting the increases in the ARO liability due to the passage of time is recognized as part of operating expenses within the consolidated statements of operations and comprehensive income (loss) (Note 6). |
Leases [Policy Text Block] | Leases The Company assesses whether a contract is or contains a lease, at the inception of a contract. A contract is, or contains, a lease if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. The Company recognizes a right-of-use ("ROU") asset and a corresponding lease liability with respect to lease arrangements in which it is the lessee, except for short-term leases (defined as leases with a lease term of 12 months or less). For such short-term leases, the Company recognizes the lease payments as an operating expense on a straight-line basis over the term of the lease unless another systematic basis is more representative of the time pattern in which economic benefits from the leased asset are consumed. The Company also made the accounting policy election to not separate lease and non-lease components for its real estate leases. The lease liability is initially measured at the present value of the unpaid lease payments at the commencement date, discounted by using the rate implicit in the lease. If this rate cannot be readily determined, the Company uses its incremental borrowing rate. Subsequently, the lease liability is measured using the effective interest method, by increasing the carrying amount to reflect accretion on the lease liability and by reducing the carrying amount to reflect the lease payments made. The ROU asset is initially measured at cost, which comprises the initial amount of the lease liability adjusted for lease payments made at or before the lease commencement date, plus any initial direct costs incurred less any lease incentives received. For operating leases, the Company records the amortization of the ROU assets and the accretion of the lease liabilities as a single lease cost on a straight-line basis over the lease term. The measurement of the lease liabilities and ROU assets requires the use of judgment and estimates which are applied in determining whether an arrangement contains a lease, determining the lease term, appropriate discount rate, and whether there are any indicators of impairment for ROU assets. |
Revenue from Contracts with Customers [Policy Text Block] | Revenue from Contracts with Customers The Company enters into contracts with customers to sell its oil, natural gas and natural gas liquids. Revenue from these contracts is recognized when the Company's performance obligations are satisfied, which generally occurs with the transfer of the control to the customer, and when collectability is reasonably assured. The transfer of control usually occurs when the product is physically transferred at the delivery point agreed upon in the contract and legal title to the product passes to the customer (often at terminals, pipelines, or other transportation methods). The Company evaluates creditworthiness on an individual customer basis prior to entering into a sales contract and throughout the contract duration (Note 18) . The sales contracts range from short term to long term contracts that are variable-priced and based on actual quantities delivered each period. The transaction price includes variable consideration as product pricing is based on published market prices and adjusted for contract specified differentials such as quality, energy content and transportation. Determining the variable consideration does not require significant judgment and the Company engages third party sources to validate the estimates. 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 – Revenue from Contracts with Customers (“ASC 606”). The expedient applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. The Company evaluates its arrangements with third parties and partners to determine if the Company acts as the principal or as an agent. In making this evaluation, the Company considers if it obtains control of the product delivered or services provided, which is indicated by the Company having the primary responsibility for the delivery of the product or rendering of the service, having the ability to establish prices or having inventory risk. If the Company acts in the capacity of an agent rather than as a principal in a transaction, then the revenue is recognized on a net-basis. Revenue is recognized net of royalties due to third parties in an amount that reflects the consideration the Company expects to receive in exchange for those products. |
Share Based Compensation [Policy Text Block] | Share Based Compensation The Company grants share purchase options, which are classified as equity settled awards. The fair value of each option granted by the Company are estimated using the Black-Scholes option pricing model and are recognized into general and administrative expense over the vesting period of the options. The Company has also issued restricted share units (“RSUs”) and deferred share units (“DSUs”) which are both accounted for as equity classified awards. The Company’s RSUs and DSUs grants are valued using the intrinsic value method, utilizing the closing share price on the day before the grant and are recognized into general and administrative expense over the vesting period for each grant (Note 12). In all cases for these awards, the Company estimates forfeitures and updates this estimate over the vesting period of the awards. |
Income Taxes [Policy Text Block] | Income Taxes Income tax expense comprises current and deferred tax. The expense is recognized in net income (loss) except to the extent that it relates to a business combination, or items recognized directly in equity or in other comprehensive income (loss). Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Each reporting period, the Company reviews its deferred tax assets for the possibility they will not be realized. A valuation allowance will be recorded if it is more likely than not that a deferred tax asset will not be realized. The benefits of uncertain tax positions that the company has taken or expects to take in its income tax returns are recognized in the financial statements if management concludes that it is more likely than not that the position will be sustained with the tax authorities. Significant judgment is required in the accounting for income tax contingencies and tax disputes because the outcomes are often difficult to predict. The Company did not have any uncertain tax positions during the periods presented in these financial statements. Interest and penalties are recognized in finance expense and income tax expense, respectively. For the fiscal years ended December 31, 2022 and 2021, the Company did not incur interest and penalties related to income taxes. |
Non-Controlling Interests [Policy Text Block] | Non-Controlling Interests Non-controlling interests ("NCI") represent ownership interest in consolidated subsidiaries which are not owned, directly or indirectly, by the Company. The portion of equity not owned by the Company in such entities is reflected as NCI within the equity section of the consolidated balance sheets, and the share of income/(loss) attributable to NCI is shown as a component of net income/(loss) in the consolidated statements of operations and comprehensive income (loss). Changes to the parent company's ownership that do not result in a loss of control are accounted for as equity transactions. |
Redeemable Non-controlling Interests [Policy Text Block] | Redeemable Non-controlling Interests Non-controlling interests with redemption features that are not solely within the control of the Company are considered redeemable non-controlling interests. The Company's redeemable non-controlling interests ("Redeemable NCI") reflects the development partnership units that are not held by the Company either directly or indirectly, and which contain certain redemption rights, as described in Note 9. The Redeemable NCI is classified in temporary equity that is reported between liabilities and shareholders’ deficiency on the consolidated balance sheets and is initially recognized at its issuance date fair value. Subsequently, the Redeemable NCI is adjusted each reporting period for the net income (or loss) attributable to the Redeemable NCI interests. Further measurement adjustments are made to adjust the Redeemable NCI to the higher of the redemption value or the carrying value each reporting period. The measurement adjustments to the redemption value are recognized through accumulated deficit and are reflected in the attribution of net income (loss) between the NCI holders, the common shareholders of the Company and the Redeemable NCI holders, such that an increase in the redemption value over the carrying value would increase the net income attributed to the Redeemable NCI. The redemption value is calculated based on future net present values of the oil and gas reserves of the related development partnership, subject to a fixed discount rate. |
Adoption of New Accounting Standards [Policy Text Block] | Adoption of New Accounting Standards Accounting Standards Update ("ASU") 2019-12, Income Taxes (Topic 740) - Simplifying the Accounting for Income Taxes ASU 2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity's Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity's Own Equity ASU 2020-04, Reference Rate Reform (Topic 848) - Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848 |
Future Accounting Standard Changes [Policy Text Block] | Future Accounting Standard Changes ASU 2021-08 - Business Combinations (Topic 805): Accounting for Contract Assets and Contract Liabilities from Contracts with Customers The Company considers the applicability and the impact of all ASUs. ASUs not discussed above were assessed and determined to be either not applicable, the effects of adoption are not expected to be material or are clarifications of ASUs previously disclosed. |
ACCOUNTS RECEIVABLE, NET (Table
ACCOUNTS RECEIVABLE, NET (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Receivables [Abstract] | |
Schedule of accounts receivable, net [Table Text Block] | December 31, 2022 2021 Trade receivables from sales of crude oil and natural gas $ 24,097,294 $ 18,110,135 Joint interest billing receivables and other 2,368,914 687,500 Accounts receivable, net $ 26,466,208 $ 18,797,635 |
OIL AND NATURAL GAS PROPERTIES
OIL AND NATURAL GAS PROPERTIES (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Property, Plant and Equipment [Abstract] | |
Schedule of property, plant and equipment, net [Table Text Block] | December 31, 2022 2021 Oil and natural gas properties: Evaluated (subject to depletion) $ 347,541,801 $ 110,155,103 Unproved and unevaluated (not subject to depletion) 42,866,767 24,987,312 Total oil and gas properties 390,408,568 135,142,415 Accumulated depreciation, depletion, and amortization (87,993,495 ) (25,911,025 ) Oil and gas properties, net $ 302,415,073 $ 109,231,390 |
Schedule of unproved and unevaluated property costs [Table Text Block] | Description 2022 2021 2020 2019 and Total Costs incurred for: Property acquisition $ 2,244,517 $ 4,300,745 $ - $ 1,243,615 $ 7,788,877 Exploration 1,635,842 1,222,509 - - 2,858,351 Development 32,219,539 - - - 32,219,539 Total unproved and unevaluated (not subject to depletion) $ 36,099,898 $ 5,523,254 $ - $ 1,243,615 $ 42,866,767 |
LEASES (Tables)
LEASES (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Leases [Abstract] | |
Schedule undiscounted cash flows or operating leases [Table Text Block] | Operating Leases 2023 $ 234,092 2024 237,524 2025 181,363 Total undiscounted lease payments 652,979 Less: effect of discounting (41,088 ) Total lease liability $ 611,891 |
ASSET RETIREMENT OBLIGATIONS (T
ASSET RETIREMENT OBLIGATIONS (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of asset retirement obligation [Table Text Block] | 2022 2021 Balance as at January 1 $ 431,704 $ 219,937 Liabilities incurred and acquired 89,636 121,553 Liabilities settled (127,862 ) (29,913 ) Revision of estimates 20,844 95,918 Accretion expense 43,756 24,209 Balance as at December 31 $ 458,078 $ 431,704 |
DEBT (Tables)
DEBT (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Debt Disclosure [Abstract] | |
Schedule of repayments of undiscounted principal required under ABS Facility [Table Text Block] | 2023 $ 61,630,567 2024 48,352,110 2025 and thereafter - Total $ 109,982,677 |
Schedule of carrying value of the outstanding loan balances [Table Text Block] | December 31, 2022 Current Long-term Total (net) Principal drawn $ 61,630,567 $ 48,352,110 $ 109,982,677 Unamortized discount and interest at the imputed rate 680,615 842,926 1,523,541 Unamortized debt issuance costs (2,084,263 ) (516,328 ) (2,600,591 ) Total (net) $ 60,226,919 $ 48,678,708 $ 108,905,627 |
Schedule of outstanding balances under facility [Table Text Block] | December 31, 2022 Current Long-term Total (net) Principal drawn - - - Unamortized discount and debt issuance costs - - - Total (net) - - - December 31, 2021 Current Long-term Total (net) Principal drawn $ 7,722,206 $ 17,515,203 $ 25,237,409 Unamortized discount and debt issuance costs (662,372 ) (1,375,896 ) (2,038,268 ) Total (net) $ 7,059,834 $ 16,139,307 $ 23,199,141 |
OTHER DEBT INSTRUMENTS (Tables)
OTHER DEBT INSTRUMENTS (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Disclosure of Securitized or Asset-Backed Financing Arrangement Assets and Other Financial Assets Managed Together [Abstract] | |
Schedule of promissory and convertible promissory notes outstanding [Table Text Block] | 2022 2021 Balance as at January 1 - $ 5,425,000 Issued for cash - 3,375,000 Converted to Origination Member Units - (3,475,000 ) Converted to LP Units - (1,000,000 ) Repayment of notes - (2,025,000 ) Converted to Origination Member Units - (2,300,000 ) Balance as at December 31 - - |
REDEEMABLE NON-CONTROLLING IN_2
REDEEMABLE NON-CONTROLLING INTERESTS (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Temporary Equity Disclosure [Abstract] | |
Schedule of movement in redeemable non-controlling interests [Table Text Block] | 2022 2021 Balance as at January 1 $ 46,552,839 $ - Redeemable non-controlling interests issued 154,456,707 55,138,395 Net loss and comprehensive loss attributed 10,598,514 12,851,005 Revaluation to redemption value, net 23,197,507 240,903 Distributions (3,340,254 ) (6,388,870 ) Settlement (123,881,576 ) (15,288,594 ) Balance as at December 31 $ 107,583,737 $ 46,552,839 |
EQUITY (Tables)
EQUITY (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Equity [Abstract] | |
Schedule of movements in common shares [Table Text Block] | Origination Member Units SVS Shares MVS Shares PVS Shares Total Share Capital Shares Amount Shares Amount Shares Amount Shares Amount Balance as at January 1, 2021 17,083,501 $ 37,097,376 - $ - - $ - - $ - $ 37,097,376 Issuance of member units for cash 819,215 8,044,700 - - - - - - 8,044,700 Issuance of member units exchanged for notes 353,870 3,475,000 - - - - - - 3,475,000 Issuance of member units for oil and gas properties 356,415 3,499,995 - - - - - - 3,499,995 Issuance of member units to contractors 923,954 9,073,228 - - - - - - 9,073,228 Redemption of member units (3,992,629 ) (8,680,786 ) - - - - - - (8,680,786 ) Issuance of member units exchanged for notes 234,216 2,300,000 - - - - - - 2,300,000 Origination Member Units split 1:3 31,557,084 - - - - - - - - Allocation of opening non-controlling interest (16,168,422 ) (18,721,276 ) - - - - - - (18,721,276 ) Exchange of units for SVS and MVS (31,167,204 ) (36,088,237 ) 1,427,421 1,652,798 297,398 34,435,439 - - - Shares issued for cash, net of share issuance costs of $247,218 - - 161,976 476,978 17,057 5,022,854 - - 5,499,832 PVS issued for cash - - - - - - 15,947 128,213 128,213 Shares issued on reverse recapitalization - - 534,384 1,697,865 - - - - 1,697,865 Conversion of MVS to SVS - - 30,411,950 38,161,379 (304,120 ) (38,161,379 ) - - - Balance as at December 31, 2021 - $ - 32,535,731 $ 41,989,020 10,335 $ 1,296,914 15,947 $ 128,213 $ 43,414,147 Exchange of units for SVS and MVS - - 195,541 245,368 (1,955 ) (245,368 ) - - - Settlement of RSUs - - 2,024,401 9,685,555 - - - - 9,685,555 Repurchase of SVS for cancellation - - (799,600 ) (4,324,915 ) - - - - (4,324,915 ) Balance as at December 31, 2022 - $ - 33,956,073 $ 47,595,028 8,380 $ 1,051,546 15,947 $ 128,213 $ 48,774,787 |
SHARE BASED COMPENSATION (Table
SHARE BASED COMPENSATION (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Summary of share-based compensation arrangements by share-based payment award [Table Text Block] | Stock options Weighted- Weighted Aggregate Outstanding, January 1, 2022 2,834,288 $ 3.56 Granted - - Forfeited - - Expired - - Exercised 1 - - Outstanding, December 31, 2022 2,834,288 $ 3.56 8.95 $ 4,166,403 Exercisable, December 31, 2022 1,803,985 $ 3.56 8.95 $ 2,651,858 |
Summary of weighted average assumptions used to determine the fair value of the options granted [Table Text Block] | For the year ended, December 31, 2022 2021 Fair value of options granted N/A 2.21 Valuation assumptions: Expected life (years) 5.55 5.72 Risk-free interest rate 1.27% 1.27% Average forfeiture rate 0.00% 0.00% Expected dividend yield 0.00% 0.00% Expected volatility 71.62% 71.62% |
Restricted Stock Units (RSUs) [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Summary of share units [Table Text Block] | Restricted Weighted- Weighted average Aggregate Nonvested, January 1, 2022 892,580 $ 3.56 Granted 1 1,214,321 5.75 Forfeited - - Vested and settled 2 (2,024,401 ) 4.78 Nonvested, December 31, 2022 82,500 $ 5.75 0.67 $ 414,975 |
Deferred Share Units [Member] | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |
Summary of share units [Table Text Block] | Deferred Weighted- average grant Weighted average Aggregate Outstanding, January 1, 2022 137,641 $ 3.56 Granted 1 88,694 5.75 Forfeited - - Settled - - Outstanding, December 31, 2022 226,335 $ 4.42 0.42 $ 1,138,465 Vested 2 , December 31, 2022 137,641 $ 3.56 N/A $ 692,334 |
EARNINGS PER SHARE (Tables)
EARNINGS PER SHARE (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Earnings Per Share [Abstract] | |
Schedule of basic earnings per share [Table Text Block] | For the year ended, December 31, 2022 2021 Net income (loss) attributable to common shareholders $ 7,428,135 $ ( 32,344,428 ) Weighted average number of common shares outstanding (as-converted) 34,453,696 42,596,264 Income (loss) per share - basic $ 0.22 $ (0.76 ) |
Schedule of diluted earnings per share [Table Text Block] | For the year ended, December 31, 2022 2021 Net income (loss) attributable to common shareholders $ 7,428,135 $ (32,344,428 ) Plus: Effect of dilutive items 3,189,196 - $ 10,617,331 $ (32,344,424 ) Weighted average number of common shares outstanding (as-converted) 34,453,696 42,596,264 Plus: Effect for conversion of Origination Class B into SVS 18,203,421 - Plus: Effect for dilutive share-based compensation awards 929,210 - 53,586,327 42,596,264 Income (loss) per share - diluted $ 0.20 $ (0.76 ) |
REVENUE FROM CONTRACTS WITH C_2
REVENUE FROM CONTRACTS WITH CUSTOMERS (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Revenue from Contract with Customer [Abstract] | |
Schedule of revenue from contracts with customers [Table Text Block] | For the year ended, December 31, 2022 2021 Crude oil $ 97,438,790 $ 50,868,794 Natural gas 77,966,801 10,286,929 Natural gas liquids 20,243,366 9,641,067 Total operating revenues $ 195,648,957 $ 70,796,790 |
INCOME TAX (Tables)
INCOME TAX (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Income Tax Disclosure [Abstract] | |
Schedule of provision for income taxes [Table Text Block] | Year ended December 31, 2022 2021 Current income tax expense: United States federal $ - $ - State - - Total current income tax expense - - Deferred income tax expense (benefit): United States federal $ (1,928,319 ) $ 1,928,319 State - - Total deferred income tax expense (benefit) $ (1,928,319 ) $ 1,928,319 Total income tax expense (benefit) $ (1,928,319 ) $ 1,928,319 |
Schedule of income tax rate reconciliation [Table Text Block] | Year ended December 31, 2022 2021 Net income (loss) before taxes $ 42,485,033 $ (30,654,438 ) U. S. federal statutory income tax rate 21% 21% Expected federal taxes at statutory rate 8,921,857 (6,437,432 ) Increase (decrease) resulting from: Canadian income tax - - Non-controlling interests (7,766,896 ) 54,250 Income (loss) not subject to corporate income taxes (1,154,961 ) 6,383,182 Change in tax status - 1,928,319 Change in valuation allowance - federal (1,928,319 ) - Income tax expense (recovery) $ (1,928,319 ) $ 1,928,319 |
Schedule of deferred income tax assets and liabilities [Table Text Block] | Year ended December 31, 2022 2021 Deferred tax liabilities Investment in Origination $ - $ (3,437,344 ) Total deferred tax liabilities - (3,437,344 ) Deferred tax assets Investment in Origination $ 10,518,502 $ 1,509,025 Canadian federal tax loss carryforwards 339,501 334,198 US federal tax loss carryforwards 9,361,332 - Total deferred tax assets, gross 20,219,335 1,843,223 Less: Valuation allowance (20,219,335 ) (334,198 ) Total deferred tax assets, net - 1,509,025 Net deferred tax assets (liabilities) - (1,928,319 ) Presented as follows: Total deferred tax assets - - Total deferred tax liabilities - (1,928,319 ) Net deferred tax assets (liabilities) $ - $ (1,928,319 ) |
FAIR VALUE MEASUREMENTS (Tables
FAIR VALUE MEASUREMENTS (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Fair Value Disclosures [Abstract] | |
Schedule of financial assets and liabilities measured at fair value on a recurring basis [Table Text Block] | Fair Value Measurements as at December 31, 2022 using Level 1 Level 2 Level 3 Assets (liabilities): Commodity derivatives - $ 3,077,079 - Interest rate derivatives - - - Total - $ 3,077,079 - Fair Value Measurements as at December 31, 2021 using Level 1 Level 2 Level 3 Assets (liabilities): Commodity derivatives - $ (20,424,601 ) - Interest rate derivatives - 43,421 - Total - $ (20,381,180 ) - |
RISK MANAGEMENT AND FINANCIAL_2
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
General Discussion of Derivative Instruments and Hedging Activities [Abstract] | |
Schedule of derivative instruments, gain (loss) [Table Text Block] | Year ended December 31, Statements of Operations Location 2022 2021 Commodity derivative contracts Unrealized gain (loss) Gain / (loss) on derivative instruments $ 26,246,351 $ (15,903,217 ) Realized gain (loss) Gain / (loss) on derivative instruments (36,269,846 ) (17,622,236 ) Total gain (loss), net $ (10,023,495 ) $ (33,525,453 ) Interest rate derivative contracts Unrealized gain Finance and interest expense $ - $ 43,421 Realized gain Finance and interest expense 623,579 - Total gain (loss), net $ 623,579 $ 43,421 |
Schedule of derivative instruments [Table Text Block] | 2023 2024 2025 Total Volumes Crude Oil: WTI NYMEX - Swaps: Volumes (Bbl) 542,548 286,150 129,642 958,340 Weighted Average Price ($/Bbl) $ 69.79 $ 65.97 $ 58.98 Natural Gas and Natural Gas Liquids: Natural Gas NYMEX - Swaps: Volumes (MMBtu) 5,306,902 2,606,643 1,331,415 9,244,960 Weighted Average Price ($/MMBtu) $ 5.43 $ 5.43 $ 5.33 Natural Gas NYMEX vs. Houston Ship Channel - Basis Swaps: Volumes (MMBtu) 465,214 325,088 177,009 967,311 Weighted Average Price ($/MMBtu) $ (0.07 ) $ (0.07 ) $ (0.07 ) Mont Belvieu Natural Gas - Swaps: Volumes (Gal) 1,560,711 857,027 326,472 2,744,210 Weighted Average Price ($/Gal) $ 1.30 $ 1.57 $ 1.65 Mont Belvieu Ethane - Swaps: Volumes (Gal) 5,818,913 3,195,317 1,217,209 10,231,439 Weighted Average Price ($/Gal) $ 0.30 $ 0.34 $ 0.36 Mont Belvieu Propane - Swaps: Volumes (Gal) 3,466,691 1,903,650 725,170 6,095,511 Weighted Average Price ($/Gal) $ 0.80 $ 0.92 $ 0.95 Mont Belvieu Isobutane - Swaps: Volumes 673,486 369,828 140,880 1,184,194 Weighted Average Price ($/Gal) $ 0.89 $ 1.06 $ 1.10 Mont Belvieu N. Butane - Swaps Volumes 1,426,461 783,308 298,388 2,508,157 Weighted Average Price ($/Gal) $ 0.87 $ 1.04 $ 1.08 |
Schedule of derivative assets and liabilities [Table Text Block] | As at December 31, 2022 2021 Derivative Assets: Current assets $ 2,019,600 $ - Noncurrent assets 1,057,479 - Total Derivative Assets: $ 3,077,079 $ - Derivative Liabilities: Current liabilities $ - $ 6,479,508 Noncurrent liabilities - 13,901,672 Total Derivative Liabilities: $ - $ 20,381,180 |
FINANCE AND INTEREST EXPENSE (T
FINANCE AND INTEREST EXPENSE (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Finance and Interest Expense [Abstract] | |
Schedule of finance expenses [Table Text Block] | Year ended December 31, 2022 2021 Interest expense on long term debt $ 11,389,415 $ 3,612,929 Interest expense for Corporate Credit Facility 1,736,868 - Interest on asset back preferred 658,047 1,857,351 Interest on promissory notes - 300,685 Interest rate derivative loss (gain) (623,579 ) (43,421 ) Interest income (14,966 ) - Bank fees and other 282,548 - Total finance and interest expense $ 13,428,333 $ 5,727,544 |
GENERAL AND ADMINISTRATIVE EX_2
GENERAL AND ADMINISTRATIVE EXPENSE (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
General and Administrative Expense [Abstract] | |
Schedule of general and administrative expense [Table Text Block] | Year ended December 31, 2022 2021 Stock based compensation expense $ 10,197,720 $ 14,478,776 Employee salaries and benefits 10,193,583 6,483,720 Professional, legal, and advisory 4,672,072 3,629,525 Travel and accommodation 278,653 174,769 Software 462,754 344,577 Operating lease and variable lease costs 215,487 75,170 Office and administration 986,558 251,246 Recoveries (916,667 ) (416,666 ) Total general and administrative expense $ 26,090,160 $ 25,021,117 |
SUPPLEMENTAL CASH FLOW DISCLO_2
SUPPLEMENTAL CASH FLOW DISCLOSURES (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Supplemental Cash Flow Information [Abstract] | |
Schedule of supplemental cash flow information [Table Text Block] | Year ended December 31, 2022 2021 Supplementary cash flow information Cash paid for interest $ 7,903,446 $ 2,278,570 Cash paid for income taxes - - Non-Cash Investing Activities Property, plant and equipment non-cash accruals $ 43,487,444 $ 15,752,315 Capitalized asset retirement obligations 110,480 217,471 Acquisition of oil and natural gas properties via share issuance - 3,499,995 $ 43,597,924 $ 19,469,781 Non-Cash Financing Activities Redemption of Redeemable NCI via issuance of Redeemable NCI $ 100,727,774 $ 14,095,702 Redemption of Redeemable NCI via issuance of Origination Member Units 15,581,968 1,192,893 Redemption of Redeemable NCI via oil and gas property disposition 542,584 - Redemption of promissory notes vis equity issuance - 6,775,000 $ 116,852,326 $ 22,063,595 Changes in Operating Assets and Liabilities Accounts receivable, net $ (7,668,573 ) $ (12,675,672 ) Prepaid expenses (540,223 ) (510,063 ) Accounts payable and accrued liabilities 4,699,365 19,986,246 Asset backed preferred instrument accrued interest - 1,857,351 Asset retirement obligation settlements (127,862 ) - Operating lease asset (235,564 ) - Operating leases liability 103,302 9,542 $ ( 3,769,555 ) $ 8,667,404 |
SUPPLEMENTAL OIL AND GAS INFO_2
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Extractive Industries [Abstract] | |
Schedule of costs incurred in crude oil and natural gas acquisition, exploration and development activities [Table Text Block] | For the year ended December 31, 2022 2021 Unevaluated property acquisition $ 2,244,517 $ 6,200,745 Development 248,185,340 68,323,942 Exploration costs 5,179,046 1,406,101 Total $ 255,608,903 $ 75,930,788 |
Schedule of proved developed and undeveloped oil and gas reserve quantities [Table Text Block] | Oils Natural Gas NGLs Total (Mbbl) (MMcf) (Mbbl) MBOE Total proved reserves at December 31, 2020 5,209 23,505 5,156 14,283 Revisions of previous estimates, and other (2,445 ) 5,415 (3,550 ) (5,093 ) Improved recovery 1,715 6,201 1,220 3,969 Production (743 ) (2,398 ) (358 ) (1,501 ) Total proved reserves at December 31, 2021 3,735 32,724 2,469 11,658 Revisions of previous estimates, and other (1,850 ) (27,505 ) (1,271 ) (7,705 ) Extensions, discoveries and other additions 2,281 93,381 1,930 19,775 Improved recovery 1,111 14,069 671 4,127 Production (1,030 ) (13,317 ) (588 ) (3,838 ) Total proved reserves at December 31, 2022 4,247 99,352 3,211 24,017 Proved Developed Reserves: December 31, 2020 2,275 6,672 1,692 5,079 December 31, 2021 2,137 7,468 1,041 4,423 December 31, 2022 3,973 70,480 2,962 18,682 Proved Undeveloped Reserves: December 31, 2020 2,934 16,833 3,464 9,204 December 31, 2021 1,598 25,256 1,428 7,235 December 31, 2022 274 28,872 249 5,335 |
Schedule of standardized measure of discounted future net cash flows relating to proved crude oil and natural gas reserves [Table Text Block] | For the year ended December 31, 2022 2021 Future cash inflows $ 1,092,307,120 $ 247,313,824 Future production costs (136,423,094 ) (53,266,494 ) Future development and abandonment costs (75,501,920 ) (3,124,700 ) Future income tax expense (98,092,314 ) (24,496,630 ) Future net cash inflows $ 782,289,792 $ 166,426,000 10% annual discount for estimated timing of cash flows (303,833,120 ) (55,888,400 ) Standardized measure of discounted future net cash flows $ 478,456,672 $ 110,537,600 |
Schedule of oil and gas, average sale price and production cost [Table Text Block] | Oil Natural Gas NGLs (Mbbl) (MMcf) (Mbbl) December 31, 2022 $ 94.49 $ 6.25 $ 32.62 December 31, 2021 $ 66.55 $ 3.64 $ 27.29 |
Schedule of changes in the standardized measure of discounted future net cash flows [Table Text Block] | For the year ended December 31, 2022 2021 Beginning of period $ 110,537,600 $ 82,028,564 Sales of oil and natural gas produced, net of production costs (81,065,058 ) (26,623,743 ) Extensions, discoveries and other additions 200,494,177 (12,803,556 ) Previously estimated development cost incurred during the period (3,124,700 ) 14,038,000 Net change of prices and production costs 139,967,308 114,050,543 Change in future development and abandonment costs (57,466,319 ) 48,932,984 Revisions of quantity and timing estimates 225,544,516 (120,961,889 ) Accretion of discount (760,264 ) 18,575,522 Change in income taxes (55,419,410 ) 8,768,285 Other (251,178 ) (15,467,110 ) End of period $ 478,456,672 $ 110,537,600 |
GENERAL (Narrative) (Details)
GENERAL (Narrative) (Details) | 1 Months Ended | 12 Months Ended | ||||||
Sep. 07, 2021 $ / shares | Sep. 07, 2021 USD ($) $ / shares shares | Apr. 08, 2021 USD ($) shares | Aug. 18, 2021 CAD ($) $ / shares shares | Aug. 18, 2021 USD ($) shares | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | Apr. 08, 2021 CAD ($) | |
Business Acquisition [Line Items] | ||||||||
Cash acquired on acquisition | $ 0 | $ 396,173 | ||||||
Business Combination Agreement [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Number of voting rights subscribed | shares | 15,947.292 | |||||||
Percentage of voting equity interests acquired | 32.20% | |||||||
Estimated fair market value of voting rights subscribed | $ 128,213 | |||||||
Finco Financing [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Gross proceeds, through issuance of subscription receipts | $ 7,500,000 | |||||||
Aggregate subordinate voting subscription receipts | shares | 161,976 | 161,976 | ||||||
Subordinate voting rights, subscription price per subscription receipt | $ / shares | $ 4.01 | |||||||
Aggregate multiple voting subscription receipts | shares | 17,057 | 17,057 | ||||||
Multiple voting rights, subscription price per subscription receipt | $ / shares | $ 401.29 | |||||||
Multiple voting subscription aggregate proceeds | $ 7,500,000 | $ 5,499,832 | ||||||
Reverse Recapitalization [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Subordinate voting rights, subscription price per subscription receipt | (per share) | $ 4.01 | $ 3.18 | ||||||
Number of subordinate voting subscription receipts issued | shares | 534,384 | |||||||
Total consideration transferred | $ 1,697,865 | |||||||
Cash acquired on acquisition | $ 396,173 | |||||||
Other expenses | $ 1,567,967 | |||||||
Agent [Member] | Finco Financing [Member] | ||||||||
Business Acquisition [Line Items] | ||||||||
Cash commission paid to agent | 21,002 | |||||||
Advisory fee | $ 156,381 |
SUMMARY OF SIGNIFICANT ACCOUN_3
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Narrative) (Details) | 12 Months Ended | |||||
Dec. 31, 2022 CAD ($) | Dec. 31, 2022 CAD ($) USD_Bbl | Dec. 31, 2022 CAD ($) USD_MMBtu | Dec. 31, 2021 USD ($) USD_Bbl | Dec. 31, 2021 USD ($) USD_MMBtu | Dec. 31, 2022 USD ($) | |
Accounting Policies [Abstract] | ||||||
Working capital (deficit) | $ (162,980,101) | $ (162,980,101) | $ (162,980,101) | |||
Restricted cash | $ 0 | $ 0 | $ 3,375,395 | |||
Discount rate used to determine the present value of future net revenues | 10% | |||||
Average oil and natural gas price (per Bbl/MMBtu) | 94.49 | 6.25 | 66.55 | 3.64 |
ACCOUNTS RECEIVABLE, NET - Sche
ACCOUNTS RECEIVABLE, NET - Schedule of accounts receivable, net (Details) - USD ($) | Dec. 31, 2022 | Dec. 31, 2021 |
Receivables [Abstract] | ||
Trade receivables from sales of crude oil and natural gas | $ 24,097,294 | $ 18,110,135 |
Joint interest billing receivables and other | 2,368,914 | 687,500 |
Accounts receivable, net | $ 26,466,208 | $ 18,797,635 |
OIL AND NATURAL GAS PROPERTIE_2
OIL AND NATURAL GAS PROPERTIES (Narrative) (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items] | ||
Depletion and depreciation | $ 62,082,471 | $ 23,497,715 |
Depletion per barrel of oil equivalent | $ 16.18 | $ 15.66 |
OIL AND NATURAL GAS PROPERTIE_3
OIL AND NATURAL GAS PROPERTIES - Schedule of property, plant and equipment, net (Details) - USD ($) | Dec. 31, 2022 | Dec. 31, 2021 |
Oil and natural gas properties: | ||
Evaluated (subject to depletion) | $ 347,541,801 | $ 110,155,103 |
Unproved and unevaluated (not subject to depletion) | 42,866,767 | 24,987,312 |
Total oil and gas properties | 390,408,568 | 135,142,415 |
Accumulated depreciation, depletion, and amortization | (87,993,495) | (25,911,025) |
Oil and gas properties, net | $ 302,415,073 | $ 109,231,390 |
OIL AND NATURAL GAS PROPERTIE_4
OIL AND NATURAL GAS PROPERTIES - Schedule of unproved and unevaluated property costs (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Costs incurred for: | ||
Property acquisition | $ 2,244,517 | $ 6,200,745 |
Exploration | 5,179,046 | 1,406,101 |
Development | 248,185,340 | 68,323,942 |
Total unproved and unevaluated (not subject to depletion) | 255,608,903 | $ 75,930,788 |
Unproved and unevaluated property costs not subject to depletion [Member] | ||
Costs incurred for: | ||
Property acquisition | 7,788,877 | |
Exploration | 2,858,351 | |
Development | 32,219,539 | |
Total unproved and unevaluated (not subject to depletion) | 42,866,767 | |
Unproved and unevaluated property costs not subject to depletion [Member] | 2022 [Member] | ||
Costs incurred for: | ||
Property acquisition | 2,244,517 | |
Exploration | 1,635,842 | |
Development | 32,219,539 | |
Total unproved and unevaluated (not subject to depletion) | 36,099,898 | |
Unproved and unevaluated property costs not subject to depletion [Member] | 2021 [Member] | ||
Costs incurred for: | ||
Property acquisition | 4,300,745 | |
Exploration | 1,222,509 | |
Development | 0 | |
Total unproved and unevaluated (not subject to depletion) | 5,523,254 | |
Unproved and unevaluated property costs not subject to depletion [Member] | 2020 [Member] | ||
Costs incurred for: | ||
Property acquisition | 0 | |
Exploration | 0 | |
Development | 0 | |
Total unproved and unevaluated (not subject to depletion) | 0 | |
Unproved and unevaluated property costs not subject to depletion [Member] | 2019 and prior [Member] | ||
Costs incurred for: | ||
Property acquisition | 1,243,615 | |
Exploration | 0 | |
Development | 0 | |
Total unproved and unevaluated (not subject to depletion) | $ 1,243,615 |
LEASES (Narrative) (Details)
LEASES (Narrative) (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Loss Contingencies [Line Items] | ||
Operating lease cost | $ 137,782 | $ 74,101 |
Variable lease cost | 77,705 | 1,069 |
Operating lease liabilities | 144,539 | $ 0 |
Undiscounted lease payments | $ 652,979 | |
New office space [Member] | ||
Loss Contingencies [Line Items] | ||
Non-cancellable term of lease | 10 years | |
Undiscounted lease payments | $ 2,226,432 |
LEASES - Schedule of undiscount
LEASES - Schedule of undiscounted cash flows for operating leases (Details) | Dec. 31, 2022 USD ($) |
Leases [Abstract] | |
2023 | $ 234,092 |
2024 | 237,524 |
2025 | 181,363 |
Lessee, Operating Lease, Liability, to be Paid, Total | 652,979 |
Less: effect of discounting | (41,088) |
Total lease liability | $ 611,891 |
ASSET RETIREMENT OBLIGATIONS (N
ASSET RETIREMENT OBLIGATIONS (Narrative) (Details) - CAD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Asset Retirement Obligation Disclosure [Abstract] | ||
Cash paid to settle adjusted retirement obligation | $ 2,634,225 | $ 1,340,178 |
Weighted average credit-adjusted risk-free interest rate | 10.32% | 9.73% |
Inflation rate | 2.28% | 2.42% |
ASSET RETIREMENT OBLIGATIONS -
ASSET RETIREMENT OBLIGATIONS - Schedule of asset retirement obligation (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Asset Retirement Obligation Disclosure [Abstract] | ||
Asset Retirement Obligation, Beginning Balance | $ 431,704 | $ 219,937 |
Liabilities incurred and acquired | 89,636 | 121,553 |
Liabilities settled | (127,862) | (29,913) |
Revision of estimates | 20,844 | 95,918 |
Accretion expense | 43,756 | 24,209 |
Asset Retirement Obligation, Ending Balance | $ 458,078 | $ 431,704 |
DEBT (Narrative) (Details)
DEBT (Narrative) (Details) - USD ($) | 1 Months Ended | 12 Months Ended | ||||||
Sep. 12, 2022 | Apr. 27, 2022 | Oct. 31, 2021 | Dec. 22, 2020 | Dec. 31, 2022 | Dec. 31, 2021 | Oct. 31, 2022 | Mar. 31, 2022 | |
ABS Facility [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Debt service coverage ratio | maintaining a debt service coverage ratio of no less that 1.1 to 1.0 | |||||||
Finance expense | $ 8,968,929 | $ 0 | ||||||
Payments for interest | $ 5,808,996 | |||||||
ABS Facility [Member] | Tranche 1 [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Current borrowing capacity | $ 80,000,000 | |||||||
Maximum borrowing capacity | $ 150,000,000 | |||||||
Interest rate description | LIBOR+6% (with a 1% LIBOR floor) for the initial year, LIBOR +12% (with a 1% LIBOR floor) for the second year | |||||||
Interest rate | 12.20% | |||||||
ABS Facility [Member] | Tranche 2 [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Increased borrowing capacity | $ 55,000,000 | |||||||
Current borrowing capacity | $ 135,000,000 | |||||||
Interest rate description | LIBOR+8% (with a 1% LIBOR floor) for the initial year, LIBOR +14% (with a 1% LIBOR floor) for the second year | |||||||
Interest rate | 13.60% | |||||||
Goldman Facility [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Interest rate description | LIBOR+6% (with a 1% LIBOR floor) | |||||||
Finance expense | $ 2,420,486 | 3,612,927 | ||||||
Corporate Credit Facility [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Maximum borrowing capacity | $ 12,500,000 | |||||||
Interest rate description | prime +2.25% | |||||||
New Corporate Facility [Member] | ||||||||
Debt Instrument [Line Items] | ||||||||
Maximum borrowing capacity | $ 65,000,000 | $ 30,000,000 | ||||||
Interest rate description | greater of 5.00% and prime +1.75% | |||||||
Amount outstanding under facility | $ 41,500,000 | 2,200,000 | ||||||
Finance expense | 1,736,868 | 0 | ||||||
Borrowing base | $ 64,435,764 | $ 6,579,750 |
DEBT - Schedule of repayments o
DEBT - Schedule of repayments of undiscounted principal required under ABS Facility (Details) - ABS Facility [Member] | Dec. 31, 2022 USD ($) |
Debt Instrument [Line Items] | |
2023 | $ 61,630,567 |
2024 | 48,352,110 |
2025 and thereafter | 0 |
Total | $ 109,982,677 |
DEBT - Schedule of carrying val
DEBT - Schedule of carrying value of the outstanding loan balances (Details) - USD ($) | Dec. 31, 2022 | Dec. 31, 2021 |
Current | ||
Principal drawn | $ 61,630,567 | |
Unamortized discount and interest at the imputed rate | 680,615 | |
Unamortized discount and debt issuance costs | 2,084,263 | |
Total (net) | 60,226,919 | $ 7,059,834 |
Long-term | ||
Principal drawn | 48,352,110 | |
Unamortized discount and interest at the imputed rate | 842,926 | |
Unamortized discount and debt issuance costs | 516,328 | |
Total (net) | 48,678,708 | $ 16,139,307 |
Total (net) | ||
Principal drawn | 109,982,677 | |
Unamortized discount and interest at the imputed rate | 1,523,541 | |
Unamortized discount and debt issuance costs | 2,600,591 | |
Total (net) | $ 108,905,627 |
DEBT - Schedule of outstanding
DEBT - Schedule of outstanding balances under facility (Details) - USD ($) | Dec. 31, 2022 | Dec. 31, 2021 |
Current | ||
Principal drawn | $ 61,630,567 | |
Unamortized discount and debt issuance costs | (680,615) | |
Total (net) | 60,226,919 | $ 7,059,834 |
Long-term | ||
Principal drawn | 48,352,110 | |
Unamortized discount and debt issuance costs | (842,926) | |
Total (net) | 48,678,708 | 16,139,307 |
Total (net) | ||
Principal drawn | 109,982,677 | |
Unamortized discount and debt issuance costs | (1,523,541) | |
Total (net) | 108,905,627 | |
Goldman Facility [Member] | ||
Current | ||
Principal drawn | 0 | 7,722,206 |
Unamortized discount and debt issuance costs | 0 | (662,372) |
Total (net) | 0 | 7,059,834 |
Long-term | ||
Principal drawn | 0 | 17,515,203 |
Unamortized discount and debt issuance costs | 0 | (1,375,896) |
Total (net) | 0 | 16,139,307 |
Total (net) | ||
Principal drawn | 0 | 25,237,409 |
Unamortized discount and debt issuance costs | 0 | (2,038,268) |
Total (net) | $ 0 | $ 23,199,141 |
OTHER DEBT INSTRUMENTS (Narrati
OTHER DEBT INSTRUMENTS (Narrative) (Details) - USD ($) | 3 Months Ended | 12 Months Ended | ||
Mar. 05, 2021 | Jun. 30, 2021 | Dec. 31, 2022 | Dec. 31, 2021 | |
Asset Backed Preferred Instruments [Line Items] | ||||
Percentage of holdings exchanged | 100% | |||
Redemption of member units | $ 20,565,702 | |||
Notes issued for cash | $ 0 | 3,375,000 | ||
Member Units [Member] | ||||
Asset Backed Preferred Instruments [Line Items] | ||||
Number of units redeemed | 3,992,629 | |||
Promissory note exchanged | $ 1,000,000 | |||
Percentage of outstanding units redeemed | 23.40% | |||
Reduction of member units | $ 8,680,786 | |||
Weighted average issue price per unit | $ 21.7 | |||
Reduction in promissory note liability | $ 1,000,000 | |||
Liability for the units at an initial fair value | 21,565,702 | |||
Reduction to accumulated deficit | 11,884,916 | |||
LP Units [Member] | ||||
Asset Backed Preferred Instruments [Line Items] | ||||
Number of units received | 23,500,000 | |||
Payment to redeem units | $ 4,735,700 | $ 16,830,000 | ||
Units redeemed on specified maturity date | 6,670,000 | 6,670,000 | ||
Remaining units to be redeemed on specified maturity date | 16,830,000 | |||
Redemption price per share | $ 0.71 | |||
Fixed rate of return on units | 12% | |||
Fixed rate of return on units in any event of default | 17% | |||
Payment to redeem units, accrued interest | $ 2,515,398 | |||
Market-based rate | 12% | |||
Finance expense | $ 658,047 | 1,857,351 | ||
LP Units [Member] | Redemption before May 1, 2021 [Member] | ||||
Asset Backed Preferred Instruments [Line Items] | ||||
Redemption price per share | $ 0.71 | |||
LP Units [Member] | Redemption before June 1, 2021 [Member] | ||||
Asset Backed Preferred Instruments [Line Items] | ||||
Redemption price per share | 0.8809 | |||
LP Units [Member] | Redemption before September 1, 2021 [Member] | ||||
Asset Backed Preferred Instruments [Line Items] | ||||
Redemption price per share | 1 | |||
LP Units [Member] | Redeemption by March 5, 2024 [Member] | ||||
Asset Backed Preferred Instruments [Line Items] | ||||
Redemption price per share | 1 | |||
LP Units [Member] | Redemption After March 5, 2024 [Member] | ||||
Asset Backed Preferred Instruments [Line Items] | ||||
Redemption price per share | $ 1.35 | |||
Promissory And Convertible Promissory Notes [Member] | ||||
Asset Backed Preferred Instruments [Line Items] | ||||
Finance expense | $ 0 | 300,685 | ||
Notes issued for cash | 0 | 3,375,000 | ||
Promissory notes converted to Origination Member Units | 0 | 3,475,000 | ||
Promissory notes converted to LP units | 0 | 1,000,000 | ||
Repayment of promissory notes for cash | $ 1,755,000 | |||
Units issued from settlement of promissory notes | 353,870 | |||
Notes offset with overhead expenses | $ 270,000 | |||
Convertible promissory notes amount converted to Origination Member Units | $ 0 | $ 2,300,000 | ||
Convertible promissory notes converted to Origination Member Units | 234,216 |
OTHER DEBT INSTRUMENTS - Schedu
OTHER DEBT INSTRUMENTS - Schedule of promissory and convertible promissory notes outstanding (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Short-Term Debt [Line Items] | ||
Issued for cash | $ 0 | $ 3,375,000 |
Repayment of promissory notes | 0 | (2,025,000) |
Promissory Convertible Promissory Notes [Member] | ||
Short-Term Debt [Line Items] | ||
Beginning balance | 0 | 5,425,000 |
Issued for cash | 0 | 3,375,000 |
Converted to Origination Member Unit | 0 | (3,475,000) |
Converted to LP Units | 0 | (1,000,000) |
Repayment of promissory notes | 0 | (2,025,000) |
Converted to Origination Member Units | 0 | (2,300,000) |
Ending balance | $ 0 | $ 0 |
REDEEMABLE NON-CONTROLLING IN_3
REDEEMABLE NON-CONTROLLING INTERESTS (Narrative) (Details) - USD ($) | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||||||||||||
Oct. 07, 2021 | Nov. 30, 2022 | Jul. 31, 2022 | Apr. 30, 2022 | Jan. 31, 2022 | Dec. 31, 2022 | Sep. 30, 2022 | Jun. 30, 2022 | Mar. 31, 2022 | Dec. 31, 2021 | Sep. 30, 2021 | Mar. 31, 2021 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Amount distributed | $ 3,340,254 | $ 6,388,870 | |||||||||||||
Carrying value | $ 107,583,737 | $ 46,552,839 | $ 107,583,737 | 46,552,839 | $ 0 | ||||||||||
Flat Payout Units [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Distributions percentage | 75% | 75% | |||||||||||||
Reduced distributions percentage | 20% | ||||||||||||||
IRR Payout Units [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Distributions percentage | 75% | 75% | |||||||||||||
Invested capital plus annualized return percentage | 15% | ||||||||||||||
Initial investment percentage | 120% | ||||||||||||||
Reduced distributions percentage | 6% | ||||||||||||||
Development Partnership 1 ("DP1") [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Funding percentage | 40% | ||||||||||||||
Redemption value | $ 15,288,594 | $ 0 | 15,288,594 | $ 0 | 15,288,594 | ||||||||||
Carrying value | 0 | 15,288,594 | 0 | 15,288,594 | |||||||||||
Development Partnership 1 ("DP1") [Member] | External Limited Partners [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Funding percentage | 60% | ||||||||||||||
Capital raised | $ 13,140,240 | ||||||||||||||
Amount distributed | 0 | 1,853,127 | |||||||||||||
Development Partnership 1 ("DP1") [Member] | Officers and Directors [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Capital raised | 1,366,709 | ||||||||||||||
Development Partnership 1 ("DP1") [Member] | Investor [Member] | Flat Payout Units [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Cost to investors | 3,252,132 | ||||||||||||||
Development Partnership 1 ("DP1") [Member] | Investor [Member] | IRR Payout Units [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Cost to investors | $ 9,888,108 | ||||||||||||||
Development Partnership 1 ("DP1") [Member] | Class B [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Amount distributed | $ 1,192,893 | ||||||||||||||
Number of units redeemed | 339,372 | ||||||||||||||
Development Partnership 2 ("DP2") [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Funding percentage | 40% | ||||||||||||||
Redemption value | $ 23,511,818 | 0 | 23,511,818 | 0 | 23,511,818 | ||||||||||
Disposition of associated working interest | 84,300 | ||||||||||||||
Carrying value | 0 | $ 25,370,013 | 0 | 25,370,013 | |||||||||||
Development Partnership 2 ("DP2") [Member] | External Limited Partners [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Funding percentage | 60% | ||||||||||||||
Capital raised | $ 20,815,329 | ||||||||||||||
Amount distributed | $ 4,535,743 | ||||||||||||||
Development Partnership 2 ("DP2") [Member] | Officers and Directors [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Capital raised | 1,724,967 | ||||||||||||||
Development Partnership 2 ("DP2") [Member] | Investor [Member] | Flat Payout Units [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Cost to investors | 7,390,362 | ||||||||||||||
Development Partnership 2 ("DP2") [Member] | Investor [Member] | IRR Payout Units [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Cost to investors | $ 13,424,967 | ||||||||||||||
Development Partnership 2 ("DP2") [Member] | Class B Non Voting Units [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Redemption value | $ 3,159,695 | ||||||||||||||
Number of units redeemed | 826,063 | ||||||||||||||
Development Partnership 3 ("DP3") [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Distributions percentage | 40% | 40% | |||||||||||||
Redemption value | $ 30,171,337 | 0 | $ 21,182,826 | 0 | $ 21,182,826 | ||||||||||
Carrying value | 0 | $ 21,182,826 | 0 | $ 21,182,826 | |||||||||||
Development Partnership 3 ("DP3") [Member] | External Limited Partners [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Distributions percentage | 60% | 60% | |||||||||||||
Capital raised | $ 21,182,826 | ||||||||||||||
Amount distributed | 0 | $ 0 | |||||||||||||
Development Partnership 3 ("DP3") [Member] | Officers and Directors [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Capital raised | 4,032,672 | ||||||||||||||
Development Partnership 3 ("DP3") [Member] | Investor [Member] | Flat Payout Units [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Cost to investors | 10,413,322 | 10,413,322 | |||||||||||||
Development Partnership 3 ("DP3") [Member] | Investor [Member] | IRR Payout Units [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Cost to investors | 10,769,504 | 10,769,504 | |||||||||||||
Development Partnership 3 ("DP3") [Member] | Class B Non Voting Units [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Redemption value | $ 5,102,229 | ||||||||||||||
Number of units redeemed | 894,929 | ||||||||||||||
Development Partnership 4 ("DP4") [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Funding percentage | 40% | ||||||||||||||
Redemption value | $ 31,734,290 | 0 | 0 | 0 | 0 | ||||||||||
Disposition of associated working interest | 291,599 | ||||||||||||||
Carrying value | 0 | 0 | 0 | 0 | |||||||||||
Development Partnership 4 ("DP4") [Member] | External Limited Partners [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Funding percentage | 60% | ||||||||||||||
Capital raised | $ 25,225,079 | ||||||||||||||
Amount distributed | 2,747,270 | ||||||||||||||
Development Partnership 4 ("DP4") [Member] | Officers and Directors [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Capital raised | 1,484,256 | ||||||||||||||
Development Partnership 4 ("DP4") [Member] | Investor [Member] | Flat Payout Units [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Cost to investors | 11,638,948 | ||||||||||||||
Development Partnership 4 ("DP4") [Member] | Investor [Member] | IRR Payout Units [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Cost to investors | $ 13,586,130 | ||||||||||||||
Development Partnership 4 ("DP4") [Member] | Class B Non Voting Units [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Redemption value | $ 4,135,797 | ||||||||||||||
Number of units redeemed | 706,975 | ||||||||||||||
Development Partnership Red Dawn 1 ("Red Dawn 1") [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Funding percentage | 40% | ||||||||||||||
Redemption value | $ 38,464,144 | 0 | 0 | 0 | 0 | ||||||||||
Carrying value | 0 | 0 | 0 | 0 | |||||||||||
Development Partnership Red Dawn 1 ("Red Dawn 1") [Member] | External Limited Partners [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Funding percentage | 60% | ||||||||||||||
Capital raised | $ 30,269,097 | ||||||||||||||
Amount distributed | 0 | ||||||||||||||
Development Partnership Red Dawn 1 ("Red Dawn 1") [Member] | Officers and Directors [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Capital raised | 773,836 | ||||||||||||||
Development Partnership Red Dawn 1 ("Red Dawn 1") [Member] | Investor [Member] | Flat Payout Units [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Cost to investors | 16,692,200 | ||||||||||||||
Development Partnership Red Dawn 1 ("Red Dawn 1") [Member] | Investor [Member] | IRR Payout Units [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Cost to investors | $ 13,576,895 | ||||||||||||||
Development Partnership Red Dawn 1 ("Red Dawn 1") [Member] | Class B Non Voting Units [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Redemption value | $ 3,184,247 | ||||||||||||||
Number of units redeemed | 617,103 | ||||||||||||||
Disposition of associated working interest | $ 166,684 | ||||||||||||||
Development Partnership 5 ("DP5") [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Funding percentage | 40% | ||||||||||||||
Redemption value | 36,354,869 | 0 | 36,354,869 | 0 | |||||||||||
Carrying value | 36,354,869 | 0 | 36,354,869 | 0 | |||||||||||
Development Partnership 5 ("DP5") [Member] | External Limited Partners [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Funding percentage | 60% | ||||||||||||||
Capital raised | $ 30,171,345 | ||||||||||||||
Amount distributed | 450,668 | ||||||||||||||
Development Partnership 5 ("DP5") [Member] | Officers and Directors [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Capital raised | 4,308,462 | ||||||||||||||
Development Partnership 5 ("DP5") [Member] | Investor [Member] | Flat Payout Units [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Cost to investors | 19,657,921 | ||||||||||||||
Development Partnership 5 ("DP5") [Member] | Investor [Member] | IRR Payout Units [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Cost to investors | $ 10,513,413 | ||||||||||||||
Development Partnership 6 ("DP6") [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Funding percentage | 40% | ||||||||||||||
Redemption value | 36,595,572 | 0 | 36,595,572 | 0 | |||||||||||
Carrying value | $ 36,595,572 | 0 | 36,595,572 | 0 | |||||||||||
Development Partnership 6 ("DP6") [Member] | External Limited Partners [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Funding percentage | 60% | ||||||||||||||
Capital raised | $ 34,157,892 | ||||||||||||||
Amount distributed | 142,316 | ||||||||||||||
Development Partnership 6 ("DP6") [Member] | Officers and Directors [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Capital raised | 2,215,096 | ||||||||||||||
Development Partnership 6 ("DP6") [Member] | Investor [Member] | Flat Payout Units [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Cost to investors | 21,176,246 | ||||||||||||||
Development Partnership 6 ("DP6") [Member] | Investor [Member] | IRR Payout Units [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Cost to investors | $ 12,981,645 | ||||||||||||||
Development Partnership Red Dawn II ("Red Dawn 2") [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Funding percentage | 40% | ||||||||||||||
Redemption value | $ 34,633,295 | 0 | 34,633,295 | 0 | |||||||||||
Carrying value | $ 34,633,295 | $ 0 | 34,633,295 | $ 0 | |||||||||||
Development Partnership Red Dawn II ("Red Dawn 2") [Member] | External Limited Partners [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Funding percentage | 60% | ||||||||||||||
Capital raised | $ 34,633,295 | ||||||||||||||
Amount distributed | 0 | ||||||||||||||
Development Partnership Red Dawn II ("Red Dawn 2") [Member] | Officers and Directors [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Capital raised | 872,944 | ||||||||||||||
Development Partnership Red Dawn II ("Red Dawn 2") [Member] | Investor [Member] | Flat Payout Units [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Cost to investors | 20,645,955 | 20,645,955 | |||||||||||||
Development Partnership Red Dawn II ("Red Dawn 2") [Member] | Investor [Member] | IRR Payout Units [Member] | |||||||||||||||
Redeemable Noncontrolling Interest [Line Items] | |||||||||||||||
Cost to investors | $ 13,987,340 | $ 13,987,340 |
REDEEMABLE NON-CONTROLLING IN_4
REDEEMABLE NON-CONTROLLING INTERESTS - Schedule of movement in redeemable non-controlling interests (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Temporary Equity Disclosure [Abstract] | ||
Beginning Balance | $ 46,552,839 | $ 0 |
Redeemable non-controlling interests issued | 154,456,707 | 55,138,395 |
Net loss and comprehensive loss attributed | 10,598,514 | 12,851,005 |
Revaluation to redemption value | 23,197,507 | 240,903 |
Distributions | (3,340,254) | (6,388,870) |
Settlement | (123,881,576) | (15,288,594) |
Ending Balance | $ 107,583,737 | $ 46,552,839 |
NON-CONTROLLING INTERESTS (Narr
NON-CONTROLLING INTERESTS (Narrative) (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Noncontrolling Interest [Line Items] | ||
Number of outstanding shares | 2,834,288 | 2,834,288 |
Value of origination units issued | $ 5,499,832 | |
Number of repurchased and cancelled shares | 0 | |
Decrease in non-controlling interest | $ 154,456,707 | 55,138,395 |
Dividends paid | 18,969,442 | |
Net liabilities | $ 252,578,589 | $ 115,581,961 |
Class B Non-Voting Units [Member] | Development Partnership One [Member] | ||
Noncontrolling Interest [Line Items] | ||
Number of origination units issued | 339,372 | |
Value of origination units issued | $ 1,192,893 | |
Class B Non-Voting Units [Member] | Development Partnership Two [Member] | ||
Noncontrolling Interest [Line Items] | ||
Number of origination units issued | 826,063 | |
Value of origination units issued | $ 3,159,695 | |
Class B Non-Voting Units [Member] | Development Partnership Three [Member] | ||
Noncontrolling Interest [Line Items] | ||
Number of origination units issued | 894,929 | |
Value of origination units issued | $ 5,102,229 | |
Class B Non-Voting Units [Member] | Development Partnership Four [Member] | ||
Noncontrolling Interest [Line Items] | ||
Number of origination units issued | 706,975 | |
Value of origination units issued | $ 4,135,797 | |
Class B Non-Voting Units [Member] | Development Partnership Red Dawn One [Member] | ||
Noncontrolling Interest [Line Items] | ||
Number of origination units issued | 617,103 | |
Value of origination units issued | $ 3,184,247 | |
Noncontrolling Interest [Member] | ||
Noncontrolling Interest [Line Items] | ||
Dividends paid | $ 6,552,683 | |
Allocation of opening non-controlling interest | (11,486,999) | |
Noncontrolling Interest [Member] | Class B Non-Voting Units [Member] | ||
Noncontrolling Interest [Line Items] | ||
Number of outstanding shares | 19,552,864 | |
Common Stock [Member] | ||
Noncontrolling Interest [Line Items] | ||
Value of origination units issued | 5,499,832 | |
Allocation of opening non-controlling interest | (18,721,276) | |
Additional Paid-in Capital [Member] | ||
Noncontrolling Interest [Line Items] | ||
Allocation of opening non-controlling interest | 30,208,275 | |
Origination [Member] | ||
Noncontrolling Interest [Line Items] | ||
Net liabilities | $ 35,344,612 | |
Origination [Member] | Class B Non-Voting Units [Member] | ||
Noncontrolling Interest [Line Items] | ||
Proportion of ownership interests held by non-controlling interests | 35.967% | 32.954% |
Dividends paid | $ 6,552,683 | |
Origination [Member] | Class A Units [Member] | ||
Noncontrolling Interest [Line Items] | ||
Number of origination units issued | 2,024,401 | |
Number of repurchased and cancelled shares | 799,600 | |
Origination [Member] | Noncontrolling Interest [Member] | ||
Noncontrolling Interest [Line Items] | ||
Allocation of opening non-controlling interest | $ 11,486,999 | |
Origination [Member] | Common Stock [Member] | ||
Noncontrolling Interest [Line Items] | ||
Allocation of opening non-controlling interest | (18,721,276) | |
Origination [Member] | Additional Paid-in Capital [Member] | ||
Noncontrolling Interest [Line Items] | ||
Allocation of opening non-controlling interest | $ 30,208,275 |
EQUITY (Narrative) (Details)
EQUITY (Narrative) (Details) | 1 Months Ended | 12 Months Ended | |||
Jun. 10, 2022 shares | Jul. 02, 2021 USD ($) $ / shares shares | May 31, 2021 USD ($) $ / shares shares | Dec. 31, 2022 USD ($) $ / shares shares | Dec. 31, 2021 USD ($) a $ / shares shares | |
Class of Stock [Line Items] | |||||
Share purchase price per share | $ / shares | $ 5.5 | ||||
Repurchase of SVS for cancellation | $ 4,324,915 | ||||
Recorded liability | $ 4,670,507 | ||||
Issuance of member units for cash | $ 8,044,700 | ||||
Issuance of member units exchanged for notes | 3,475,000 | ||||
Issuance of member units to contractors | 9,073,228 | ||||
Issuance of member units exchanged for notes | $ 2,300,000 | ||||
SVS Shares [Member] | |||||
Class of Stock [Line Items] | |||||
Repurchase of SVS for cancellation (Shares) | shares | 1,648,783 | 799,600 | |||
Voting rights of common stock | each SVS is entitled to one vote per share | ||||
Percentage of shares available under normal course issuer bid | 5% | ||||
Share purchase price per share | $ / shares | $ 5.41 | ||||
Repurchase of SVS for cancellation | $ 4,324,915 | ||||
Exchange of units for SVS and MVS (Shares) | shares | 195,541 | 1,427,421 | |||
Exchange of units for SVS and MVS | $ 245,368 | $ 1,652,798 | |||
Settlement of RSUs (Shares) | shares | 2,024,401 | ||||
Settlement of RSUs | $ 9,685,555 | ||||
Conversion of MVS to SVS (Shares) | shares | 30,411,950 | ||||
Origination Member Units [Member] | |||||
Class of Stock [Line Items] | |||||
Share purchase price per share | $ / shares | $ 9.82 | $ 9.82 | |||
Exchange of units for SVS and MVS (Shares) | shares | (31,167,204) | ||||
Exchange of units for SVS and MVS | $ (36,088,237) | ||||
Issuance of member units for cash (Shares) | shares | 819,215 | ||||
Issuance of member units for cash | $ 8,044,700 | ||||
Issuance of member units exchanged for notes (Shares) | shares | 353,870 | ||||
Issuance of member units exchanged for notes | $ 3,475,000 | ||||
Issuance of member units to contractors | $ 9,073,228 | ||||
Issuance of member units exchanged for notes (Shares) | shares | 234,216 | 234,216 | |||
Issuance of member units exchanged for notes | $ 2,300,000 | $ 2,300,000 | |||
MVS Shares [Member] | |||||
Class of Stock [Line Items] | |||||
Common stock conversion terms | each MVS is convertible, at the option of the holder, into 100 SVS and entitles the holder to 100 votes per share | ||||
Exchange of units for SVS and MVS (Shares) | shares | (1,955) | 297,398 | |||
Exchange of units for SVS and MVS | $ (245,368) | $ 34,435,439 | |||
Conversion of MVS to SVS (Shares) | shares | (304,120) | ||||
PVS Shares [Member] | |||||
Class of Stock [Line Items] | |||||
Common stock conversion terms | PVS is convertible into one SVS and entitles the holder to 1,000 votes per share | ||||
Eagle Ford Formation [Member] | |||||
Class of Stock [Line Items] | |||||
Area of Land | a | 16,201 | ||||
Eagle Ford Formation [Member] | Origination Member Units [Member] | |||||
Class of Stock [Line Items] | |||||
Share purchase price per share | $ / shares | $ 9.82 | ||||
Number of origination member units issued | $ 2,000,000 | ||||
Number of origination member units issued (Shares) | shares | 203,666 | ||||
Eagle Ford Formation Washington [Member] | |||||
Class of Stock [Line Items] | |||||
Area of Land | a | 630 | ||||
Eagle Ford Formation Washington [Member] | Origination Member Units [Member] | |||||
Class of Stock [Line Items] | |||||
Share purchase price per share | $ / shares | $ 9.82 | ||||
Number of origination member units issued | $ 1,499,995 | ||||
Number of origination member units issued (Shares) | shares | 152,749 | ||||
Officers And Consultants [Member] | Origination Member Units [Member] | |||||
Class of Stock [Line Items] | |||||
Share purchase price per share | $ / shares | $ 9.82 | ||||
Number of origination member units issued (Shares) | shares | 923,954 | ||||
Issuance of member units to contractors | $ 9,073,228 | ||||
Dividends [Member] | |||||
Class of Stock [Line Items] | |||||
Dividends declared and paid | $ 12,416,759 | $ 0 | |||
Dividends [Member] | SVS Shares [Member] | |||||
Class of Stock [Line Items] | |||||
Dividends declared | $ / shares | $ 0.03 | ||||
Dividends declared and paid | $ 12,092,734 | ||||
Dividends [Member] | MVS Shares [Member] | |||||
Class of Stock [Line Items] | |||||
Dividends declared | $ / shares | $ 3 | ||||
Dividends declared and paid | $ 318,284 | ||||
Dividends [Member] | PVS Shares [Member] | |||||
Class of Stock [Line Items] | |||||
Dividends declared | $ / shares | $ 0.03 | ||||
Dividends declared and paid | $ 5,741 |
EQUITY - Schedule of movements
EQUITY - Schedule of movements in common shares (Details) - USD ($) | 1 Months Ended | 12 Months Ended | ||
Jun. 10, 2022 | Jul. 02, 2021 | Dec. 31, 2022 | Dec. 31, 2021 | |
Class of Stock [Line Items] | ||||
Beginning balance | $ 28,687 | |||
Issuance of member units for cash | $ 8,044,700 | |||
Issuance of member units exchanged for notes | 3,475,000 | |||
Issuance of member units for oil and gas properties | 3,499,995 | |||
Issuance of member units to contractors | 9,073,228 | |||
Redemption of member units | (20,565,702) | |||
Issuance of member units exchanged for notes | 2,300,000 | |||
Repurchase of SVS for cancellation | (4,324,915) | |||
Shares issued for cash, net of issuance costs of $247,218 | 5,499,832 | |||
PVS issued for cash | 128,213 | |||
Shares issued on reverse recapitalization | 1,697,865 | |||
Ending balance | 9,000,921 | 28,687 | ||
Shares issued for cash, net of issuance costs | 247,218 | |||
Origination Member Units [Member] | ||||
Class of Stock [Line Items] | ||||
Beginning balance | $ 0 | $ 37,097,376 | ||
Beginning balance (Shares) | 0 | 17,083,501 | ||
Issuance of member units for cash | $ 8,044,700 | |||
Issuance of member units for cash (Shares) | 819,215 | |||
Issuance of member units exchanged for notes | $ 3,475,000 | |||
Issuance of member units exchanged for notes (Shares) | 353,870 | |||
Issuance of member units for oil and gas properties | $ 3,499,995 | |||
Issuance of member units for oil and gas properties (Shares) | 356,415 | |||
Issuance of member units to contractors | $ 9,073,228 | |||
Issuance of member units to contractors (Shares) | 923,954 | |||
Redemption of member units | $ (8,680,786) | |||
Redemption of member units (Shares) | (3,992,629) | |||
Issuance of member units exchanged for notes | $ 2,300,000 | $ 2,300,000 | ||
Issuance of member units exchanged for notes (Shares) | 234,216 | 234,216 | ||
Origination Member Units split 1:3 (Shares) | 31,557,084 | |||
Allocation of opening non-controlling interest | $ (18,721,276) | |||
Allocation of opening non-controlling interest (Shares) | (16,168,422) | |||
Exchange of units for SVS and MVS | $ (36,088,237) | |||
Exchange of units for SVS and MVS (Shares) | (31,167,204) | |||
Ending balance | $ 0 | $ 0 | ||
Ending balance (Shares) | 0 | 0 | ||
SVS Shares [Member] | ||||
Class of Stock [Line Items] | ||||
Beginning balance | $ 41,989,020 | $ 0 | ||
Beginning balance (Shares) | 32,535,731 | 0 | ||
Exchange of units for SVS and MVS | $ 245,368 | $ 1,652,798 | ||
Exchange of units for SVS and MVS (Shares) | 195,541 | 1,427,421 | ||
Settlement of RSUs | $ 9,685,555 | |||
Settlement of RSUs (Shares) | 2,024,401 | |||
Repurchase of SVS for cancellation | $ (4,324,915) | |||
Repurchase of SVS for cancellation (Shares) | (1,648,783) | (799,600) | ||
Shares issued for cash, net of issuance costs of $247,218 | $ 476,978 | |||
Shares issued for cash, net of issuance costs of $247,218 (Shares) | 161,976 | |||
Shares issued on reverse recapitalization | $ 1,697,865 | |||
Shares issued on reverse recapitalization (Shares) | 534,384 | |||
Conversion of MVS to SVS | $ 38,161,379 | |||
Conversion of MVS to SVS (Shares) | 30,411,950 | |||
Ending balance | $ 47,595,028 | $ 41,989,020 | ||
Ending balance (Shares) | 33,956,073 | 32,535,731 | ||
MVS Shares [Member] | ||||
Class of Stock [Line Items] | ||||
Beginning balance | $ 1,296,914 | $ 0 | ||
Beginning balance (Shares) | 10,335 | 0 | ||
Exchange of units for SVS and MVS | $ (245,368) | $ 34,435,439 | ||
Exchange of units for SVS and MVS (Shares) | (1,955) | 297,398 | ||
Shares issued for cash, net of issuance costs of $247,218 | $ 5,022,854 | |||
Shares issued for cash, net of issuance costs of $247,218 (Shares) | 17,057 | |||
Conversion of MVS to SVS | $ (38,161,379) | |||
Conversion of MVS to SVS (Shares) | (304,120) | |||
Ending balance | $ 1,051,546 | $ 1,296,914 | ||
Ending balance (Shares) | 8,380 | 10,335 | ||
PVS Shares [Member] | ||||
Class of Stock [Line Items] | ||||
Beginning balance | $ 128,213 | $ 0 | ||
Beginning balance (Shares) | 15,947 | 0 | ||
PVS issued for cash | $ 128,213 | |||
PVS issued for cash (Shares) | 15,947 | |||
Ending balance | $ 128,213 | $ 128,213 | ||
Ending balance (Shares) | 15,947 | 15,947 | ||
Total Share Capital [Member] | ||||
Class of Stock [Line Items] | ||||
Beginning balance | $ 43,414,147 | $ 37,097,376 | ||
Issuance of member units for cash | 8,044,700 | |||
Issuance of member units exchanged for notes | 3,475,000 | |||
Issuance of member units for oil and gas properties | 3,499,995 | |||
Issuance of member units to contractors | 9,073,228 | |||
Redemption of member units | (8,680,786) | |||
Issuance of member units exchanged for notes | 2,300,000 | |||
Origination Member Units split 1:3 | 0 | |||
Allocation of opening non-controlling interest | (18,721,276) | |||
Exchange of units for SVS and MVS | 0 | |||
Settlement of RSUs | 9,685,555 | |||
Repurchase of SVS for cancellation | (4,324,915) | |||
Shares issued for cash, net of issuance costs of $247,218 | 5,499,832 | |||
PVS issued for cash | 128,213 | |||
Shares issued on reverse recapitalization | 1,697,865 | |||
Conversion of MVS to SVS | 0 | |||
Ending balance | $ 48,774,787 | $ 43,414,147 |
SHARE BASED COMPENSATION - (Nar
SHARE BASED COMPENSATION - (Narrative) (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Stock based compensation | $ 10,197,720 | $ 5,405,548 |
Share based compensation by share based payment arrangement weighted average grant date fair value per share | $ 0 | $ 2.21 |
Weighted average remaining contractual term (years) | 8 years 11 months 12 days | |
Minimum [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Stock options and RSUs granted vesting period | 0 years | |
Maximum [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Stock options and RSUs granted vesting period | 3 years | |
Stock options [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Stock based compensation | $ 2,046,166 | $ 2,858,702 |
Share based compensation by share based payment arrangement options unrecognized compensation | $ 1,293,484 | |
Weighted average remaining contractual term (years) | 1 year 4 months 24 days | |
RSUs [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Stock based compensation | $ 7,415,252 | $ 2,488,955 |
Unrecognized compensation expense related to non-vested RSU's and DSU's | $ 252,724 | |
Share based compensation by share based payment arrangement weighted average grant date fair value per share | $ 5.75 | $ 3.56 |
Share based compensation arrangement by share based payment award, option, nonvested, weighted average exercise price | $ 11,609,135 | $ 0 |
Share based compensation by share based payment arrangement weighted average period of recognition | 8 months 1 day | |
Unrecognized compensation cost, weighted average period | 8 months 1 day | |
DSUs [Member] | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Stock based compensation | $ 736,302 | $ 51,891 |
Unrecognized compensation expense related to non-vested RSU's and DSU's | $ 211,800 | |
Share based compensation by share based payment arrangement weighted average grant date fair value per share | $ 3.56 | |
Share based compensation by share based payment arrangement weighted average grant date fair value per share | $ 5.75 | |
Share based compensation arrangement by share based payment award, option, nonvested, weighted average exercise price | $ 490,002 | $ 0 |
SHARE BASED COMPENSATION - Summ
SHARE BASED COMPENSATION - Summary of share-based compensation arrangements by share-based payment award (Details) | 12 Months Ended |
Dec. 31, 2022 USD ($) $ / shares shares | |
Share-based Payment Arrangement [Abstract] | |
Number of options Outstanding | shares | 2,834,288 |
Number of options Granted | shares | 0 |
Number of options Forfeited | shares | 0 |
Number of options Expired | shares | 0 |
Number of options Outstanding at End | shares | 2,834,288 |
Number of options Exercisable | shares | 1,803,985 |
Weighted- average exercise price,Outstanding | $ 3.56 |
Weighted- average exercise price Granted | 0 |
Weighted- average exercise price Exercised | 0 |
Weighted- average exercise price Forfeited | 0 |
Weighted- average exercise price Expired | 0 |
Weighted- average exercise price Outstanding at End | 3.56 |
Weighted- average exercise price Exercisable | $ 3.56 |
Weighted average remaining contractual term (years) | 8 years 11 months 12 days |
Weighted average remaining contractual term (years) Exercisable | 8 years 11 months 12 days |
Aggregate intrinsic value, Outstanding at End | $ | $ 4,166,403 |
Aggregate intrinsic value Exercisable | $ | $ 2,651,858 |
SHARE BASED COMPENSATION - Su_2
SHARE BASED COMPENSATION - Summary of weighted average assumptions used to determine the fair value of the options granted (Details) - $ / shares | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Share-based Payment Arrangement [Abstract] | ||
Fair value of options granted | $ 0 | $ 2.21 |
Expected life (years) | 5 years 6 months 18 days | 5 years 8 months 19 days |
Risk-free interest rate | 1.27% | 1.27% |
Average forfeiture rate | 0% | 0% |
Expected dividend yield | 0% | 0% |
Expected volatility | 71.62% | 71.62% |
SHARE BASED COMPENSATION - Su_3
SHARE BASED COMPENSATION - Summary of share units (Detail) | 12 Months Ended | ||
Dec. 31, 2022 USD ($) $ / shares | Dec. 31, 2022 USD ($) $ / shares shares | Dec. 31, 2021 $ / shares shares | |
RSUs [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Nonvested, January 1, 2022 | 892,580 | ||
Granted | 1,214,321 | ||
Forfeited | 0 | ||
Vested | (2,024,401) | ||
Nonvested, December 31, 2022 | 82,500 | 892,580 | |
Weighted average grant date fair value per share, Unvested as of December 31, 2022 | $ / shares | $ 3.56 | ||
Weighted average grant date fair value per share, Granted | $ / shares | 5.75 | $ 3.56 | |
Weighted average grant date fair value per share, Vested | $ / shares | 4.78 | ||
Weighted average grant date fair value per share, Forfeited | $ / shares | 0 | ||
Weighted average grant date fair value per share, Unvested as of December 31,2022 | $ / shares | $ 5.75 | $ 3.56 | |
Weighted average remaining contractual term (years) | 8 months 1 day | ||
Aggregate Intrinsic Value | $ | $ 414,975 | $ 414,975 | |
DSUs [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Nonvested, January 1, 2022 | 137,641 | ||
Granted | 88,694 | ||
Forfeited | 0 | ||
Vested | (137,641) | ||
Settled | 0 | ||
Nonvested, December 31, 2022 | 226,335 | 137,641 | |
Weighted average grant date fair value per share, Unvested as of December 31, 2022 | $ / shares | $ 3.56 | ||
Weighted average grant date fair value per share, Granted | $ / shares | 5.75 | ||
Weighted average grant date fair value per share, Vested | $ / shares | 3.56 | ||
Weighted average grant date fair value per share, Forfeited | $ / shares | 0 | ||
Weighted average grant date fair value per share, Unvested as of December 31,2022 | $ / shares | $ 3.56 | ||
Weighted average grant date fair value per share, Settled | (per share) | $ 0 | $ 4.42 | |
Weighted average remaining contractual term (years) | 5 months 1 day | ||
Aggregate Intrinsic Value | $ | $ 1,138,465 | $ 1,138,465 | |
Aggregate Intrinsic Value | $ | $ 692,334 |
EARNINGS PER SHARE - Schedule o
EARNINGS PER SHARE - Schedule of basic earnings per share (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Earnings Per Share [Abstract] | ||
Net income (loss) attributable to common shareholders | $ 7,428,135 | $ (32,344,428) |
Weighted average number of common shares outstanding (as-converted) | 34,453,696 | 42,596,264 |
Income (loss) per share - basic | $ 0.22 | $ (0.76) |
EARNINGS PER SHARE - Schedule_2
EARNINGS PER SHARE - Schedule of diluted earnings per share (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Earnings Per Share [Abstract] | ||
Net income (loss) attributable to common shareholders | $ 7,428,135 | $ (32,344,428) |
Plus: Effect of dilutive items | 3,189,196 | 0 |
Net Income (Loss) Attributable to Parent, Diluted | $ 10,617,331 | $ (32,344,424) |
Weighted average number of common shares outstanding (as-converted) | 34,453,696 | 42,596,264 |
Plus: Effect for conversion of Origination Class B into SVS | 18,203,421 | 0 |
Plus: Effect for dilutive share-based compensation awards | 929,210 | 0 |
Weighted average number of shares outstanding, Diluted | 53,586,327 | 42,596,264 |
Income (loss) per share - diluted | $ 0.2 | $ (0.76) |
REVENUE FROM CONTRACTS WITH C_3
REVENUE FROM CONTRACTS WITH CUSTOMERS - Schedule of revenue from contracts with customers (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Revenue | $ 195,648,957 | $ 70,796,790 |
Crude oil [Member] | ||
Revenue | 97,438,790 | 50,868,794 |
Natural gas [Member] | ||
Revenue | 77,966,801 | 10,286,929 |
Natural gas liquids [Member] | ||
Revenue | $ 20,243,366 | $ 9,641,067 |
INCOME TAX (Narrative) (Details
INCOME TAX (Narrative) (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Income Tax Disclosure [Abstract] | ||
Effective income tax rates (benefits) | (4.50%) | 5.90% |
Income tax expense (benefit) | $ (1,928,319) | $ 1,928,319 |
U.S. federal income tax rate | 21% | 21% |
Deferred tax assets, valuation allowance | $ 20,219,335 | $ 334,198 |
INCOME TAX - Schedule of compon
INCOME TAX - Schedule of components of income tax expense (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Current income tax expense: | ||
United States federal | $ 0 | $ 0 |
State | 0 | 0 |
Total current income tax expense | 0 | 0 |
Deferred income tax expense (benefit): | ||
United States federal | (1,928,319) | 1,928,319 |
State | 0 | 0 |
Total deferred income tax expense (benefit) | (1,928,319) | 1,928,319 |
Total income tax expense (benefit) | $ (1,928,319) | $ 1,928,319 |
INCOME TAX - Schedule of income
INCOME TAX - Schedule of income tax rate reconciliation (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Income Tax Disclosure [Abstract] | ||
Net income (loss) before taxes | $ 42,485,033 | $ (30,654,438) |
U. S. federal statutory income tax rate | 21% | 21% |
Expected federal taxes at statutory rate | $ 8,921,857 | $ (6,437,432) |
Increase (decrease) resulting from: | ||
Canadian income tax | 0 | 0 |
Non-controlling interests | (7,766,896) | 54,250 |
Income (loss) not subject to corporate income taxes | (1,154,961) | 6,383,182 |
Change in tax status | 0 | 1,928,319 |
Change in valuation allowance - federal | (1,928,319) | 0 |
Income tax expense (recovery) | $ (1,928,319) | $ 1,928,319 |
INCOME TAX - Schedule of deferr
INCOME TAX - Schedule of deferred tax assets and liabilities (Details) - USD ($) | Dec. 31, 2022 | Dec. 31, 2021 |
Deferred tax liabilities | ||
Investment in Origination | $ 0 | $ (3,437,344) |
Total deferred tax liabilities | 0 | (3,437,344) |
Deferred tax assets | ||
Investment in Origination | 10,518,502 | 1,509,025 |
Canadian federal tax loss carryforwards | 339,501 | 334,198 |
US federal tax loss carryforwards | 9,361,332 | 0 |
Total deferred tax assets, gross | 20,219,335 | 1,843,223 |
Less: Valuation allowance | (20,219,335) | (334,198) |
Total deferred tax assets, net | 0 | 1,509,025 |
Net deferred tax assets (liabilities) | 0 | (1,928,319) |
Presented As Follows [Abstract] | ||
Total deferred tax assets | 0 | 1,509,025 |
Net deferred tax liabilities | 0 | (1,928,319) |
Net deferred tax assets (liabilities) | $ 0 | $ (1,928,319) |
RELATED PARTY TRANSACTIONS (Nar
RELATED PARTY TRANSACTIONS (Narrative) (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |
Jun. 30, 2021 | Dec. 31, 2022 | Dec. 31, 2021 | |
Related Party Transaction [Line Items] | |||
Recognized general and administrative expenses | $ 26,090,160 | $ 25,021,117 | |
Accounts receivable, net | 26,466,208 | 18,797,635 | |
Due from common equity holders, officers and directors | $ 143,572 | 120,501 | |
Management Services Agreement [Member] | |||
Related Party Transaction [Line Items] | |||
Description of transactions with related party | The Company was obligated to pay for these services on a quarterly basis amounting to the lesser of; i) $2.00 per produced barrel of oil equivalent (converting natural gas to BOE equivalent of 6:1), and ii) 0.375% of measured assets as defined in the credit agreement. | ||
Recognized general and administrative expenses | 287,126 | ||
Letter of Credit [Member] | |||
Related Party Transaction [Line Items] | |||
Annual fee received on a quarterly basis | $ 1,000,000 | ||
Recognized general and administrative expenses | $ 916,667 | 416,666 | |
Accounts receivable, net | $ 0 | $ 120,501 |
FAIR VALUE MEASUREMENTS - Sched
FAIR VALUE MEASUREMENTS - Schedule of fair value on recurring basis (Details) - Fair value on recurring basis [Member] - USD ($) | Dec. 31, 2022 | Dec. 31, 2021 |
Level 1 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total | $ 0 | $ 0 |
Level 1 [Member] | Commodity derivatives [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total | 0 | 0 |
Level 1 [Member] | Interest rate derivatives [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total | 0 | 0 |
Level 2 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total | 3,077,079 | (20,381,180) |
Level 2 [Member] | Commodity derivatives [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total | 3,077,079 | (20,424,601) |
Level 2 [Member] | Interest rate derivatives [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total | 0 | 43,421 |
Level 3 [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total | 0 | 0 |
Level 3 [Member] | Commodity derivatives [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total | 0 | 0 |
Level 3 [Member] | Interest rate derivatives [Member] | ||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||
Total | $ 0 | $ 0 |
RISK MANAGEMENT AND FINANCIAL_3
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Narrative) (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Derivatives, Fair Value [Line Items] | ||
Working capital | $ (162,980,101) | |
Oil and gas revenue benchmark [Member] | Customer Concentration Risk [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Concentration Risk, Percentage | 91.25% | |
Oil and gas revenue benchmark [Member] | Customer Concentration Risk [Member] | Customer One [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Concentration Risk, Percentage | 49.80% | |
Oil and gas revenue benchmark [Member] | Customer Concentration Risk [Member] | Customer Two [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Concentration Risk, Percentage | 31.40% | |
Oil and gas revenue benchmark [Member] | Customer Concentration Risk [Member] | Customer Three [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Concentration Risk, Percentage | 10% | |
Interest Rate Swap [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Notional amount | $ 0 | $ 25,237,409 |
RISK MANAGEMENT AND FINANCIAL_4
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Schedule of derivative instruments, gain (loss) (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Derivative Instruments, Gain (Loss) [Line Items] | ||
Unrealized gain (loss) | $ 26,246,352 | $ (15,859,796) |
Total gain (loss), net | (10,023,495) | (33,525,453) |
Gain / (loss) on derivative instruments [Member] | Commodity derivative contracts [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Unrealized gain (loss) | 26,246,351 | (15,903,217) |
Realized gain (loss) | (36,269,846) | (17,622,236) |
Total gain (loss), net | (10,023,495) | (33,525,453) |
Finance Expense [Member] | Interest rate derivative contracts [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Unrealized gain (loss) | 0 | 43,421 |
Realized gain (loss) | 623,579 | 0 |
Total gain (loss), net | $ 623,579 | $ 43,421 |
RISK MANAGEMENT AND FINANCIAL_5
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Schedule of derivative instruments (Details) | 12 Months Ended |
Dec. 31, 2022 Bbl_Per_Unit bbl Gal_Per_Unit gal MMBtu_Per_Unit MMBbls | |
Crude oil [Member] | WTI NYMEX - Swaps [Member] | |
Derivative [Line Items] | |
Volume | bbl | 958,340 |
Crude oil [Member] | WTI NYMEX - Swaps [Member] | 2023 [Member] | |
Derivative [Line Items] | |
Volume | bbl | 542,548 |
Weighted Average Price | Bbl_Per_Unit | 69.79 |
Crude oil [Member] | WTI NYMEX - Swaps [Member] | 2024 [Member] | |
Derivative [Line Items] | |
Volume | bbl | 286,150 |
Weighted Average Price | Bbl_Per_Unit | 65.97 |
Crude oil [Member] | WTI NYMEX - Swaps [Member] | 2025 [Member] | |
Derivative [Line Items] | |
Volume | bbl | 129,642 |
Weighted Average Price | Bbl_Per_Unit | 58.98 |
Natural Gas And Natural Gas Liquids [Member] | Natural Gas NYMEX - Swaps [Member] | |
Derivative [Line Items] | |
Volume | MMBbls | 9,244,960 |
Natural Gas And Natural Gas Liquids [Member] | Natural Gas NYMEX - Swaps [Member] | 2023 [Member] | |
Derivative [Line Items] | |
Volume | MMBbls | 5,306,902 |
Weighted Average Price | MMBtu_Per_Unit | 5.43 |
Natural Gas And Natural Gas Liquids [Member] | Natural Gas NYMEX - Swaps [Member] | 2024 [Member] | |
Derivative [Line Items] | |
Volume | MMBbls | 2,606,643 |
Weighted Average Price | MMBtu_Per_Unit | 5.43 |
Natural Gas And Natural Gas Liquids [Member] | Natural Gas NYMEX - Swaps [Member] | 2025 [Member] | |
Derivative [Line Items] | |
Volume | MMBbls | 1,331,415 |
Weighted Average Price | MMBtu_Per_Unit | 5.33 |
Natural Gas And Natural Gas Liquids [Member] | Natural Gas NYMEX vs. Houston Ship Channel[Member] | |
Derivative [Line Items] | |
Volume | MMBbls | 967,311 |
Natural Gas And Natural Gas Liquids [Member] | Natural Gas NYMEX vs. Houston Ship Channel[Member] | 2023 [Member] | |
Derivative [Line Items] | |
Volume | MMBbls | 465,214 |
Weighted Average Price | MMBtu_Per_Unit | (0.07) |
Natural Gas And Natural Gas Liquids [Member] | Natural Gas NYMEX vs. Houston Ship Channel[Member] | 2024 [Member] | |
Derivative [Line Items] | |
Volume | MMBbls | 325,088 |
Weighted Average Price | MMBtu_Per_Unit | (0.07) |
Natural Gas And Natural Gas Liquids [Member] | Natural Gas NYMEX vs. Houston Ship Channel[Member] | 2025 [Member] | |
Derivative [Line Items] | |
Volume | MMBbls | 177,009 |
Weighted Average Price | MMBtu_Per_Unit | (0.07) |
Natural Gas And Natural Gas Liquids [Member] | Mont Belvieu Natural Gas - Swaps [Member] | |
Derivative [Line Items] | |
Volume | 2,744,210 |
Natural Gas And Natural Gas Liquids [Member] | Mont Belvieu Natural Gas - Swaps [Member] | 2023 [Member] | |
Derivative [Line Items] | |
Volume | 1,560,711 |
Weighted Average Price | Gal_Per_Unit | 1.3 |
Natural Gas And Natural Gas Liquids [Member] | Mont Belvieu Natural Gas - Swaps [Member] | 2024 [Member] | |
Derivative [Line Items] | |
Volume | 857,027 |
Weighted Average Price | Gal_Per_Unit | 1.57 |
Natural Gas And Natural Gas Liquids [Member] | Mont Belvieu Natural Gas - Swaps [Member] | 2025 [Member] | |
Derivative [Line Items] | |
Volume | 326,472 |
Weighted Average Price | Gal_Per_Unit | 1.65 |
Natural Gas And Natural Gas Liquids [Member] | Mont Belvieu Ethane - Swaps [Member] | |
Derivative [Line Items] | |
Volume | 10,231,439 |
Natural Gas And Natural Gas Liquids [Member] | Mont Belvieu Ethane - Swaps [Member] | 2023 [Member] | |
Derivative [Line Items] | |
Volume | 5,818,913 |
Weighted Average Price | Gal_Per_Unit | 0.3 |
Natural Gas And Natural Gas Liquids [Member] | Mont Belvieu Ethane - Swaps [Member] | 2024 [Member] | |
Derivative [Line Items] | |
Volume | 3,195,317 |
Weighted Average Price | Gal_Per_Unit | 0.34 |
Natural Gas And Natural Gas Liquids [Member] | Mont Belvieu Ethane - Swaps [Member] | 2025 [Member] | |
Derivative [Line Items] | |
Volume | 1,217,209 |
Weighted Average Price | Gal_Per_Unit | 0.36 |
Natural Gas And Natural Gas Liquids [Member] | Mont Belvieu Propane - Swaps [Member] | |
Derivative [Line Items] | |
Volume | 6,095,511 |
Natural Gas And Natural Gas Liquids [Member] | Mont Belvieu Propane - Swaps [Member] | 2023 [Member] | |
Derivative [Line Items] | |
Volume | 3,466,691 |
Weighted Average Price | Gal_Per_Unit | 0.8 |
Natural Gas And Natural Gas Liquids [Member] | Mont Belvieu Propane - Swaps [Member] | 2024 [Member] | |
Derivative [Line Items] | |
Volume | 1,903,650 |
Weighted Average Price | Gal_Per_Unit | 0.92 |
Natural Gas And Natural Gas Liquids [Member] | Mont Belvieu Propane - Swaps [Member] | 2025 [Member] | |
Derivative [Line Items] | |
Volume | 725,170 |
Weighted Average Price | Gal_Per_Unit | 0.95 |
Natural Gas And Natural Gas Liquids [Member] | Mont Belvieu Isobutane - Swaps [Member] | |
Derivative [Line Items] | |
Volume | 1,184,194 |
Natural Gas And Natural Gas Liquids [Member] | Mont Belvieu Isobutane - Swaps [Member] | 2023 [Member] | |
Derivative [Line Items] | |
Volume | 673,486 |
Weighted Average Price | Gal_Per_Unit | 0.89 |
Natural Gas And Natural Gas Liquids [Member] | Mont Belvieu Isobutane - Swaps [Member] | 2024 [Member] | |
Derivative [Line Items] | |
Volume | 369,828 |
Weighted Average Price | Gal_Per_Unit | 1.06 |
Natural Gas And Natural Gas Liquids [Member] | Mont Belvieu Isobutane - Swaps [Member] | 2025 [Member] | |
Derivative [Line Items] | |
Volume | 140,880 |
Weighted Average Price | Gal_Per_Unit | 1.1 |
Natural Gas And Natural Gas Liquids [Member] | Mont Belvieu N. Butane - Swaps [Member] | |
Derivative [Line Items] | |
Volume | 2,508,157 |
Natural Gas And Natural Gas Liquids [Member] | Mont Belvieu N. Butane - Swaps [Member] | 2023 [Member] | |
Derivative [Line Items] | |
Volume | 1,426,461 |
Weighted Average Price | Gal_Per_Unit | 0.87 |
Natural Gas And Natural Gas Liquids [Member] | Mont Belvieu N. Butane - Swaps [Member] | 2024 [Member] | |
Derivative [Line Items] | |
Volume | 783,308 |
Weighted Average Price | Gal_Per_Unit | 1.04 |
Natural Gas And Natural Gas Liquids [Member] | Mont Belvieu N. Butane - Swaps [Member] | 2025 [Member] | |
Derivative [Line Items] | |
Volume | 298,388 |
Weighted Average Price | Gal_Per_Unit | 1.08 |
RISK MANAGEMENT AND FINANCIAL_6
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Schedule of derivative assets and liabilities (Details) - USD ($) | Dec. 31, 2022 | Dec. 31, 2021 |
Derivative Assets: | ||
Current assets | $ 2,019,600 | $ 0 |
Noncurrent assets | 1,057,479 | 0 |
Total Derivative Assets | 3,077,079 | 0 |
Derivative Liabilities: | ||
Current liabilities | 0 | 6,479,508 |
Noncurrent liabilities | 0 | 13,901,672 |
Total Derivative Liabilities | $ 0 | $ 20,381,180 |
COMMITMENTS AND CONTINGENCIES (
COMMITMENTS AND CONTINGENCIES (Narrative) (Details) | 12 Months Ended |
Dec. 31, 2022 USD ($) | |
Commitments and Contingencies Disclosure [Abstract] | |
Transportation agreement, approximate daily transportation fees | $ 11,000 |
FINANCE AND INTEREST EXPENSE -
FINANCE AND INTEREST EXPENSE - Schedule of finance and interest expense (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Finance and Interest Expense [Abstract] | ||
Interest expense on long term debt | $ 11,389,415 | $ 3,612,929 |
Interest expense for Corporate Credit Facility | 1,736,868 | 0 |
Interest on asset back preferred | 658,047 | 1,857,351 |
Interest on promissory notes | 0 | 300,685 |
ARO accretion | 43,756 | 24,209 |
Interest rate derivative loss (gain) | (623,579) | (43,421) |
Interest income | (14,966) | 0 |
Bank fees and other | 282,548 | 0 |
Total finance and interest expense | $ 13,428,333 | $ 5,727,544 |
GENERAL AND ADMINISTRATIVE EX_3
GENERAL AND ADMINISTRATIVE EXPENSE - Schedule of general and administrative expense (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
General and Administrative Expense [Abstract] | ||
Stock based compensation expense | $ 10,197,720 | $ 14,478,776 |
Employee salaries and benefits | 10,193,583 | 6,483,720 |
Professional, legal, and advisory | 4,672,072 | 3,629,525 |
Travel and accommodation | 278,653 | 174,769 |
Software | 462,754 | 344,577 |
Operating lease and variable lease costs | 215,487 | 75,170 |
Office and administration | 986,558 | 251,246 |
Recoveries | (916,667) | (416,666) |
Total general and administrative expense | $ 26,090,160 | $ 25,021,117 |
SUPPLEMENTAL CASH FLOW DISCLO_3
SUPPLEMENTAL CASH FLOW DISCLOSURES - Schedule of supplemental cash flow information (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Supplemental Cash Flow Information [Abstract] | ||
Cash paid for interest | $ 7,903,446 | $ 2,278,570 |
Cash paid for income taxes | 0 | 0 |
Non-Cash Investing Activities | ||
Property, plant and equipment non-cash accruals | 43,487,444 | 15,752,315 |
Capitalized asset retirement obligations | 110,480 | 217,471 |
Acquisition of oil and natural gas properties via share issuance | 0 | 3,499,995 |
Non-cash investing activities | 43,597,924 | 19,469,781 |
Non-Cash Financing Activities | ||
Redemption of Redeemable NCI via issuance of Redeemable NCI | 100,727,774 | 14,095,702 |
Redemption of Redeemable NCI via issuance of Origination Member Units | 15,581,968 | 1,192,893 |
Redemption Of Redeemable Nci Via Oil And Gas Property Disposition | 542,584 | 0 |
Redemption of promissory notes vis equity issuance | 0 | 6,775,000 |
Non-Cash Financing Activities | 116,852,326 | 22,063,595 |
Changes in Operating Assets and Liabilities | ||
Accounts receivable, net | (7,668,573) | (12,675,672) |
Prepaid expenses | (540,223) | (510,063) |
Accounts payable and accrued liabilities | 4,699,365 | 19,986,246 |
Asset backed preferred instrument accrued interest | 0 | 1,857,351 |
Asset retirement obligation settlements | (127,862) | 0 |
Operating lease asset | (235,564) | 0 |
Operating leases liability | 103,302 | 9,542 |
Changes in operating assets and liabilities | $ 3,769,555 | $ 8,667,404 |
SUBSEQUENT EVENTS (Narrative) (
SUBSEQUENT EVENTS (Narrative) (Details) - Subsequent Events [Member] - USD ($) | 1 Months Ended | ||
Jan. 20, 2023 | Feb. 01, 2023 | Jan. 03, 2023 | |
Development Partnership 7 [Member] | |||
Subsequent Event [Line Items] | |||
Redeemable non-controlling interests, redemption value | $ 36,354,869 | ||
Funding percentage | 40% | ||
Development Partnership 7 [Member] | Class B [Member] | |||
Subsequent Event [Line Items] | |||
Redeemable non-controlling interests, redemption value | $ 2,505,631 | ||
Number of units redeemed | 499,794 | ||
Development Partnership 7 [Member] | External Limited Partners [Member] | |||
Subsequent Event [Line Items] | |||
Funding percentage | 60% | ||
Capital raised | $ 34,262,236 | ||
Development Partnership 7 [Member] | Officers and Directors [Member] | |||
Subsequent Event [Line Items] | |||
Capital raised | 4,946,981 | ||
Development Partnership 7 [Member] | Flat Payout Units [Member] | |||
Subsequent Event [Line Items] | |||
Cost to investors | 20,478,084 | ||
Development Partnership 7 [Member] | IRR Payout Units [Member] | |||
Subsequent Event [Line Items] | |||
Cost to investors | $ 13,784,152 | ||
SVS [Member] | |||
Subsequent Event [Line Items] | |||
Dividends declared | $ 0.0315 | $ 0.0315 | |
PVS [Member] | |||
Subsequent Event [Line Items] | |||
Dividends declared | 0.0315 | 0.0315 | |
MVS [Member] | |||
Subsequent Event [Line Items] | |||
Dividends declared | $ 3.15 | $ 3.15 |
SUPPLEMENTAL OIL AND GAS INFO_3
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) - Schedule of costs incurred in crude oil and natural gas acquisition, exploration and development activities (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Extractive Industries [Abstract] | ||
Unevaluated property acquisition | $ 2,244,517 | $ 6,200,745 |
Development | 248,185,340 | 68,323,942 |
Exploration costs | 5,179,046 | 1,406,101 |
Total | $ 255,608,903 | $ 75,930,788 |
SUPPLEMENTAL OIL AND GAS INFO_4
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) - Schedule of proved developed and undeveloped oil and gas reserve quantities (Details) - bbl | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Reserve Quantities [Line Items] | |||
Total proved reserves, beginning balance | 11,658 | 14,283 | |
Revisions of previous estimates, and other | 7,705 | 5,093 | |
Extensions, discoveries and other additions | 19,775 | ||
Improved recovery | 4,127 | 3,969 | |
Production | (3,838) | (1,501) | |
Proved Developed Reserves | 18,682 | 4,423 | 5,079 |
Proved Undeveloped Reserves | 5,335 | 7,235 | 9,204 |
Total proved reserves, ending balance | 24,017 | 11,658 | |
Oils (Mbbl) [Member] | |||
Reserve Quantities [Line Items] | |||
Total proved reserves, beginning balance | 3,735 | 5,209 | |
Revisions of previous estimates, and other | 1,850 | (2,445) | |
Extensions, discoveries and other additions | 2,281 | ||
Improved recovery | 1,111 | 1,715 | |
Production | (1,030) | (743) | |
Proved Developed Reserves | 3,973 | 2,137 | 2,275 |
Proved Undeveloped Reserves | 274 | 1,598 | 2,934 |
Total proved reserves, ending balance | 4,247 | 3,735 | |
Natural Gas (MMcf) [Member] | |||
Reserve Quantities [Line Items] | |||
Total proved reserves, beginning balance | 32,724 | 23,505 | |
Revisions of previous estimates, and other | 27,505 | 5,415 | |
Extensions, discoveries and other additions | 93,381 | ||
Improved recovery | 14,069 | 6,201 | |
Production | (13,317) | (2,398) | |
Proved Developed Reserves | 70,480 | 7,468 | 6,672 |
Proved Undeveloped Reserves | 28,872 | 25,256 | 16,833 |
Total proved reserves, ending balance | 99,352 | 32,724 | |
NGLs [Member] | |||
Reserve Quantities [Line Items] | |||
Total proved reserves, beginning balance | 2,469 | 5,156 | |
Revisions of previous estimates, and other | 1,271 | 3,550 | |
Extensions, discoveries and other additions | 1,930 | ||
Improved recovery | 671 | 1,220 | |
Production | (588) | (358) | |
Proved Developed Reserves | 2,962 | 1,041 | 1,692 |
Proved Undeveloped Reserves | 249 | 1,428 | 3,464 |
Total proved reserves, ending balance | 3,211 | 2,469 |
SUPPLEMENTAL OIL AND GAS INFO_5
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) - Schedule of standardized measure of discounted future net cash flows relating to proved crude oil and natural gas reserves (Details) - USD ($) | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 |
Extractive Industries [Abstract] | |||
Future cash inflows | $ 1,092,307,120 | $ 247,313,824 | |
Future production costs | (136,423,094) | (53,266,494) | |
Future development and abandonment costs | (75,501,920) | (3,124,700) | |
Future income tax expense | (98,092,314) | (24,496,630) | |
Future net cash inflows | 782,289,792 | 166,426,000 | |
10% annual discount for estimated timing of cash flows | (303,833,120) | (55,888,400) | |
Standardized measure of discounted future net cash flows | $ 478,456,672 | $ 110,537,600 | $ 82,028,564 |
SUPPLEMENTAL OIL AND GAS INFO_6
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) - Schedule of oil and gas, average sale price and production cost (Details) - $ / Bbl | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Oils (Mbbl) [Member] | ||
Reserve Quantities [Line Items] | ||
Sales price per unit | 94.49 | 66.55 |
Natural Gas (MMcf) [Member] | ||
Reserve Quantities [Line Items] | ||
Sales price per unit | 6.25 | 3.64 |
NGLs [Member] | ||
Reserve Quantities [Line Items] | ||
Sales price per unit | 32.62 | 27.29 |
SUPPLEMENTAL OIL AND GAS INFO_7
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) - Schedule of changes in the standardized measure of discounted future net cash flows (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Extractive Industries [Abstract] | ||
Beginning of period | $ 110,537,600 | $ 82,028,564 |
Sales of oil and natural gas produced, net of production costs | (81,065,058) | (26,623,743) |
Extensions, discoveries and other additions | 200,494,177 | (12,803,556) |
Previously estimated development cost incurred during the period | 3,124,700 | (14,038,000) |
Net change of prices and production costs | 139,967,308 | 114,050,543 |
Change in future development costs | (57,466,319) | 48,932,984 |
Revisions of quantity and timing estimates | 225,544,516 | (120,961,889) |
Accretion of discount | (760,264) | 18,575,522 |
Change in future development and abandonment costs | 55,419,410 | 8,768,285 |
Other | (251,178) | (15,467,110) |
End of period | $ 478,456,672 | $ 110,537,600 |