Petrolia Energy (BBLSQ) 10-K 12 May 23 2022 FY Annual report Financial data

Cover

Cover - USD ($)	12 Months Ended
	Dec. 31, 2022	May 12, 2023	Jun. 30, 2022
Cover [Abstract]
Document Type	10-K
Amendment Flag	false
Document Annual Report	true
Document Transition Report	false
Document Period End Date	Dec. 31, 2022
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2022
Current Fiscal Year End Date	--12-31
Entity File Number	000-52690
Entity Registrant Name	PETROLIA ENERGY CORPORATION
Entity Central Index Key	0001368637
Entity Tax Identification Number	86-1061005
Entity Incorporation, State or Country Code	TX
Entity Address, Address Line One	710 N. Post Oak Road
Entity Address, Address Line Two	Suite 400
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77024
City Area Code	832
Local Phone Number	723-1266
Title of 12(g) Security	Common Stock, $0.001 Par Value Per Share
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	true
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float			$ 257,964
Entity Common Stock, Shares Outstanding		176,988,322
Documents Incorporated by Reference	None
ICFR Auditor Attestation Flag	false
Auditor Firm ID	2738
Auditor Name	M&K CPAS, PLLC
Auditor Location	Houston, TX

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($)	Dec. 31, 2022		Dec. 31, 2021
Current assets
Cash	$ 1,425,335		$ 14,058
Accounts receivable	290		5,942
Other current assets	5,641		5,641
Total current assets	1,431,266		25,641
Oil and gas, on the basis of full cost accounting:
Evaluated Properties	6,638,037		6,797,025
Furniture, equipment & software	155,293		155,293
Less accumulated depreciation & depletion	(807,047)		(603,135)
Net property and equipment	5,986,283		6,349,183
Other assets
Operating Lease Right-of-Use Asset	23,086		12,821
Other assets	1,333,478		1,450,841
Total Assets	8,774,113		7,838,486
Current liabilities
Accounts payable	223,453		320,088
Accounts payable - related parties	2,466,155		57,363
Operating Lease Liability	5,482		13,909
Accrued liabilities	1,151,328		1,149,012
Accrued liabilities - related parties	1,536,247		862,158
Notes payable - short term	398,837	[1]	3,438,162
Notes payable - related party	3,460,815		779,373
Total current liabilities	9,242,317		6,620,065
Asset retirement obligations	2,301,335		2,257,027
Operating Lease Liability	17,714
Derivative liability			22,554
Total Liabilities	11,561,366		8,899,646
Stockholders’ Equity (Deficit)
Common stock, $0.001 par value; 400,000,000 shares authorized; 176,988,322 and 176,988,322 shares issued and outstanding	176,988		176,988
Additional paid in capital	60,244,255		60,216,722
Accumulated other comprehensive income (loss)	(349,065)		(269,155)
Accumulated deficit	(63,013,127)		(61,339,161)
Total Stockholders’ Equity (Deficit)	(2,787,253)		(1,061,160)
Total Liabilities and Stockholders’ Equity (Deficit)	8,774,113		7,838,486
Series A Preferred Stock [Member]
Stockholders’ Equity (Deficit)
Preferred stock, value	199		199
Series B Preferred Stock [Member]
Stockholders’ Equity (Deficit)
Preferred stock, value	152,397		152,397
Series C Preferred Stock [Member]
Stockholders’ Equity (Deficit)
Preferred stock, value	$ 1,100		$ 850
[1]All notes are current (due within one year or less from December 31, 2022.)

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2022	Dec. 31, 2021
Common stock, par value	$ 0.001	$ 0.001
Common stock, shares authorized	400,000,000	400,000,000
Common stock, shares issued	176,988,322	176,988,322
Common stock, shares outstanding	176,988,322	176,988,322
Series A Preferred Stock [Member]
Preferred stock, par value	$ 0.001	$ 0.001
Preferred stock, shares authorized	1,000,000	1,000,000
Preferred stock, shares issued	199,100	199,100
Preferred stock, shares outstanding	199,100	199,100
Series B Preferred Stock [Member]
Preferred stock, shares authorized	3	3
Preferred stock, shares issued	3	3
Preferred stock, shares outstanding	3	3
Preferred stock, no par value	$ 0.001	$ 0.001
Series C Preferred Stock [Member]
Preferred stock, par value	$ 0.10	$ 0.10
Preferred stock, shares authorized	50,000	50,000
Preferred stock, shares issued	11,000	8,500
Preferred stock, shares outstanding	11,000	8,500

Consolidated Statements of Oper

Consolidated Statements of Operations and Comprehensive Loss - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Income Statement [Abstract]
Total revenue	$ 6,847,800	$ 5,895,228
Revenue, Product and Service [Extensible Enumeration]	BBLS:OilandGasSalesMember	BBLS:OilandGasSalesMember
Operating expenses
Lease operating expense	$ 6,790,040	$ 5,346,287
Production tax	438	1,203
General and administrative expenses	697,010	1,107,517
Depreciation, depletion and amortization	238,184	403,145
Asset retirement obligation accretion	173,603	316,873
Loss on forfeiture		132,000
Total operating expenses	7,899,275	7,307,025
Loss from operations	(1,051,475)	(1,411,797)
Other income (expenses)
Interest expense	(489,487)	(638,569)
Change in fair value of derivative liabilities	22,554	161,244
Other income (expense)	30,828	(101,297)
Gain on sale of assets	1,500	3,919,323
Total other income (expenses)	(434,605)	3,340,701
Net income (loss) before taxes	(1,486,080)	1,928,904
Income tax provision (benefit)
Net income (loss)	(1,486,080)	1,928,904
Series A preferred dividends	(179,190)	(179,190)
Series C preferred dividends	(8,696)	(779)
Net income (loss) attributable to common stockholders	(1,673,966)	1,748,935
Other comprehensive income, net of tax
Foreign currency translation adjustments	(79,910)	(2,723)
Comprehensive income (loss)	$ (1,753,876)	$ 1,746,212
Gain (loss) per share
(Basic and diluted)	$ (0.01)	$ 0.01
Weighted average number of common shares outstanding, basic and diluted	176,988,322	175,434,139

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Cash Flows from Operating Activities
Net income (loss)	$ (1,486,080)	$ 1,928,904
Adjustment to reconcile net loss to net cash used in operating activities:
Depletion, depreciation and amortization	238,184	403,145
Asset retirement obligation accretion and well plugging costs	125,603	316,873
Operating Lease Accrual	(978)	(2,783)
Amortization of debt discount	55,430	217,699
Change in fair value of derivative liabilities	(22,554)	(161,244)
Warrants as finance fees	2,783	18,061
Stock-based compensation expense		211,481
PPP loan forgiven		(56,680)
Gain on sale of assets	(1,500)	(3,919,323)
Loss on forfeiture		132,000
Accounts receivable	5,640	(1,097)
Prepaids and other current assets	24,597	33,802
Accounts payable	(90,254)	88,190
Accounts payable – related parties	2,451,946	56,776
Accrued liabilities	(41,974)	178,194
Accrued liabilities – related parties	537,414	450,424
Net cash provided by (used in) operating activities	1,798,257	(105,578)
Cash Flows from Investing Activities
Sale of equipment	1,500
Cash provided by (used in) investing activities	1,500
Cash Flows from Financing Activities
Proceeds from issuance of Series C preferred stock	25,000	85,000
Repayments of notes payable	(408,498)	(120,890)
Repayments of related party notes payable	(4,815)
Cash provided by financing activities	(388,313)	(35,890)
Foreign currency remeasurement	(167)	481
Net change in cash	1,411,277	(140,987)
Cash at beginning of period	14,058	155,045
Cash at end of period	1,425,335	14,058
SUPPLEMENTAL DISCLOSURES
Interest paid	128,209	239,384
Income taxes paid
NON-CASH INVESTING AND FINANCIAL DISCLOSURES
Settlement of related party accrued liabilities for common shares		527,520
Settlement of notes payable related party for common shares		144,888
Modification of related party debt		181,791
Accrued Series A preferred dividends	179,190	179,190
Accrued Series C preferred dividends	8,696	779
Series B Preferred Stock issued to directors		152,397
Utikuma acquisition – extra cost triggered by WTI		787,250
Capitalized accrued interest		$ 238,768

Statements of Changes in Stockh

Statements of Changes in Stockholders' Equity (Deficit) - USD ($)	Preferred Stock [Member] Series A Preferred Stock [Member]	Preferred Stock [Member] Series B Preferred Stock [Member]	Preferred Stock [Member] Series C Preferred Stock [Member]	Common Stock [Member]	Additional Paid-in Capital [Member]	Shares to be issued [Member]	AOCI Attributable to Parent [Member]	Retained Earnings [Member]	Total
Balance at Dec. 31, 2020	$ 199			$ 168,696	$ 59,044,519		$ (266,432)	$ (63,088,096)	$ (4,141,114)
Balance, shares at Dec. 31, 2020	199,100			168,696,226
Stock based compensation		$ 152,397			59,084				211,481
Stock based compensation, shares		3
Series A preferred dividends								(179,190)	(179,190)
Series C preferred dividends								(779)	(779)
Preferred Series C issued for cash			$ 850		84,150				85,000
Preferred Series C issued for cash, shares			8,500
Warrants issued as financing fee					18,061				18,061
Common shares issued for conversion of debt				$ 2,700	96,288				98,988
Common shares issued for conversion of debt, shares				2,700,000
Common shares issued for settlement of related party fees				$ 5,592	158,895				164,487
Common shares issued for settlement of related party fees, shares				5,592,096
Warrants issued for conversion of debt					200,378				200,378
Gain on modification of related party debt					181,791				181,791
Gain on issuance of shares for settlement of accrued related party fees					373,556				373,556
Other comprehensive income (loss)							(2,723)		(2,723)
Net income								1,928,904	1,928,904
Balance at Dec. 31, 2021	$ 199	$ 152,397	$ 850	$ 176,988	60,216,722		(269,155)	(61,339,161)	(1,061,160)
Balance, shares at Dec. 31, 2021	199,100	3	8,500	176,988,322
Series A preferred dividends								(179,190)	(179,190)
Series C preferred dividends								(8,696)	(8,696)
Preferred Series C issued for cash			$ 250		24,750				25,000
Preferred Series C issued for cash, shares			2,500
Warrants issued as financing fee					2,783				2,783
Other comprehensive income (loss)							(79,910)		(79,910)
Net income								(1,486,080)	(1,486,080)
Balance at Dec. 31, 2022	$ 199	$ 152,397	$ 1,100	$ 176,988	$ 60,244,255		$ (349,065)	$ (63,013,127)	$ (2,787,253)
Balance, shares at Dec. 31, 2022	199,100	3	11,000	176,988,322

ORGANIZATION AND BASIS OF PRESE

ORGANIZATION AND BASIS OF PRESENTATION	12 Months Ended
	Dec. 31, 2022
Organization, Consolidation and Presentation of Financial Statements [Abstract]
ORGANIZATION AND BASIS OF PRESENTATION	NOTE 1. ORGANIZATION AND BASIS OF PRESENTATION Petrolia Energy Corporation (the “Company”) is in the business of oil and gas exploration, development, and production. Basis of presentation The accompanying financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and pursuant to the accounting and disclosure rules and regulations of the United States Securities and Exchange Commission (“SEC”). A summary of the significant accounting policies applied in the preparation of the accompanying financial statements follows.

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2022
Accounting Policies [Abstract]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Principles of consolidation The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries, Askarii Resources and Petrolia Canada Corporation. All significant intercompany balances and transactions have been eliminated upon consolidation. The Company accounts for its investment in companies in which it has significant influence by the equity method. The Company’s proportionate share of earnings is included in earnings and added to or deducted from the cost of the investment. Foreign currency translation The functional and reporting currency of the Company is the United States dollar. The functional currencies of the Company’s wholly-owned subsidiaries, Askarii Resources and Petrolia Canada Corporation are the United States dollar and the Canadian dollar, respectively. Transactions involving foreign currencies are converted into the Company’s functional currency using the exchange rates in effect at the time of the transactions. At the balance sheet date, monetary assets and liabilities that are denominated in currencies other than the Company’s functional currency are translated using exchange rates at that date. Exchange gains and losses are included in net earnings. On consolidation, Petrolia Canada Corporation’s income statement amounts are translated at average exchange rates for the year, while the assets and liabilities are translated at year-end exchange rates. Translation adjustments are accumulated as a separate component of stockholders’ equity in other comprehensive income. Management estimates The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates made in preparing these financial statements include depreciation of furniture, equipment and software, asset retirement obligations (“AROs”) (Note 9), income taxes (Note 13) and the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom (Note 15). Cash and cash equivalents The Company considers all highly liquid instruments purchased with an original maturity date of three months or less to be cash equivalents. As of December 31, 2022, the Company did no Receivables and allowance for doubtful accounts Oil revenues receivable do not bear any interest. These receivables are primarily comprised of joint interest billings. Management regularly reviews collectability and establishes or adjusts an allowance for uncollectible amounts as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. Management has determined that a reserve for uncollectible amounts was not required in the periods presented. Oil and gas properties The Company follows the full cost accounting method to account for oil and natural gas properties, whereby costs incurred in the acquisition, exploration and development of oil and gas reserves are capitalized. Such costs include lease acquisition, geological and geophysical activities, rentals on nonproducing leases, drilling, completing and equipping of oil and gas wells and administrative costs directly attributable to those activities and asset retirement costs. Disposition of oil and gas properties are accounted for as a reduction of capitalized costs, with no gain or loss recognized unless such adjustment would significantly alter the relationship between capital costs and proved reserves of oil and gas, in which case the gain or loss is recognized to operations. The capitalized costs of oil and gas properties, excluding unevaluated and unproved properties, are amortized as depreciation, depletion and amortization expense using the units-of-production method based on estimated proved recoverable oil and gas reserves. The costs associated with unevaluated and unproved properties, initially excluded from the amortization base, relate to unproved leasehold acreage, wells and production facilities in progress and wells pending determination of the existence of proved reserves, together with capitalized interest costs for these projects. Unproved leasehold costs are transferred to the amortization base with the costs of drilling the related well once a determination of the existence of proved reserves has been made or upon impairment of a lease. Costs associated with wells in progress and completed wells that have yet to be evaluated are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property. Costs of dry wells are transferred to the amortization base immediately upon determination that the well is unsuccessful. All items classified as unproved property are assessed on a quarterly basis for possible impairment or reduction in value. Properties are assessed on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of various factors, including, but not limited to, the following: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; assignment of proved reserves; and economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization. Under full cost accounting rules for each cost center, capitalized costs of evaluated oil and gas properties, including asset retirement costs, less accumulated amortization and related deferred income taxes, may not exceed an amount (the “cost ceiling”) equal to the sum of (a) the present value of future net cash flows from estimated production of proved oil and gas reserves, based on current prices and operating conditions, discounted at ten percent (10%), plus (b) the cost of properties not being amortized, plus (c) the lower of cost or estimated fair value of any unproved properties included in the costs being amortized, less (d) any income tax effects related to differences between the book and tax basis of the properties involved. If capitalized costs exceed this limit, the excess is charged to operations. For purposes of the ceiling test calculation, current prices are defined as the un-weighted arithmetic average of the first day of the month price for each month within the 12 month period prior to the end of the reporting period. Prices are adjusted for basis or location differentials. Unless sales contracts specify otherwise, prices are held constant for the productive life of each well. Similarly, current costs are assumed to remain constant over the entire calculation period. Given the volatility of oil and gas prices, it is reasonably possible that the estimate of discounted future net cash flows from proved oil and gas reserves could change in the near term. If oil and gas prices decline in the future, even if only for a short period of time, it is possible that impairments of oil and gas properties could occur. In addition, it is reasonably possible that impairments could occur if costs are incurred in excess of any increases in the present value of future net cash flows from proved oil and gas reserves, or if properties are sold for proceeds less than the discounted present value of the related proved oil and gas reserves. Furniture, equipment and software Furniture, equipment, and software are stated at cost, less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the related asset, generally three to five years. Fully depreciated assets are retained in property and accumulated depreciation accounts until they are removed from service. Management performs ongoing evaluations of the estimated useful lives of the property and equipment for depreciation purposes. Maintenance and repairs are expensed as incurred. Management periodically reviews long-lived assets, other than oil and gas property, for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be fully recoverable. The Company recognizes an impairment loss when the sum of expected undiscounted future cash flows is less than the carrying amount of the asset. The amount of impairment is measured as the difference between the asset’s estimated fair value and its book value. Derivative financial instruments The Company’s derivative financial instruments consist of warrants with an exercise price denominated in the Company’s functional currency. These derivative financial instruments are measured at their fair value at the end of each reporting period. Changes in fair value are recorded in net income. Asset retirement obligations The Company records a liability for Asset Retirement Obligations (“AROs”) associated with its oil and gas wells when those assets are placed in service. The corresponding cost is capitalized as an asset and included in the carrying amount of oil and gas properties and is depleted over the useful life of the properties. Subsequently, the ARO liability is accreted to its then-present value. Inherent in the fair value calculation of an ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance. Settlements greater than or less than amounts accrued as ARO are recorded as a gain or loss upon settlement. Debt issuance costs Costs incurred in connection with the issuance of long-term debt are presented as a direct deduction from the carrying value of the related debt and amortized over the term of the related debt. Revenue recognition In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers Revenue from contracts with customers The Company recognizes revenue when it satisfies a performance obligation by transferring control over a product to a customer. Revenue is measured based on the consideration the Company expects to receive in exchange for those products. Performance obligations and significant judgments The Company sells oil and natural gas products in the United States through a single reportable segment. The Company enters into contracts that generally include one type of distinct product in variable quantities and priced based on a specific index related to the type of product. The oil and natural gas is typically sold in an unprocessed state to processors and other third parties for processing and sale to customers. The Company recognizes revenue at a point in time when control of the oil or natural gas passes to the customer or processor, as applicable, discussed below. For oil sales, control is typically transferred to the customer upon receipt at the wellhead or a contractually agreed upon delivery point. Under our natural gas contracts with processors, control transfers upon delivery at the wellhead or the inlet of the processing entity’s system. For our other natural gas contracts, control transfers upon delivery to the inlet or to a contractually agreed upon delivery point. In the cases where the Company sells to a processor, management has determined that the Company is the principal in the arrangement and the processors are customers. The Company recognizes the revenue in these contracts based on the net proceeds received from the processor. Transfer of control drives the presentation of transportation and gathering costs within the accompanying consolidated statements of operations. Transportation and gathering costs incurred prior to control transfer are recorded within the transportation and gathering expense line item on the accompanying consolidated statements of operations, while transportation and gathering costs incurred subsequent to control transfer are recorded as a reduction to the related revenue. A portion of our product sales are short-term in nature. For those contracts, the Company uses the practical expedient in Accounting Standards Codification (“ASC”) 606-10-50-14 exempting us from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For our product sales that have a contract term greater than one year, the Company has utilized the practical expedient in ASC 606-10-50-14(a) which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to an unsatisfied performance obligation. Under these sales contracts, each unit of product represents a separate performance obligation; therefore, future volumes are unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required. The Company has no unsatisfied performance obligations at the end of each reporting period. Management does not believe that significant judgments are required with respect to the determination of the transaction price, including any variable consideration identified. There is a low level of uncertainty due to the precision of measurement and use of index-based pricing with predictable differentials. Additionally, any variable consideration identified is not constrained. Stock-based compensation The Company accounts for stock-based compensation to employees in accordance with FASB ASC 718. Stock-based compensation Income taxes Income taxes are accounted for pursuant to ASC 740, Income Taxes Uncertain tax positions are recognized in the financial statements only if that position is more likely than not of being sustained upon examination by taxing authorities, based on the technical merits of the position. The Company recognizes interest and penalties related to uncertain tax positions in the income tax provision. There are currently no unrecognized tax benefits that if recognized would affect the tax rate. There was no The Company is required to file federal income tax returns in the United States and Canada, and in various state and local jurisdictions. The Company’s tax returns are subject to examination by taxing authorities in the jurisdictions in which it operates in accordance with the normal statutes of limitations in the applicable jurisdiction. Earnings (loss) per share Basic earnings (loss) per share have been calculated based on the weighted-average number of common shares outstanding. The treasury stock method is used to compute the dilutive effect of the Company’s share-based compensation awards. Under this method, the incremental number of shares used in computing diluted earnings per share (“EPS”) is the difference between the number of shares assumed issued and purchased using assumed proceeds. Diluted EPS amounts would include the effect of outstanding stock options, warrants, and other convertible securities if including such potential shares of common stock is dilutive. Basic and diluted earnings per share are the same in all periods presented as all outstanding instruments are anti-dilutive. Concentration of credit risk The Company is subject to credit risk resulting from the concentration of its oil receivables with significant purchasers. Three purchasers accounted for all of the Company’s oil sales revenues for 2022 and 2021. The Company does not require collateral. While the Company believes its recorded receivables will be collected, in the event of default the Company would follow normal collection procedures. The Company does not believe the loss of a purchaser would materially impact its operating results as oil is a fungible product with a well-established market and numerous purchasers. At times, the Company maintains deposits in federally insured financial institutions in excess of federally insured limits. Management monitors the credit ratings and concentration of risk with these financial institutions on a continuing basis to safeguard cash deposits. Fair value measurements Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (i.e., the “exit price”) in an orderly transaction between market participants at the measurement date. The hierarchy is broken down into three levels based on the observability of inputs as follows: ● Level 1 — Valuations based on quoted prices in active markets for identical assets or liabilities that the Company has the ability to access. Valuation adjustments and block discounts are not applied to Level 1 instruments. Since valuations are based on quoted prices that are readily and regularly available in an active market, valuation of these products does not entail a significant degree of judgment; ● Level 2 — Valuations based on one or more quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly; and ● Level 3 — Valuations based on inputs that are unobservable and significant to the overall fair value measurement. Our derivative liabilities are measured at fair value on a recurring basis and estimated as follows: SCHEDULE OF DERIVATIVE LIABILITIES MEASURED AT FAIR VALUE ON RECURRING BASIS December 31, 2021 Level 1 Level 2 Level 3 Total Derivative liabilities $ — $ — $ 22,554 $ 22,554 ARO liabilities $ — $ — 2,257,027 $ 2,257,027 December 31, 2022 Derivative liabilities $ — $ — $ — $ — ARO liabilities $ — $ — $ 2,301,335 $ 2,301,335 The carrying value of cash, accounts receivable, other current assets, accounts payable, accounts payable – related parties, accrued liabilities and accrued liabilities – related parties, as reflected in the consolidated balance sheets, approximate fair value, due to the short-term maturity of these instruments. The carrying value of notes payable approximates their fair value due to immaterial changes in market interest rates and the Company’s credit risk since issuance of the instruments or due to their short-term nature. Derivative liabilities are remeasured at fair value every reporting period. Our derivative liabilities are considered level 3 financial instruments. Related parties The Audit Committee approves all material related party transactions. The Audit Committee is provided with the details of each new, existing or proposed related party transaction, including the terms of the transaction, the business purpose of the transaction, and the benefits to the Company and the relevant related party. In determining whether to approve a related party transaction, the following factors are considered: (1) if the terms are fair to the Company, (2) if there are business reasons to enter into the transaction, (3) if the transaction would impair independence of an outside Director, or (4) if the transaction would present an improper conflict of interest for any Director or executive officer. Any member of the Audit Committee who has an interest in the transaction will abstain from voting on the approval of the related party transaction. Business combinations In January 2017, the FASB issued ASU 2017-01 Business Combinations Clarifying the Definition of a Business Reclassifications Certain amounts previously presented for prior periods have been reclassified to conform to the current presentation. The reclassifications had no effect on net loss, working capital or equity previously reported. Recent accounting pronouncements The Company has evaluated all the recent accounting pronouncements through the filing date and believes that none of them will have a material effect on the Company.

GOING CONCERN

GOING CONCERN	12 Months Ended
	Dec. 31, 2022
Organization, Consolidation and Presentation of Financial Statements [Abstract]
GOING CONCERN	NOTE 3. GOING CONCERN The Company has suffered recurring losses from operations and currently has a working capital deficit. These conditions raise substantial doubt about the Company’s ability to continue as a going concern. The Company plans to generate profits by reducing overhead costs and reworking its existing oil or gas wells, as needed, funding permitting. The Company may need to raise funds through either the sale of its securities, issuance of corporate bonds, joint venture agreements and/or bank financing to accomplish its goals. If additional financing is not available when needed, we may need to cease operations. The Company may not be successful in raising the capital needed to drill and/or rework existing oil wells. Any additional wells that the Company may drill may be non-productive. Management believes that actions presently being taken to secure additional funding for the reworking of its existing assets will provide the opportunity for the Company to continue as a going concern. Since the Company has an oil producing asset, its goal is to increase the production rate by optimizing its current infrastructure. The accompanying financial statements have been prepared assuming the Company will continue as a going concern; no adjustments to the financial statements have been made to account for this uncertainty.

EVALUATED PROPERTIES

EVALUATED PROPERTIES	12 Months Ended
	Dec. 31, 2022
Extractive Industries [Abstract]
EVALUATED PROPERTIES	NOTE 4. EVALUATED PROPERTIES The acquired properties and current properties can be summarized as follows: SCHEDULE OF ACQUIRED PROPERTIES AND CURRENT PROPERTIES Cost Canadian properties US properties Total As of December 31, 2020 $ 4,314,805 $ 4,304,622 $ 8,619,427 Additions 787,250 — 787,250 Dispositions (2,563,434 ) — (2,563,434 ) Foreign currency translation (46,218 ) — (46,218 ) As of December 31, 2021 $ 2,492,403 $ 4,304,622 $ 6,797,025 Additions — — — Dispositions — 375 375 Foreign currency translation (159,363 ) — (159,363 ) As of December 31, 2022 $ 2,333,040 $ 4,304,997 $ 6,638,037 Accumulated depletion As of December 31, 2020 2,631,749 $ 61,551 $ 2,693,300 Dispositions (2,629,672 ) — (2,629,672 ) Depletion 378,306 — 378,306 Foreign currency translation 7,026 — 7,026 As of December 31, 2021 $ 387,409 $ 61,551 $ 448,960 Depletion 237,067 — 237,067 Foreign currency translation (34,273 ) — (34,273 ) As of December 31, 2022 $ 590,203 $ 61,551 $ 651,754 Net book value as at December 31, 2022 $ 1,742,837 $ 4,243,446 $ 5,986,283 Net book value as at December 31, 2021 $ 2,104,994 $ 4,243,071 $ 6,348,065 U.S. Properties – Minerva-Rockdale Field (“NOACK”) Field On November 1, 2018, the Company sold 83% 100% 375,000 260,000 115,000 120,000 255,000 On August 6, 2019, the Company entered into a Purchase and Sale Agreement (“PSA”) for the sale of the same NOACK property with Flowtex Energy LLC. (“FT”). The purchaser agreed to pay $ 400,000 20,000 380,000 375,000 25,000 400,000 25,000 8,995 16,005 U.S. Properties – Slick Unit Dutcher Sand (“SUDS”) Field The Slick Unit Dutcher Sand (SUDS) field is located in Creek County, Oklahoma. Petrolia owns a 100 76.5 2,530 1,670 860 As of December 31, 2022, SUDS total estimated net proved reserves were approximately 346 153 On January 13, 2023, the Company received an Incident and Complaint Investigation Report issued by the Oklahoma Corporation Commission (OCC) due to a mineral owner complaint. The OCC issued a plug or produce order for SUDS West unit and SUDS East unit. The Company has received two extensions of time and is working with the OCC to implement a production plan to bring both units into compliance. The SUDS field is currently shut-in while the Company completes a review of the land and lease records currently being conducted by a petroleum landman. PEC has also initiated a detailed reservoir and historical waterflood sweeping pattern analysis. The Company is currently awaiting the outcome of the review of the SUDS subsurface geology. PEC is finalizing a SUDS capital budget with the intent to commence further field development in Q3 2023. The SUDS field is still burdened with the Lazy D Ranch Slick, LLC (Plaintiff) vs. Petrolia Energy Corporation (Defendant) litigation, including the Statement of Judgment dated February 20, 2020 and the Settlement Agreement and Release dated August 2020. U.S. Properties – Twin Lakes San Andres Unit (“TLSAU”) Field The Twin Lakes San Andres Unit (TLSAU) field is located in Chaves County, New Mexico. As of December 31, 2022, it was determined that PEC does not own any TLSAU leases, and therefore has no reserves. It is estimated that PEC has 29 wells that need to be plugged and abandoned, plus surface remediated. The estimated cost of the TLSAU well plugging and abandonment, and surface remediation obligations are approximately $ 1.2 Luseland, Hearts Hill and Cuthbert fields On June 29, 2018, the Company acquired a 25% 41,526 80% The effective date of the acquisition was June 1, 2018. The acquisition of the Canadian Properties was evidenced and documented by a Memorandum of Understanding between the Company and Blue Sky dated June 29, 2018 and a Conveyance between the parties dated as of the same date, pursuant to which the Company agreed to acquire the Working Interest in consideration for $ 1,428,581 1,096,216 1,022,400 782,441 406,181 313,775 1,530,000 12% 19% The Working Interest will be held in the name of the Company’s wholly-owned Alberta, Canada, subsidiary, Petrolia Canada Corporation. The Acquisition Note which was dated June 8, 2018, bears interest at the rate of 9% extend the maturity date for a period six months with 10 days’ notice to Blue Sky, in the event the Company pays 25% of the principal amount of the Acquisition Note at the time of extension. On September 17, 2018, the Company entered a Memorandum of Understanding (“MOU”) with Blue Sky. Pursuant to the MOU, the Company obtained the rights to acquire an additional 3% 28% 3% 150,000 On February 16, 2022, the Company entered into both a Purchase and Sale Agreement and a Debt Settlement Agreement with Prospera Energy. Prospera agreed to purchase the Company’s twenty-eight percent ( 28 2,061,614 510,000 75,000 1,622,756 1,711,142 2,312,897 3,333,898 4,959,512 3,919,323 Utikuma field On May 1, 2020, Petrolia Energy Corporation acquired a 50% 28,000 100% The total purchase price of the property was $2,000,000 (CAD), with $1,000,000 of that total due initially. The additional $1,000,000 was contingent on the future price of WTI crude. At the time WTI price exceeded $50/bbl, the Company would pay an additional $750,000 CAD. In addition, at the time WTI price exceeded $57/bbl the Company would pay an additional $250,000 CAD (for a cumulative contingent total of $1,000,000 CAD). The price of WTI crude exceeded $50/bbl on January 6, 2021 and exceeded $57/bbl on February 8, 2021. The additional payments due were netted with the accounts receivable balance from previous Joint Interest Billing statements from BSR. The total USD value of the addition was $787,250, using prevailing exchange rates on the respective dates. Included in the terms of the agreement, the Company also funded their portion of the Alberta Energy Regulator (“AER”) bond fund requirement $763,754 CAD ($563,904 USD), necessary for the wells to continue in production after the acquisition. Additional funds in the amount of $490,624 CAD ($362,245 USD) remain in the other current asset balance for future payments to BSR, related to the acquisition On December 2, 2020, Petrolia Canada Corporation received $ 602,404.84 On August 21, 2021, the Company signed a Letter Agreement to divest the Company’s wholly owned Canada subsidiary, Petrolia Canada Corporation (PCC) and its assets in consideration for $ 6,500,000 5,150,000 50% 28,000 28% 200,000 2,000,000 1,000,000 3,300,000 200,000 On May 5, 2023, the Company was notified by Blue Sky Resources (BSR), the operator of our Utikuma asset that the Province of Alberta has declared a state of emergency due to wildfires in Alberta. We were informed that because of wildfires in the vicinity of our oilfield assets, the field was shut in and all personnel were evacuated, and that the highway to the Slave Lake area has been closed. Early assessments of the situation indicate that our Utikuma facilities may have incurred major damage.

NOTES PAYABLE

NOTES PAYABLE	12 Months Ended
	Dec. 31, 2022
Debt Disclosure [Abstract]
NOTES PAYABLE	NOTE 5. NOTES PAYABLE SCHEDULE OF NOTES PAYABLE Interest rate Date of maturity December 31, 2022 December 31, 2021 Truck loan (ii) 5.49 % January 20, 2022 $ — $ 4,021 Credit note I (iii) 10 % January 01, 2020 426,909 831,387 Discount on credit note I (41,572 ) (97,001 ) Credit note II (iv) 10 % December 31, 2022 — 2,085,432 Lee Lytton On demand 3,500 3,500 Credit note III (v) 10 % December 31, 2021 — 416,900 Quinten Beasley (vi) 10 % October 14, 2016 — 5,000 Jovian Petroleum Corporation (vii) 3.5 % December 31, 2021 — 178,923 M. Horowitz 10 % October 14, 2016 10,000 10,000 $ 398,837 (1) $ 3,438,162 (i) All notes are current (due within one year or less from December 31, 2022.) (ii) On January 6, 2017, the Company purchased a truck and entered into an installment note in the amount of $ 35,677 five years 5.49% 683 (iii) On January 2, 2020, the Company entered into a loan agreement in the amount of $ 1,000,000 120,000 10% June 30, 2020 5,000,000 0.10 January 2, 2023 266,674 11,111 5,000,000 0.05 January 6, 2023 166,289 4,614.14 (iv) On December 1, 2021, the Company signed an amended loan agreement with a third party for $ 2,085,432 10% December 31, 2022 25% (v) Various shareholder advances were provided by Joel. Oppenheim during 2018 and 2019. There were no formal documents drawn. Interest rates were applied based on other similar loan agreements entered into by the Company during that period. On February 12, 2021, the Company entered into an amended loan agreement in the amount of $ 416,900 10% December 31, 2021 (vi) This note was reclassified to Notes Payable – Related Party, due to Mr. Beasley’s beneficial ownership of our common stock. See Note 7. Related Party Notes Payable. (vii) On February 9, 2018, the Company entered into a Revolving Line of Credit Agreement (“LOC”) for $ 200,000 500,000 25% 3.5% The following is a schedule of future minimum repayments of notes payable as of December 31, 2022: SCHEDULE OF FUTURE MINIMUM REPAYMENTS OF NOTES PAYABLE 2023 $ 440,409 Thereafter — Total $ 440,409

LEASES

LEASES	12 Months Ended
	Dec. 31, 2022
Leases
LEASES	NOTE 6. LEASES Our adoption of ASU 2016-02, Leases (Topic 842), and subsequent ASUs related to Topic 842, requires us to recognize substantially all leases on the balance sheet as an ROU asset and a corresponding lease liability. The new guidance also requires additional disclosures as detailed below. We adopted this standard on the effective date of January 1, 2019 and used this effective date as the date of initial application. Under this application method, we were not required to restate prior period financial information or provide Topic 842 disclosures for prior periods. We elected the ‘package of practical expedients,’ which permitted us to not reassess our prior conclusions related to lease identification, lease classification, and initial direct costs, and we did not elect the use of hindsight. Lease ROU assets and liabilities are recognized at commencement date of the lease, based on the present value of lease payments over the lease term. The lease ROU asset also includes any lease payments made and excludes any lease incentives. When readily determinable, we use the implicit rate in determining the present value of lease payments. When leases do not provide an implicit rate, we use our incremental borrowing rate based on the information available at the lease commencement date, including the lease term. Short-term leases with an initial term of 12 months or less are not recorded on the balance sheet. Lease expense for short-term leases is recognized on a straight-line basis over the lease term. As of December 31, 2022 and 2021, we did not have any short-term leases. The tables below present financial information associated with our lease. SCHEDULE OF FINANCIAL INFORMATION LEASE Balance Sheet Classification December 31, 2022 December 31, 2021 Right-of-use assets Other long-term assets 23,086 12,821 Current lease liabilities Other current liabilities 5,482 13,909 Non-current lease liabilities Other long-term liabilities 17,714 — As of December 31, 2022, our maturities of our lease liability are as follows: SCHEDULE OF MATURITIES LEASE LIABILITY 2023 $ 5,482 2024 5,714 2025 6,539 2026 5,400 Total $ 23,196 Less: Imputed interest (110 ) Present value of lease liabilities $ 23,086

RELATED PARTY NOTES PAYABLE

RELATED PARTY NOTES PAYABLE	12 Months Ended
	Dec. 31, 2022
Related Party Notes Payable
RELATED PARTY NOTES PAYABLE	NOTE 7. RELATED PARTY NOTES PAYABLE The chart below summarizes the related party Notes Payable as of December 31, 2022 and 2021. SCHEDULE OF RELATED PARTY NOTES PAYABLE Interest rate Date of maturity December 31, 2022 December 31, 2021 Quinten Beasley 10 % October 14, 2016 5,000 — Blue Sky Resources (i) 3.5 % December 31, 2021 178,923 — Blue Sky Resources (ii) 10 % December 31, 2021 150,000 — Blue Sky Resources (iii) 10 % December 31, 2022 2,085,432 — Ivar Siem (iv) 9 % December 31, 2021 278,435 278,435 Mark Allen (v) 9 % September 2, 2021 55,000 55,000 Mark Allen (vi) 12 % June 30, 2020 200,000 200,000 Mark Allen (vii) 9 % June 30, 2021 241,125 245,938 Joel Oppenheim (viii) 10 % December 31, 2021 266,900 — $ 3,460,815 $ 779,373 (i) On February 9, 2018, the Company entered into a Revolving Line of Credit Agreement (“LOC”) for $ 200,000 500,000 25% 3.5% (ii) On February 3, 2022, Joel Oppenheim assigned $150,000 of his note, shown as Credit Note II in Note 5. Notes Payable to Blue Sky Resources. (iii) On December 1, 2021, the Company signed an amended loan agreement with a third party for $ 2,085,432 10% December 31, 2022 25% (iv) On August 15, 2019, the Company entered into a loan agreement in the amount of $ 75,000 12% 100,000 12% 1,250,000 0.08 5,000,000 0.10 50,000 0% 200,000 0.10 March 1, 2022 278,435 9% December 31, 2021 (v) On April 15, 2020, the Company entered into an agreement, with Mark Allen, that included a funding clause where the Company borrowed $ 55,000 9% September 2, 2021 (vi) During 2019, the Company entered into a loan agreement in the amount of $ 200,000 12% June 30, 2020 2,500,000 0.08 10,000,000 0.10 (vii) On January 3, 2020, the Company entered into a loan agreement in the amount of $ 100,000 10% June 1, 2020 400,000 0.10 January 3, 2023 31,946 1,775 125,000 10 June 1, 2020 750,000 0.10 February 14, 2022 38,249 1,903 245,938 9% June 30, 2021 (viii) Various shareholder advances were provided by Joel. Oppenheim during 2018 and 2019. There were no formal documents drawn. Interest rates were applied based on other similar loan agreements entered into by the Company during that period. On February 12, 2021, the Company entered into an amended loan agreement in the amount of $416,900 that consolidated these amounts. The loan bears interest at 10% per annum and has a maturity date of December 31, 2021. On August 31, 2021, this loan was in default due to missed interest payments, and a default interest rate was applied to the principal balance. On February 3, 2022, $150,000 of this note was assigned to Blue Sky Resources. The remaining balance has been moved to Notes Payable – Related Party due to Mr. Oppenheim’s beneficial ownership of our common stock. The following is a schedule of future minimum repayments of related party notes payable as of December 31, 2022: SCHEDULE OF FUTURE MINIMUM REPAYMENTS OF RELATED PARTY NOTES PAYABLE 2023 $ 3,460,815 Thereafter — Total $ 3,460,815

DERIVATIVE FINANCIAL INSTRUMENT

DERIVATIVE FINANCIAL INSTRUMENTS	12 Months Ended
	Dec. 31, 2022
Investments, All Other Investments [Abstract]
DERIVATIVE FINANCIAL INSTRUMENTS	NOTE 8. DERIVATIVE FINANCIAL INSTRUMENTS On May 18, 2018, as an inducement to enter into an Amended and Restated Loan Agreement, the Company issued, among other instruments, warrants to acquire 320,000 0.10 30,012 May 11, 2021 On January 6, 2020, as an inducement to enter into a Loan Agreement, the Company issued, among other instruments, warrants to acquire 5,000,000 0.10 144,259 On October 30, 2020, as an inducement to extend the principal payment deadline from the previously issued Loan Agreement, the Company issued additional warrants to acquire 5,000,000 0.10 95,352 As of December 31, 2022, all of the above warrants were expired, so no further derivative value exists. A summary of the activity of the derivative liabilities is shown below: SCHEDULE OF DERIVATIVE LIABILITIES Balance, December 31, 2021 $ 22,554 Additions — Fair value adjustments (22,554 ) As of December 31, 2022 $ — Derivative liability classified warrants in the years ended December 31, 2022 were valued using the Black Scholes Option Pricing Model with the range of assumptions outlined below. Expected life was determined based on historical exercise data of the Company. SCHEDULE OF DERIVATIVE LIABILITY OF FAIR VALUE ASSUMPTION December 31, 2022 Risk-free interest rate 4.12 % Expected life 0 Expected dividend rate 0 % Expected volatility 267 %

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Dec. 31, 2022
Asset Retirement Obligation Disclosure [Abstract]
ASSET RETIREMENT OBLIGATIONS	NOTE 9. ASSET RETIREMENT OBLIGATIONS The Company has a number of oil and gas wells in production and will have AROs once the wells are permanently removed from service. The primary obligations involve the removal and disposal of surface equipment, plugging and abandoning the wells and site restoration. Petrolia Energy Corporation (“Petrolia” or the “Company”) is the operator of certain wells located in New Mexico, at the Twin Lakes San Andres Unit (“TLSAU”) Field. TLSAU is located 45 miles from Roswell, Chaves County, New Mexico. On March 4, 2021, the Company received a letter from the Commissioner of Public Lands of the State of New Mexico, which was sent to us and certain other parties notifying such parties of certain non-compliance with the laws and regulations that it administers. The deficiencies are currently in the process of being settled by a third party agreeing to plug six wells, including at least two Company operated wells (TLSAU wells #316 and #037). The scope of the matter above included only 240 acres of the 640 acres of The New Mexico State Land Office (SLO) lease. The Commissioner of Public Lands of the State of New Mexico could still file suit and require the plugging and surface remediation of all wells in section 36. On April 8, 2021, the State of New Mexico Energy, Minerals and Natural Resources Department Oil Conservation Division (“OCD”) sent the Company a Notice of Violation alleging that the Company was not in compliance with certain New Mexico Oil and Gas Act regulations (the “NMAC”), associated with required reporting, inactive wells and financial assurance requirements, plugging certain abandoned wells, providing required financial assurance in connection with plugging expenses, and proposing to assess certain civil penalties in the amount of an aggregate of approximately $ 35,100 As previously reported and in Petrolia’s Form 8-K dated October 25, 2021 (reference to which is hereby made), on April 8, 2021, the State of New Mexico Energy, Minerals and Natural Resources Department, Oil Conservation Division (the “OCD”) issued a Notice of Violation (the “NOV”) to Petrolia alleging that the Company violated four regulations under Title 19, Chapter 15 of the New Mexico Administrative Code (the “NMAC”) by: (i) failing to file production reports for certain wells, (ii) exceeding the number of inactive wells allowed, (iii) failing to provide financial assurance in the amount required, and (iv) failing to provide additional financial assurance in the amount required. The Company acknowledged the violations alleged in the NOV and requested an informal resolution. On December 30, 2021, to resolve this matter, Petrolia entered into a Stipulated Final Order ( the “SFO”) in Case No. 21982 with the OCD whereby Petrolia among other things agreed to: (i) submit appropriate forms for wells identified on the SFO Inactive Well List, (ii) plug the specific TLSAU wells listed in section 8 (c) and (d) of the SFO, as well as submit all required information and forms specified in the SFO, (iii) open an escrow account meeting the terms listed in the SFO, (iv) deposit funds into an escrow account within the timeframe described in the SFO, and (v) provide the OCD with a report proposing deadlines for bringing all remaining wells into compliance. The company recognized an additional liability of $ 792,000 The Company entered into a settlement agreement on July 27, 2020 with Moon Company, Trustee of the O’Brien Mineral Trust pursuant to which nine leases totaling approximately 3,800 acres of the 4,880 acre Twin Lakes San Andres Unit were terminated as a part of the settlement agreement. Pursuant to this settlement agreement, the Company no longer has the right to produce oil, gas, or other hydrocarbons and any other minerals from the mineral estate encumbered by the leases and owned by the trustee of the O’Brien Mineral Trust. AROs associated with the retirement of tangible long-lived assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived assets in the period incurred. The fair value of AROs is recognized as of the acquisition date of the working interest. The cost of the tangible asset, including the asset retirement cost, is depleted over the life of the asset. AROs are recorded at estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligations discounted at the Company’s credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. If estimated future costs of AROs change, an adjustment is recorded to both the ARO and the long-lived asset. Revisions to estimated AROs can result from changes in retirement cost estimates, revisions to estimated discount rates and changes in the estimated timing of abandonment. SCHEDULE OF FAIR VALUE OF ASSET RETIREMENT OBLIGATIONS December 31, 2022 Inflation rate 1.92 2.15 % Estimated asset life 12 22 The following table shows the change in the Company’s ARO liability for the years ended December 31, 2022, and 2021: SCHEDULE OF CHANGE IN ASSET RETIREMENT OBLIGATIONS Canadian properties United States properties Total Asset retirement obligations, December 31, 2020 $ 2,711,909 $ 912,225 $ 3,624,133 Plugging liability at Twin Lakes — 152,000 132,000 Accretion expense 290,367 26,506 316,873 Disposition (1,824,339 ) — (1,824,339 ) Foreign currency translation 8,360 — 8,360 Asset retirement obligations, December 31, 2021 $ 1,186,297 $ 1,070,730 $ 2,257,027 Plugging liability at Twin Lakes — — — Accretion expense 145,191 28,412 173,603 Disposition — (47,624 ) (47,624 ) Foreign currency translation (81,671 ) — (81,671 ) Asset retirement obligations, December 31, 2022 $ 1,249,816 $ 1,051,518 $ 2,301,335

EQUITY

EQUITY	12 Months Ended
	Dec. 31, 2022
Equity [Abstract]
EQUITY	NOTE 10. EQUITY Preferred stock The holders of Series A Preferred Stock are entitled to receive cumulative dividends at a rate of 9 0.28 the value of each dollar of preferred stock (based on a $10 per share price) will convert into 7.1429 common shares (which results in a $0.14 per common share conversion rate) In accordance with the terms of the Series A Preferred Stock, cumulative dividends of $ 179,190 179,190 The holders of Series B Preferred Stock do not accrue dividends and have no conversion rights. For so long as any shares of Series B Preferred Stock remain issued and outstanding, the holders thereof, voting separately as a class, have the right to vote on all shareholder matters (including, but not limited to at every meeting of the stockholders of the Company and upon any action taken by stockholders of the Company with or without a meeting) equal to sixty percent (60%) of the total vote. No shares of Series B Preferred Stock held by any person who is not then a member of Board of Directors of the Company shall have any voting rights. For more information, see Form 8-K reference in the Exhibits section. The holders of Series C Preferred Stock are entitled to receive cumulative dividends at a rate of 8 the value of each dollar of Series C Preferred Stock (based on a $10 per share price) will convert into 100 common shares (which results in a $0.01 per common share conversion rate) In accordance with the terms of the Series C Preferred Stock, cumulative dividends of $ 8,696 779 Common stock On January 25, 2021, the Company signed an Executive Salary Payable Agreement with Zel Khan as the Chief Executive Officer. All of Mr. Khan’s previous salary obligations were satisfied by the issuance of 1,992,272 Joel Oppenheim, former Director, was issued 316,491 Paul Deputy was reinstated Interim Chief Financial Officer and signed a Settlement and Mutual Release Agreement. In exchange for releasing the Company for any current, outstanding payroll and/or service-related liability on January 29, 2021, the Company agreed to pay Mr. Deputy $ 50,000 250,000 0.033 134,270 45,000 On March 30, 2021, Mark Allen converted $ 30,000 333,333 0.09 On March 30, 2021, Mark Allen converted a defaulted secured loan of $ 135,000 9,888 135,000 5,400,000 5,400,000 0.08 36 months More details on the transactions above can be found in Note 11. Related Party Transactions. The common stock is currently not traded. Warrants Continuity of the Company’s common stock purchase warrants issued and outstanding is as follows: SCHEDULE Of COMMON STOCK PURCHASE WARRANTS ISSUED AND OUTSTANDING Warrants Weighted average exercise price Outstanding at year ended December 31, 2020 40,764,666 $ 0.13 Granted 9,400,000 0.09 Expired (20,464,666 ) 0.11 Outstanding at year ended December 31, 2021 29,700,000 0.13 Granted 1,000,000 0.10 Expired (6,730,000 ) 0.11 Outstanding at year ended December 31, 2022 23,970,000 0.13 As of December 31, 2022, the weighted-average remaining contractual life of warrants outstanding was 0.81 1.71 As of December 31, 2022, the intrinsic value of warrants outstanding is $ 0 0 The table below summarizes warrant issuances during the years ended December 31, 2022, and 2021: SCHEDULE OF WARRANTS ISSUANCE DURING PERIOD Year ended December 31, 2022 2021 Warrants granted: Board of directors and advisory board service — 3,000,000 Pursuant to financing arrangements 1,000,000 1,000,000 Pursuant to loan agreements — 5,400,000 Total 1,000,000 9,400,000 Warrants granted in the years ended December 31, 2022, and 2021 were valued using the Black Scholes Option Pricing Model with the range of assumptions outlined below. Expected life was determined based on historical exercise data of the Company. SCHEDULE OF FAIR VALUE OF ASSUMPTION OF WARRANTS December 31, 2022 December 31, 2021 Risk-free interest rate 2.49 4.22 % 0.16 0.97 % Expected life 3.0 2.0 3.0 Expected dividend rate 0 % 0 % Expected volatility 267 299 % 277 356 % On October 30, 2020, a third-party debtor was issued warrants to purchase 5,000,000 0.05 3 On March 31, 2021, Mark Allen was issued warrants to purchase 5,400,000 0.08 3 135,000

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	12 Months Ended
	Dec. 31, 2022
Related Party Transactions [Abstract]
RELATED PARTY TRANSACTIONS	NOTE 11. RELATED PARTY TRANSACTIONS On May 29, 2020, Petrolia Energy Corporation acquired a 50 28,000 100 2,000,000 1,000,000 1,000,000 At the time WTI price exceeded $50/bbl, the Company would pay an additional $750,000. In addition, at the time WTI price exceeded $57/bbl the Company would pay an additional $250,000 (for a cumulative contingent total of $ 1,000,000 787,250 765,752 563,904 490,624 362,245 On January 7, 2021, prior Board Member Joel Oppenheim was issued 316,491 60,000 0.02 53,670 On January 11, 2021, prior CEO Zel Khan was issued 1,992,272 325,000 0.025 275,193 On January 29, 2021, prior CFO Paul Deputy was reinstated as Interim Chief Financial Officer and signed an agreement that in exchange for 250,000 20 2,500 192,520.04 0.033 134,270 On March 30, 2021, President Mark Allen was issued 333,333 0.09 30,000 0.033 19,001 On March 31, 2021, President Mark Allen was issued 5,400,000 135,000 9,888 135,000 0.033 5,400,000 0.08 200,378 98,690 On August 21, 2021, the Company signed a Letter Agreement to divest the Company’s wholly-owned Canada subsidiary, Petrolia Canada Corporation (PCC) and its assets in consideration for $ 6,500,000 5,150,000 50 28,000 28 200,000 2,000,000 1,000,000 3,300,000 200,000 On October 25, 2021, Petrolia Energy Corporation issued one share of its newly designated shares of Series B Preferred Stock to each of the three members of its then Board of Directors, (1) James E. Burns, (2) Leo Womack and (3) Ivar Siem, in consideration for services rendered to the Company as members of the Board of Directors. Such shares of Series B Preferred Stock vote in aggregate sixty percent ( 60 50,799 In October and November of 2021, Board Member Leo Womack purchased an aggregate of 2,500 25,000

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2022
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	NOTE 12. COMMITMENTS AND CONTINGENCIES Environmental Matters – As mentioned in Note 6, the Company held a lease for acreage at SUDS Field from Joel Oppenheim. On November 4, 2022, this property was acquired by Flying M. Real Estate, and a new lease was signed by Petrolia Energy. The lease is for four years, starting at $ 500 7%

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2022
Income Tax Disclosure [Abstract]
INCOME TAXES	NOTE 13. INCOME TAXES There was no provision for income taxes for 2022 and 2021 due to net operating losses and loss carry forwards and doubt as to the entity’s ability to continue as a going concern resulting in a 100 The provision for income taxes differs from the amount computed by applying the federal statutory income tax rate of 21 21 SCHEDULE OF INCOME TAX EXPENSES Fiscal Year Ended Fiscal Year Ended Income tax (benefit) expense computed at statutory rates $ (384,000 ) $ 405,000 Non-deductible items (4,000 ) 49,000 Change in statutory, foreign tax, foreign exchange rates and other (384,000 ) (559,000 ) Change in valuation allowance 24,000 105,000 Total $ — $ — The significant components of the net deferred tax asset were as follows: SCHEDULE OF DEFERRED TAX ASSETS 2022 2021 December 31, 2022 2021 Deferred tax assets Net operating loss carryforwards $ 6,226,000 $ 6,038,000 Asset retirement obligation 508,000 498,000 Oil and gas properties (739,000 ) (593,000 ) Property and equipment — — Other — — Total deferred tax assets (liabilities) 5,995,000 5,943,000 Less: Valuation allowance ) (5,943,000 ) Net deferred tax assets (liabilities) $ — $ — A valuation allowance has been established to offset deferred tax assets. The Company’s accumulated net operating losses in the United States were approximately $ 28.5 begin to expire if not utilized beginning in the year 2033 1 expire in 2039 The Tax Cuts and Jobs Act was signed into law on December 22, 2017 and reduced the corporate income tax rate from 34% to 21%

SEGMENT REPORTING

SEGMENT REPORTING	12 Months Ended
	Dec. 31, 2022
Segment Reporting [Abstract]
SEGMENT REPORTING	NOTE 14. SEGMENT REPORTING The Company has a single SCHEDULE OF LONG-LIVED ASSETS Canada United States Total Year ended December 31, 2021 Revenue $ 5,882,499 $ 12,729 $ 5,895,228 Production costs (5,281,740 ) (65,750 ) (5,347,490 ) Depreciation, depletion, amortization and accretion (668,672 ) (51,346 ) (720,018 ) Results of operations from producing activities $ (67,913 ) $ (104,367 ) $ (172,280 ) Total long-lived assets $ 2,104,993 $ 4,244,189 $ 6,349,182 Year ended December 31, 2022 Revenue $ 6,841,721 $ 6,079 $ 6,847,800 Production costs (6,651,673 ) (138,805 ) (6,790,478 ) Depreciation, depletion, amortization and accretion (382,258 ) (29,529 ) (411,787 ) Results of operations from producing activities $ (192,210 ) $ (162,255 ) $ (354,465 ) Total long-lived assets $ 1,742,837 $ 4,243,466 $ 5,986,283 The Company’s revenues are derived from the following major customers: SCHEDULE OF REVENUES December 31, 2022 December 31, 2021 Customer A $ — $ 796,176 Customer B 6,079 12,729 Customer C 4,793,138 5,086,323 Customer D 2,048,583 — Total revenues $ 6,847,800 $ 5,895,228

SUPPLEMENTAL INFORMATION RELATI

SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)	12 Months Ended
	Dec. 31, 2022
Extractive Industries [Abstract]
SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)	NOTE 15. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Amounts reported as costs incurred include both capitalized costs and costs charged to expense during the year for oil and gas property acquisition, exploration and development activities. Costs incurred also include new ARO established in the current year, as well as increases or decreases to the ARO resulting from changes to cost estimates during the year. Exploration costs presented below include the costs of drilling and equipping successful exploration wells, as well as dry hole costs, leasehold impairments, geological and geophysical expenses, and the costs of retaining undeveloped leaseholds. Development costs include the costs of drilling and equipping development wells, and construction of related production facilities. In 2020, the Company purchased 50 678,765 906,146 1,000,000 At the time WTI price exceeded $50/bbl, the Company would pay an additional $750,000 CAD. In addition, at the time WTI price exceeded $57/bbl the Company would pay an additional $250,000 CAD (for a cumulative contingent total of $ 1,000,000 787,250 SCHEDULE OF COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION,EXPLORATION AND DEVELOPMENT Fiscal Year Ended December 31, 2022 Fiscal Year Ended December 31, 2021 Property acquisitions $ — $ 787,250 Unevaluated — — Evaluated — — Exploration — — Development — — Total costs incurred $ — $ 787,250 Capitalized costs Capitalized costs include the cost of properties, equipment and facilities for oil and natural-gas producing activities, excluding any asset retirement obligations. Capitalized costs for proved properties include costs for oil and natural-gas leaseholds where proved reserves have been identified, development wells, and related equipment and facilities, including development wells in progress. Capitalized costs for unproved properties include costs for acquiring oil and gas leaseholds and geological and geophysical expenses where no proved reserves have been identified. SCHEDULE OF CAPITALIZED COSTS IN OIL AND GAS PROPERTY ACQUISITION,EXPLORATION AND DEVELOPMENT December 31, 2022 December 31, 2021 Capitalized costs: Unevaluated properties $ — $ — Evaluated properties 5,414,771 5,511,480 Gross capitalized costs 5,414,771 5,511,480 Less: Accumulated DD&A -651,754 (448,960 ) Net capitalized costs $ 4,763,017 $ 5,062,520 Oil and Gas Reserve Information MKM Engineering (“MKM”), an independent engineering firm, prepared the estimates of the proved reserves, future production, and income attributable to the Chaves County, New Mexico and Creek County, Oklahoma and Canadian property leasehold interests as of December 31, 2022 and the estimates of the proved reserves, future production, and income attributable to the Milam County, Texas, Chaves County, New Mexico and Creek County, Oklahoma leasehold interests as of December 31, 2021. The estimated proved net recoverable reserves presented below include only those quantities that were expected to be commercially recoverable at prices and costs in effect at the balance sheet dates under the then existing regulatory practices and with conventional equipment and operating methods. Proved Developed Reserves represent only those reserves estimated to be recovered through existing wells. Proved Undeveloped Reserves include those reserves that may be recovered from new wells on undrilled acreage or from existing wells on which a relatively major expenditure for recompletion or secondary recovery operations is required. All of the Company’s Proved Reserves are located onshore in the continental United States of America and Canada. Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of oil and gas properties. Estimates of fair value should also consider unproved reserves, anticipated future oil and gas prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is subjective and imprecise. The following table sets forth estimates of the proved oil and gas reserves (net of royalty interests) for the Company and changes therein, for the periods indicated. SCHEDULE OF PROVED OIL AND GAS RESERVES BOE December 31, 2020 1,311,672 Revisions of prior estimates 292,335 Purchases of reserves in place — Disposition of mineral in place (57,070 ) Production (97,084 ) December 31, 2021 1,449,853 Revisions of prior estimates (232,950 ) Purchases of reserves in place — Disposition of mineral in place (71,380 ) Production (80,333 ) December 31, 2022 1,065,190 SCHEDULE OF PROVED DEVELOPMENT AND UNDEVELOPED RESERVES December 31, 2022 December 31, 2021 Estimated quantities of proved developed reserves – BOE 1,043,830 1,449,853 Estimated quantities of proved undeveloped reserves – BOE 21,360 — Proved developed and proved undeveloped reserves decreased from December 31, 2021 to December 31, 2022, primarily due the revision of prior estimates and production, and the removal of all Twin Lakes reserves. The following table sets forth estimates of the proved developed and proved undeveloped oil and gas reserves (net of royalty interests) for the Company and changes therein, for the period indicates. Proved developed producing and non-producing reserve BOE December 31, 2021 1,449,853 Revision of prior estimates (325,690 ) Production (80,334 ) December 31, 2022 1,043,830 Proved undeveloped reserves BOE December 31, 2021 — Revisions to prior estimates 21,360 December 31, 2022 21,360 Standardized Measure of Discounted Future Net Cash Flows The Standardized Measure related to proved oil and gas reserves is summarized below. Future cash inflows were computed by applying a twelve-month average of the first day of the month prices to estimated future production, less estimated future expenditures (based on year end costs) to be incurred in developing and producing the proved reserves, less estimated future income tax expense. Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net cash flows, less the tax basis of properties involved. Future net cash flows are discounted at a rate of 10 Standardized Measure of Oil and Gas The following table sets forth the changes in standardized measure of discounted future net cash flows relating to proved oil and gas reserves for the periods indicated. SCHEDULE OF STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS December 31, 2022 December 31, 2021 Future cash inflows $ 95,454,352 $ 93,082,624 Future production costs (49,218,382 ) (45,892,778 ) Future development costs (2,622,876 ) (1,867,485 ) Future income taxes — — Future net cash flows 43,613,094 45,322,361 Discount of future net cash flows at 10 (20,782,000 ) (27,929,984 ) Standardized measure of discounted future net cash flows $ 22,831,094 $ 17,392,377 Changes in standardized measure of discounted future cash flows SCHEDULE OF CHANGES IN STANDARDIZED MEASURE OF DISCONTINUED FUTURE CASH FLOWS December 31, 2022 December 31, 2021 Beginning of year $ 17,392,377 $ 7,956,920 Sales and transfers of oil & gas produced, net of production costs (660,629 ) (539,927 ) Net changes in prices and production costs (1,278,130 ) (865,805 ) Changes in estimated future development costs 537,696 (565,870 ) Acquisitions/dispositions of minerals in place, net of production costs (367,027 ) (231,470 ) Revision of previous estimates (11,820,528 ) 1,194,016 Change in discount — — Change in production rate or other 19,027,334 10,444,513 End of year $ 22,831,094 $ 17,392,377

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	12 Months Ended
	Dec. 31, 2022
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	NOTE 16. SUBSEQUENT EVENTS On January 11, 2023, PEC and PCC filed a motion to strike the petition in intervention by Joel Oppenheim, disclosed in Item 3. Legal Proceedings On February 3, 2023, Joel Oppenheim filed an opposition to the motion to strike. On January 31, 2023, Petrolia Canada Corporation filed a Statement of Claim in the Calgary Court of King’s Bench of Alberta naming Blue Sky Resources, Ltd. as a defendant in a lawsuit. On February 9, 2023, Edna Meyer-Nelson, Suzanne Klein, and Laura S. Ward, each a shareholder of the Company, filed a separate Petition in Intervention to join in Oppenheim’s derivative suit against the Company. On March 2, 2023, Dr. Marvin Chasen and Billie Mae Chasen, filed a separate Petition in Intervention to join in Oppenheim’s derivative suit against the Company. On January 31, 2023, Petrolia Canada Corporation filed a Statement of Claim in the Calgary Court of King’s Bench of Alberta naming Blue Sky Resources, Ltd. as a defendant in a lawsuit. On March 24, 2023, Blue Sky Resources, Ltd. filed a Statement of Defense and Counterclaim in the Calgary Court of King’s Bench of Alberta. The Court File Number is 2301-01310. On April 20, 2023, Petrolia Canada Corporation filed a Statement of Defense to Counterclaim, Reply to Defense, and Amended Statement of Claim, adding Zel Khan and Quinten Beasley as defendants in the Court File Number 2301-01310 matter filed in the Calgary Court of King’s Bench of Alberta. On May 5, 2023, the Company was notified by Blue Sky Resources (BSR), the operator of our Utikuma asset that the Province of Alberta has declared a state of emergency due to wildfires in Alberta. We were informed that because of wildfires in the vicinity of our oilfield assets, the field was shut in and all personnel were evacuated, and that the highway to the Slave Lake area has been closed. Early assessments of the situation indicate that our Utikuma facilities may have incurred major damage.

SUMMARY OF SIGNIFICANT ACCOUN_2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2022
Accounting Policies [Abstract]
Principles of consolidation	Principles of consolidation The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries, Askarii Resources and Petrolia Canada Corporation. All significant intercompany balances and transactions have been eliminated upon consolidation. The Company accounts for its investment in companies in which it has significant influence by the equity method. The Company’s proportionate share of earnings is included in earnings and added to or deducted from the cost of the investment.
Foreign currency translation	Foreign currency translation The functional and reporting currency of the Company is the United States dollar. The functional currencies of the Company’s wholly-owned subsidiaries, Askarii Resources and Petrolia Canada Corporation are the United States dollar and the Canadian dollar, respectively. Transactions involving foreign currencies are converted into the Company’s functional currency using the exchange rates in effect at the time of the transactions. At the balance sheet date, monetary assets and liabilities that are denominated in currencies other than the Company’s functional currency are translated using exchange rates at that date. Exchange gains and losses are included in net earnings. On consolidation, Petrolia Canada Corporation’s income statement amounts are translated at average exchange rates for the year, while the assets and liabilities are translated at year-end exchange rates. Translation adjustments are accumulated as a separate component of stockholders’ equity in other comprehensive income.
Management estimates	Management estimates The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates made in preparing these financial statements include depreciation of furniture, equipment and software, asset retirement obligations (“AROs”) (Note 9), income taxes (Note 13) and the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom (Note 15).
Cash and cash equivalents	Cash and cash equivalents The Company considers all highly liquid instruments purchased with an original maturity date of three months or less to be cash equivalents. As of December 31, 2022, the Company did no
Receivables and allowance for doubtful accounts	Receivables and allowance for doubtful accounts Oil revenues receivable do not bear any interest. These receivables are primarily comprised of joint interest billings. Management regularly reviews collectability and establishes or adjusts an allowance for uncollectible amounts as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. Management has determined that a reserve for uncollectible amounts was not required in the periods presented.
Oil and gas properties	Oil and gas properties The Company follows the full cost accounting method to account for oil and natural gas properties, whereby costs incurred in the acquisition, exploration and development of oil and gas reserves are capitalized. Such costs include lease acquisition, geological and geophysical activities, rentals on nonproducing leases, drilling, completing and equipping of oil and gas wells and administrative costs directly attributable to those activities and asset retirement costs. Disposition of oil and gas properties are accounted for as a reduction of capitalized costs, with no gain or loss recognized unless such adjustment would significantly alter the relationship between capital costs and proved reserves of oil and gas, in which case the gain or loss is recognized to operations. The capitalized costs of oil and gas properties, excluding unevaluated and unproved properties, are amortized as depreciation, depletion and amortization expense using the units-of-production method based on estimated proved recoverable oil and gas reserves. The costs associated with unevaluated and unproved properties, initially excluded from the amortization base, relate to unproved leasehold acreage, wells and production facilities in progress and wells pending determination of the existence of proved reserves, together with capitalized interest costs for these projects. Unproved leasehold costs are transferred to the amortization base with the costs of drilling the related well once a determination of the existence of proved reserves has been made or upon impairment of a lease. Costs associated with wells in progress and completed wells that have yet to be evaluated are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property. Costs of dry wells are transferred to the amortization base immediately upon determination that the well is unsuccessful. All items classified as unproved property are assessed on a quarterly basis for possible impairment or reduction in value. Properties are assessed on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of various factors, including, but not limited to, the following: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; assignment of proved reserves; and economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization. Under full cost accounting rules for each cost center, capitalized costs of evaluated oil and gas properties, including asset retirement costs, less accumulated amortization and related deferred income taxes, may not exceed an amount (the “cost ceiling”) equal to the sum of (a) the present value of future net cash flows from estimated production of proved oil and gas reserves, based on current prices and operating conditions, discounted at ten percent (10%), plus (b) the cost of properties not being amortized, plus (c) the lower of cost or estimated fair value of any unproved properties included in the costs being amortized, less (d) any income tax effects related to differences between the book and tax basis of the properties involved. If capitalized costs exceed this limit, the excess is charged to operations. For purposes of the ceiling test calculation, current prices are defined as the un-weighted arithmetic average of the first day of the month price for each month within the 12 month period prior to the end of the reporting period. Prices are adjusted for basis or location differentials. Unless sales contracts specify otherwise, prices are held constant for the productive life of each well. Similarly, current costs are assumed to remain constant over the entire calculation period. Given the volatility of oil and gas prices, it is reasonably possible that the estimate of discounted future net cash flows from proved oil and gas reserves could change in the near term. If oil and gas prices decline in the future, even if only for a short period of time, it is possible that impairments of oil and gas properties could occur. In addition, it is reasonably possible that impairments could occur if costs are incurred in excess of any increases in the present value of future net cash flows from proved oil and gas reserves, or if properties are sold for proceeds less than the discounted present value of the related proved oil and gas reserves.
Furniture, equipment and software	Furniture, equipment and software Furniture, equipment, and software are stated at cost, less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the related asset, generally three to five years. Fully depreciated assets are retained in property and accumulated depreciation accounts until they are removed from service. Management performs ongoing evaluations of the estimated useful lives of the property and equipment for depreciation purposes. Maintenance and repairs are expensed as incurred. Management periodically reviews long-lived assets, other than oil and gas property, for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be fully recoverable. The Company recognizes an impairment loss when the sum of expected undiscounted future cash flows is less than the carrying amount of the asset. The amount of impairment is measured as the difference between the asset’s estimated fair value and its book value.
Derivative financial instruments	Derivative financial instruments The Company’s derivative financial instruments consist of warrants with an exercise price denominated in the Company’s functional currency. These derivative financial instruments are measured at their fair value at the end of each reporting period. Changes in fair value are recorded in net income.
Asset retirement obligations	Asset retirement obligations The Company records a liability for Asset Retirement Obligations (“AROs”) associated with its oil and gas wells when those assets are placed in service. The corresponding cost is capitalized as an asset and included in the carrying amount of oil and gas properties and is depleted over the useful life of the properties. Subsequently, the ARO liability is accreted to its then-present value. Inherent in the fair value calculation of an ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance. Settlements greater than or less than amounts accrued as ARO are recorded as a gain or loss upon settlement.
Debt issuance costs	Debt issuance costs Costs incurred in connection with the issuance of long-term debt are presented as a direct deduction from the carrying value of the related debt and amortized over the term of the related debt.
Revenue recognition	Revenue recognition In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers Revenue from contracts with customers The Company recognizes revenue when it satisfies a performance obligation by transferring control over a product to a customer. Revenue is measured based on the consideration the Company expects to receive in exchange for those products. Performance obligations and significant judgments The Company sells oil and natural gas products in the United States through a single reportable segment. The Company enters into contracts that generally include one type of distinct product in variable quantities and priced based on a specific index related to the type of product. The oil and natural gas is typically sold in an unprocessed state to processors and other third parties for processing and sale to customers. The Company recognizes revenue at a point in time when control of the oil or natural gas passes to the customer or processor, as applicable, discussed below. For oil sales, control is typically transferred to the customer upon receipt at the wellhead or a contractually agreed upon delivery point. Under our natural gas contracts with processors, control transfers upon delivery at the wellhead or the inlet of the processing entity’s system. For our other natural gas contracts, control transfers upon delivery to the inlet or to a contractually agreed upon delivery point. In the cases where the Company sells to a processor, management has determined that the Company is the principal in the arrangement and the processors are customers. The Company recognizes the revenue in these contracts based on the net proceeds received from the processor. Transfer of control drives the presentation of transportation and gathering costs within the accompanying consolidated statements of operations. Transportation and gathering costs incurred prior to control transfer are recorded within the transportation and gathering expense line item on the accompanying consolidated statements of operations, while transportation and gathering costs incurred subsequent to control transfer are recorded as a reduction to the related revenue. A portion of our product sales are short-term in nature. For those contracts, the Company uses the practical expedient in Accounting Standards Codification (“ASC”) 606-10-50-14 exempting us from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For our product sales that have a contract term greater than one year, the Company has utilized the practical expedient in ASC 606-10-50-14(a) which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to an unsatisfied performance obligation. Under these sales contracts, each unit of product represents a separate performance obligation; therefore, future volumes are unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required. The Company has no unsatisfied performance obligations at the end of each reporting period. Management does not believe that significant judgments are required with respect to the determination of the transaction price, including any variable consideration identified. There is a low level of uncertainty due to the precision of measurement and use of index-based pricing with predictable differentials. Additionally, any variable consideration identified is not constrained.
Stock-based compensation	Stock-based compensation The Company accounts for stock-based compensation to employees in accordance with FASB ASC 718. Stock-based compensation
Income taxes	Income taxes Income taxes are accounted for pursuant to ASC 740, Income Taxes Uncertain tax positions are recognized in the financial statements only if that position is more likely than not of being sustained upon examination by taxing authorities, based on the technical merits of the position. The Company recognizes interest and penalties related to uncertain tax positions in the income tax provision. There are currently no unrecognized tax benefits that if recognized would affect the tax rate. There was no The Company is required to file federal income tax returns in the United States and Canada, and in various state and local jurisdictions. The Company’s tax returns are subject to examination by taxing authorities in the jurisdictions in which it operates in accordance with the normal statutes of limitations in the applicable jurisdiction.
Earnings (loss) per share	Earnings (loss) per share Basic earnings (loss) per share have been calculated based on the weighted-average number of common shares outstanding. The treasury stock method is used to compute the dilutive effect of the Company’s share-based compensation awards. Under this method, the incremental number of shares used in computing diluted earnings per share (“EPS”) is the difference between the number of shares assumed issued and purchased using assumed proceeds. Diluted EPS amounts would include the effect of outstanding stock options, warrants, and other convertible securities if including such potential shares of common stock is dilutive. Basic and diluted earnings per share are the same in all periods presented as all outstanding instruments are anti-dilutive.
Concentration of credit risk	Concentration of credit risk The Company is subject to credit risk resulting from the concentration of its oil receivables with significant purchasers. Three purchasers accounted for all of the Company’s oil sales revenues for 2022 and 2021. The Company does not require collateral. While the Company believes its recorded receivables will be collected, in the event of default the Company would follow normal collection procedures. The Company does not believe the loss of a purchaser would materially impact its operating results as oil is a fungible product with a well-established market and numerous purchasers. At times, the Company maintains deposits in federally insured financial institutions in excess of federally insured limits. Management monitors the credit ratings and concentration of risk with these financial institutions on a continuing basis to safeguard cash deposits.
Fair value measurements	Fair value measurements Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (i.e., the “exit price”) in an orderly transaction between market participants at the measurement date. The hierarchy is broken down into three levels based on the observability of inputs as follows: ● Level 1 — Valuations based on quoted prices in active markets for identical assets or liabilities that the Company has the ability to access. Valuation adjustments and block discounts are not applied to Level 1 instruments. Since valuations are based on quoted prices that are readily and regularly available in an active market, valuation of these products does not entail a significant degree of judgment; ● Level 2 — Valuations based on one or more quoted prices in markets that are not active or for which all significant inputs are observable, either directly or indirectly; and ● Level 3 — Valuations based on inputs that are unobservable and significant to the overall fair value measurement. Our derivative liabilities are measured at fair value on a recurring basis and estimated as follows: SCHEDULE OF DERIVATIVE LIABILITIES MEASURED AT FAIR VALUE ON RECURRING BASIS December 31, 2021 Level 1 Level 2 Level 3 Total Derivative liabilities $ — $ — $ 22,554 $ 22,554 ARO liabilities $ — $ — 2,257,027 $ 2,257,027 December 31, 2022 Derivative liabilities $ — $ — $ — $ — ARO liabilities $ — $ — $ 2,301,335 $ 2,301,335 The carrying value of cash, accounts receivable, other current assets, accounts payable, accounts payable – related parties, accrued liabilities and accrued liabilities – related parties, as reflected in the consolidated balance sheets, approximate fair value, due to the short-term maturity of these instruments. The carrying value of notes payable approximates their fair value due to immaterial changes in market interest rates and the Company’s credit risk since issuance of the instruments or due to their short-term nature. Derivative liabilities are remeasured at fair value every reporting period. Our derivative liabilities are considered level 3 financial instruments.
Related parties	Related parties The Audit Committee approves all material related party transactions. The Audit Committee is provided with the details of each new, existing or proposed related party transaction, including the terms of the transaction, the business purpose of the transaction, and the benefits to the Company and the relevant related party. In determining whether to approve a related party transaction, the following factors are considered: (1) if the terms are fair to the Company, (2) if there are business reasons to enter into the transaction, (3) if the transaction would impair independence of an outside Director, or (4) if the transaction would present an improper conflict of interest for any Director or executive officer. Any member of the Audit Committee who has an interest in the transaction will abstain from voting on the approval of the related party transaction.
Business combinations	Business combinations In January 2017, the FASB issued ASU 2017-01 Business Combinations Clarifying the Definition of a Business
Reclassifications	Reclassifications Certain amounts previously presented for prior periods have been reclassified to conform to the current presentation. The reclassifications had no effect on net loss, working capital or equity previously reported.
Recent accounting pronouncements	Recent accounting pronouncements The Company has evaluated all the recent accounting pronouncements through the filing date and believes that none of them will have a material effect on the Company.

SUMMARY OF SIGNIFICANT ACCOUN_3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2022
Accounting Policies [Abstract]
SCHEDULE OF DERIVATIVE LIABILITIES MEASURED AT FAIR VALUE ON RECURRING BASIS	Our derivative liabilities are measured at fair value on a recurring basis and estimated as follows: SCHEDULE OF DERIVATIVE LIABILITIES MEASURED AT FAIR VALUE ON RECURRING BASIS December 31, 2021 Level 1 Level 2 Level 3 Total Derivative liabilities $ — $ — $ 22,554 $ 22,554 ARO liabilities $ — $ — 2,257,027 $ 2,257,027 December 31, 2022 Derivative liabilities $ — $ — $ — $ — ARO liabilities $ — $ — $ 2,301,335 $ 2,301,335

EVALUATED PROPERTIES (Tables)

EVALUATED PROPERTIES (Tables)	12 Months Ended
	Dec. 31, 2022
Extractive Industries [Abstract]
SCHEDULE OF ACQUIRED PROPERTIES AND CURRENT PROPERTIES	The acquired properties and current properties can be summarized as follows: SCHEDULE OF ACQUIRED PROPERTIES AND CURRENT PROPERTIES Cost Canadian properties US properties Total As of December 31, 2020 $ 4,314,805 $ 4,304,622 $ 8,619,427 Additions 787,250 — 787,250 Dispositions (2,563,434 ) — (2,563,434 ) Foreign currency translation (46,218 ) — (46,218 ) As of December 31, 2021 $ 2,492,403 $ 4,304,622 $ 6,797,025 Additions — — — Dispositions — 375 375 Foreign currency translation (159,363 ) — (159,363 ) As of December 31, 2022 $ 2,333,040 $ 4,304,997 $ 6,638,037 Accumulated depletion As of December 31, 2020 2,631,749 $ 61,551 $ 2,693,300 Dispositions (2,629,672 ) — (2,629,672 ) Depletion 378,306 — 378,306 Foreign currency translation 7,026 — 7,026 As of December 31, 2021 $ 387,409 $ 61,551 $ 448,960 Depletion 237,067 — 237,067 Foreign currency translation (34,273 ) — (34,273 ) As of December 31, 2022 $ 590,203 $ 61,551 $ 651,754 Net book value as at December 31, 2022 $ 1,742,837 $ 4,243,446 $ 5,986,283 Net book value as at December 31, 2021 $ 2,104,994 $ 4,243,071 $ 6,348,065

NOTES PAYABLE (Tables)

NOTES PAYABLE (Tables)	12 Months Ended
	Dec. 31, 2022
Debt Disclosure [Abstract]
SCHEDULE OF NOTES PAYABLE	SCHEDULE OF NOTES PAYABLE Interest rate Date of maturity December 31, 2022 December 31, 2021 Truck loan (ii) 5.49 % January 20, 2022 $ — $ 4,021 Credit note I (iii) 10 % January 01, 2020 426,909 831,387 Discount on credit note I (41,572 ) (97,001 ) Credit note II (iv) 10 % December 31, 2022 — 2,085,432 Lee Lytton On demand 3,500 3,500 Credit note III (v) 10 % December 31, 2021 — 416,900 Quinten Beasley (vi) 10 % October 14, 2016 — 5,000 Jovian Petroleum Corporation (vii) 3.5 % December 31, 2021 — 178,923 M. Horowitz 10 % October 14, 2016 10,000 10,000 $ 398,837 (1) $ 3,438,162 (i) All notes are current (due within one year or less from December 31, 2022.) (ii) On January 6, 2017, the Company purchased a truck and entered into an installment note in the amount of $ 35,677 five years 5.49% 683 (iii) On January 2, 2020, the Company entered into a loan agreement in the amount of $ 1,000,000 120,000 10% June 30, 2020 5,000,000 0.10 January 2, 2023 266,674 11,111 5,000,000 0.05 January 6, 2023 166,289 4,614.14 (iv) On December 1, 2021, the Company signed an amended loan agreement with a third party for $ 2,085,432 10% December 31, 2022 25% (v) Various shareholder advances were provided by Joel. Oppenheim during 2018 and 2019. There were no formal documents drawn. Interest rates were applied based on other similar loan agreements entered into by the Company during that period. On February 12, 2021, the Company entered into an amended loan agreement in the amount of $ 416,900 10% December 31, 2021 (vi) This note was reclassified to Notes Payable – Related Party, due to Mr. Beasley’s beneficial ownership of our common stock. See Note 7. Related Party Notes Payable. (vii) On February 9, 2018, the Company entered into a Revolving Line of Credit Agreement (“LOC”) for $ 200,000 500,000 25% 3.5%
SCHEDULE OF FUTURE MINIMUM REPAYMENTS OF NOTES PAYABLE	The following is a schedule of future minimum repayments of notes payable as of December 31, 2022: SCHEDULE OF FUTURE MINIMUM REPAYMENTS OF NOTES PAYABLE 2023 $ 440,409 Thereafter — Total $ 440,409

LEASES (Tables)

LEASES (Tables)	12 Months Ended
	Dec. 31, 2022
Leases
SCHEDULE OF FINANCIAL INFORMATION LEASE	The tables below present financial information associated with our lease. SCHEDULE OF FINANCIAL INFORMATION LEASE Balance Sheet Classification December 31, 2022 December 31, 2021 Right-of-use assets Other long-term assets 23,086 12,821 Current lease liabilities Other current liabilities 5,482 13,909 Non-current lease liabilities Other long-term liabilities 17,714 —
SCHEDULE OF MATURITIES LEASE LIABILITY	As of December 31, 2022, our maturities of our lease liability are as follows: SCHEDULE OF MATURITIES LEASE LIABILITY 2023 $ 5,482 2024 5,714 2025 6,539 2026 5,400 Total $ 23,196 Less: Imputed interest (110 ) Present value of lease liabilities $ 23,086

RELATED PARTY NOTES PAYABLE (Ta

RELATED PARTY NOTES PAYABLE (Tables)	12 Months Ended
	Dec. 31, 2022
Related Party Notes Payable
SCHEDULE OF RELATED PARTY NOTES PAYABLE	The chart below summarizes the related party Notes Payable as of December 31, 2022 and 2021. SCHEDULE OF RELATED PARTY NOTES PAYABLE Interest rate Date of maturity December 31, 2022 December 31, 2021 Quinten Beasley 10 % October 14, 2016 5,000 — Blue Sky Resources (i) 3.5 % December 31, 2021 178,923 — Blue Sky Resources (ii) 10 % December 31, 2021 150,000 — Blue Sky Resources (iii) 10 % December 31, 2022 2,085,432 — Ivar Siem (iv) 9 % December 31, 2021 278,435 278,435 Mark Allen (v) 9 % September 2, 2021 55,000 55,000 Mark Allen (vi) 12 % June 30, 2020 200,000 200,000 Mark Allen (vii) 9 % June 30, 2021 241,125 245,938 Joel Oppenheim (viii) 10 % December 31, 2021 266,900 — $ 3,460,815 $ 779,373 (i) On February 9, 2018, the Company entered into a Revolving Line of Credit Agreement (“LOC”) for $ 200,000 500,000 25% 3.5% (ii) On February 3, 2022, Joel Oppenheim assigned $150,000 of his note, shown as Credit Note II in Note 5. Notes Payable to Blue Sky Resources. (iii) On December 1, 2021, the Company signed an amended loan agreement with a third party for $ 2,085,432 10% December 31, 2022 25% (iv) On August 15, 2019, the Company entered into a loan agreement in the amount of $ 75,000 12% 100,000 12% 1,250,000 0.08 5,000,000 0.10 50,000 0% 200,000 0.10 March 1, 2022 278,435 9% December 31, 2021 (v) On April 15, 2020, the Company entered into an agreement, with Mark Allen, that included a funding clause where the Company borrowed $ 55,000 9% September 2, 2021 (vi) During 2019, the Company entered into a loan agreement in the amount of $ 200,000 12% June 30, 2020 2,500,000 0.08 10,000,000 0.10 (vii) On January 3, 2020, the Company entered into a loan agreement in the amount of $ 100,000 10% June 1, 2020 400,000 0.10 January 3, 2023 31,946 1,775 125,000 10 June 1, 2020 750,000 0.10 February 14, 2022 38,249 1,903 245,938 9% June 30, 2021 (viii) Various shareholder advances were provided by Joel. Oppenheim during 2018 and 2019. There were no formal documents drawn. Interest rates were applied based on other similar loan agreements entered into by the Company during that period. On February 12, 2021, the Company entered into an amended loan agreement in the amount of $416,900 that consolidated these amounts. The loan bears interest at 10% per annum and has a maturity date of December 31, 2021. On August 31, 2021, this loan was in default due to missed interest payments, and a default interest rate was applied to the principal balance. On February 3, 2022, $150,000 of this note was assigned to Blue Sky Resources. The remaining balance has been moved to Notes Payable – Related Party due to Mr. Oppenheim’s beneficial ownership of our common stock.
SCHEDULE OF FUTURE MINIMUM REPAYMENTS OF RELATED PARTY NOTES PAYABLE	The following is a schedule of future minimum repayments of related party notes payable as of December 31, 2022: SCHEDULE OF FUTURE MINIMUM REPAYMENTS OF RELATED PARTY NOTES PAYABLE 2023 $ 3,460,815 Thereafter — Total $ 3,460,815

DERIVATIVE FINANCIAL INSTRUME_2

DERIVATIVE FINANCIAL INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2022
Investments, All Other Investments [Abstract]
SCHEDULE OF DERIVATIVE LIABILITIES	A summary of the activity of the derivative liabilities is shown below: SCHEDULE OF DERIVATIVE LIABILITIES Balance, December 31, 2021 $ 22,554 Additions — Fair value adjustments (22,554 ) As of December 31, 2022 $ —
SCHEDULE OF DERIVATIVE LIABILITY OF FAIR VALUE ASSUMPTION	SCHEDULE OF DERIVATIVE LIABILITY OF FAIR VALUE ASSUMPTION December 31, 2022 Risk-free interest rate 4.12 % Expected life 0 Expected dividend rate 0 % Expected volatility 267 %

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2022
Asset Retirement Obligation Disclosure [Abstract]
SCHEDULE OF FAIR VALUE OF ASSET RETIREMENT OBLIGATIONS	SCHEDULE OF FAIR VALUE OF ASSET RETIREMENT OBLIGATIONS December 31, 2022 Inflation rate 1.92 2.15 % Estimated asset life 12 22
SCHEDULE OF CHANGE IN ASSET RETIREMENT OBLIGATIONS	The following table shows the change in the Company’s ARO liability for the years ended December 31, 2022, and 2021: SCHEDULE OF CHANGE IN ASSET RETIREMENT OBLIGATIONS Canadian properties United States properties Total Asset retirement obligations, December 31, 2020 $ 2,711,909 $ 912,225 $ 3,624,133 Plugging liability at Twin Lakes — 152,000 132,000 Accretion expense 290,367 26,506 316,873 Disposition (1,824,339 ) — (1,824,339 ) Foreign currency translation 8,360 — 8,360 Asset retirement obligations, December 31, 2021 $ 1,186,297 $ 1,070,730 $ 2,257,027 Plugging liability at Twin Lakes — — — Accretion expense 145,191 28,412 173,603 Disposition — (47,624 ) (47,624 ) Foreign currency translation (81,671 ) — (81,671 ) Asset retirement obligations, December 31, 2022 $ 1,249,816 $ 1,051,518 $ 2,301,335

EQUITY (Tables)

EQUITY (Tables)	12 Months Ended
	Dec. 31, 2022
Equity [Abstract]
SCHEDULE Of COMMON STOCK PURCHASE WARRANTS ISSUED AND OUTSTANDING	Continuity of the Company’s common stock purchase warrants issued and outstanding is as follows: SCHEDULE Of COMMON STOCK PURCHASE WARRANTS ISSUED AND OUTSTANDING Warrants Weighted average exercise price Outstanding at year ended December 31, 2020 40,764,666 $ 0.13 Granted 9,400,000 0.09 Expired (20,464,666 ) 0.11 Outstanding at year ended December 31, 2021 29,700,000 0.13 Granted 1,000,000 0.10 Expired (6,730,000 ) 0.11 Outstanding at year ended December 31, 2022 23,970,000 0.13
SCHEDULE OF WARRANTS ISSUANCE DURING PERIOD	The table below summarizes warrant issuances during the years ended December 31, 2022, and 2021: SCHEDULE OF WARRANTS ISSUANCE DURING PERIOD Year ended December 31, 2022 2021 Warrants granted: Board of directors and advisory board service — 3,000,000 Pursuant to financing arrangements 1,000,000 1,000,000 Pursuant to loan agreements — 5,400,000 Total 1,000,000 9,400,000
SCHEDULE OF FAIR VALUE OF ASSUMPTION OF WARRANTS	Warrants granted in the years ended December 31, 2022, and 2021 were valued using the Black Scholes Option Pricing Model with the range of assumptions outlined below. Expected life was determined based on historical exercise data of the Company. SCHEDULE OF FAIR VALUE OF ASSUMPTION OF WARRANTS December 31, 2022 December 31, 2021 Risk-free interest rate 2.49 4.22 % 0.16 0.97 % Expected life 3.0 2.0 3.0 Expected dividend rate 0 % 0 % Expected volatility 267 299 % 277 356 %

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2022
Income Tax Disclosure [Abstract]
SCHEDULE OF INCOME TAX EXPENSES	The provision for income taxes differs from the amount computed by applying the federal statutory income tax rate of 21 21 SCHEDULE OF INCOME TAX EXPENSES Fiscal Year Ended Fiscal Year Ended Income tax (benefit) expense computed at statutory rates $ (384,000 ) $ 405,000 Non-deductible items (4,000 ) 49,000 Change in statutory, foreign tax, foreign exchange rates and other (384,000 ) (559,000 ) Change in valuation allowance 24,000 105,000 Total $ — $ —
SCHEDULE OF DEFERRED TAX ASSETS	The significant components of the net deferred tax asset were as follows: SCHEDULE OF DEFERRED TAX ASSETS 2022 2021 December 31, 2022 2021 Deferred tax assets Net operating loss carryforwards $ 6,226,000 $ 6,038,000 Asset retirement obligation 508,000 498,000 Oil and gas properties (739,000 ) (593,000 ) Property and equipment — — Other — — Total deferred tax assets (liabilities) 5,995,000 5,943,000 Less: Valuation allowance ) (5,943,000 ) Net deferred tax assets (liabilities) $ — $ —

SEGMENT REPORTING (Tables)

SEGMENT REPORTING (Tables)	12 Months Ended
	Dec. 31, 2022
Segment Reporting [Abstract]
SCHEDULE OF LONG-LIVED ASSETS	SCHEDULE OF LONG-LIVED ASSETS Canada United States Total Year ended December 31, 2021 Revenue $ 5,882,499 $ 12,729 $ 5,895,228 Production costs (5,281,740 ) (65,750 ) (5,347,490 ) Depreciation, depletion, amortization and accretion (668,672 ) (51,346 ) (720,018 ) Results of operations from producing activities $ (67,913 ) $ (104,367 ) $ (172,280 ) Total long-lived assets $ 2,104,993 $ 4,244,189 $ 6,349,182 Year ended December 31, 2022 Revenue $ 6,841,721 $ 6,079 $ 6,847,800 Production costs (6,651,673 ) (138,805 ) (6,790,478 ) Depreciation, depletion, amortization and accretion (382,258 ) (29,529 ) (411,787 ) Results of operations from producing activities $ (192,210 ) $ (162,255 ) $ (354,465 ) Total long-lived assets $ 1,742,837 $ 4,243,466 $ 5,986,283
SCHEDULE OF REVENUES	The Company’s revenues are derived from the following major customers: SCHEDULE OF REVENUES December 31, 2022 December 31, 2021 Customer A $ — $ 796,176 Customer B 6,079 12,729 Customer C 4,793,138 5,086,323 Customer D 2,048,583 — Total revenues $ 6,847,800 $ 5,895,228

SUPPLEMENTAL INFORMATION RELA_2

SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2022
Extractive Industries [Abstract]
SCHEDULE OF COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION,EXPLORATION AND DEVELOPMENT	SCHEDULE OF COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION,EXPLORATION AND DEVELOPMENT Fiscal Year Ended December 31, 2022 Fiscal Year Ended December 31, 2021 Property acquisitions $ — $ 787,250 Unevaluated — — Evaluated — — Exploration — — Development — — Total costs incurred $ — $ 787,250
SCHEDULE OF CAPITALIZED COSTS IN OIL AND GAS PROPERTY ACQUISITION,EXPLORATION AND DEVELOPMENT	SCHEDULE OF CAPITALIZED COSTS IN OIL AND GAS PROPERTY ACQUISITION,EXPLORATION AND DEVELOPMENT December 31, 2022 December 31, 2021 Capitalized costs: Unevaluated properties $ — $ — Evaluated properties 5,414,771 5,511,480 Gross capitalized costs 5,414,771 5,511,480 Less: Accumulated DD&A -651,754 (448,960 ) Net capitalized costs $ 4,763,017 $ 5,062,520
SCHEDULE OF PROVED OIL AND GAS RESERVES	The following table sets forth estimates of the proved oil and gas reserves (net of royalty interests) for the Company and changes therein, for the periods indicated. SCHEDULE OF PROVED OIL AND GAS RESERVES BOE December 31, 2020 1,311,672 Revisions of prior estimates 292,335 Purchases of reserves in place — Disposition of mineral in place (57,070 ) Production (97,084 ) December 31, 2021 1,449,853 Revisions of prior estimates (232,950 ) Purchases of reserves in place — Disposition of mineral in place (71,380 ) Production (80,333 ) December 31, 2022 1,065,190
SCHEDULE OF PROVED DEVELOPMENT AND UNDEVELOPED RESERVES	SCHEDULE OF PROVED DEVELOPMENT AND UNDEVELOPED RESERVES December 31, 2022 December 31, 2021 Estimated quantities of proved developed reserves – BOE 1,043,830 1,449,853 Estimated quantities of proved undeveloped reserves – BOE 21,360 — Proved developed and proved undeveloped reserves decreased from December 31, 2021 to December 31, 2022, primarily due the revision of prior estimates and production, and the removal of all Twin Lakes reserves. The following table sets forth estimates of the proved developed and proved undeveloped oil and gas reserves (net of royalty interests) for the Company and changes therein, for the period indicates. Proved developed producing and non-producing reserve BOE December 31, 2021 1,449,853 Revision of prior estimates (325,690 ) Production (80,334 ) December 31, 2022 1,043,830 Proved undeveloped reserves BOE December 31, 2021 — Revisions to prior estimates 21,360 December 31, 2022 21,360
SCHEDULE OF STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS	The following table sets forth the changes in standardized measure of discounted future net cash flows relating to proved oil and gas reserves for the periods indicated. SCHEDULE OF STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS December 31, 2022 December 31, 2021 Future cash inflows $ 95,454,352 $ 93,082,624 Future production costs (49,218,382 ) (45,892,778 ) Future development costs (2,622,876 ) (1,867,485 ) Future income taxes — — Future net cash flows 43,613,094 45,322,361 Discount of future net cash flows at 10 (20,782,000 ) (27,929,984 ) Standardized measure of discounted future net cash flows $ 22,831,094 $ 17,392,377
SCHEDULE OF CHANGES IN STANDARDIZED MEASURE OF DISCONTINUED FUTURE CASH FLOWS	Changes in standardized measure of discounted future cash flows SCHEDULE OF CHANGES IN STANDARDIZED MEASURE OF DISCONTINUED FUTURE CASH FLOWS December 31, 2022 December 31, 2021 Beginning of year $ 17,392,377 $ 7,956,920 Sales and transfers of oil & gas produced, net of production costs (660,629 ) (539,927 ) Net changes in prices and production costs (1,278,130 ) (865,805 ) Changes in estimated future development costs 537,696 (565,870 ) Acquisitions/dispositions of minerals in place, net of production costs (367,027 ) (231,470 ) Revision of previous estimates (11,820,528 ) 1,194,016 Change in discount — — Change in production rate or other 19,027,334 10,444,513 End of year $ 22,831,094 $ 17,392,377

SCHEDULE OF DERIVATIVE LIABILIT

SCHEDULE OF DERIVATIVE LIABILITIES MEASURED AT FAIR VALUE ON RECURRING BASIS (Details) - USD ($)	Dec. 31, 2022	Dec. 31, 2021
Defined Benefit Plan Disclosure [Line Items]
Derivative liabilities		$ 22,554
Fair Value, Recurring [Member]
Defined Benefit Plan Disclosure [Line Items]
Derivative liabilities		22,554
ARO liabilities	2,301,335	2,257,027
Fair Value, Inputs, Level 1 [Member] | Fair Value, Recurring [Member]
Defined Benefit Plan Disclosure [Line Items]
Derivative liabilities
ARO liabilities
Fair Value, Inputs, Level 2 [Member] | Fair Value, Recurring [Member]
Defined Benefit Plan Disclosure [Line Items]
Derivative liabilities
ARO liabilities
Fair Value, Inputs, Level 3 [Member] | Fair Value, Recurring [Member]
Defined Benefit Plan Disclosure [Line Items]
Derivative liabilities		22,554
ARO liabilities	$ 2,301,335	$ 2,257,027

SUMMARY OF SIGNIFICANT ACCOUN_4

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Accounting Policies [Abstract]
Cash equivalents	$ 0
Income tax, interest or penalties	$ 0	$ 0

SCHEDULE OF ACQUIRED PROPERTIES

SCHEDULE OF ACQUIRED PROPERTIES AND CURRENT PROPERTIES (Details) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Property, Plant and Equipment [Line Items]
Evaluated properties cost, beginning balance	$ 6,797,025	$ 8,619,427
Evaluated properties cost, Additions		787,250
Evaluated properties cost, Disposition	375	(2,563,434)
Evaluated properties cost, Foreign currency translation	(159,363)	(46,218)
Evaluated properties cost, ending balance	6,638,037	6,797,025
Evaluated properties accumulated depletion, beginning balance	448,960	2,693,300
Evaluated properties accumulated depletion, Dispositions		(2,629,672)
Evaluated properties accumulated depletion, Depletion	237,067	378,306
Evaluated properties accumulated depletion, Foreign currency translation	(34,273)	7,026
Evaluated properties accumulated depletion, ending balance	651,754	448,960
Net book value as at ending balance	5,986,283	6,348,065
Canadian Properties [Member]
Property, Plant and Equipment [Line Items]
Evaluated properties cost, beginning balance	2,492,403	4,314,805
Evaluated properties cost, Additions		787,250
Evaluated properties cost, Disposition		(2,563,434)
Evaluated properties cost, Foreign currency translation	(159,363)	(46,218)
Evaluated properties cost, ending balance	2,333,040	2,492,403
Evaluated properties accumulated depletion, beginning balance	387,409	2,631,749
Evaluated properties accumulated depletion, Dispositions		(2,629,672)
Evaluated properties accumulated depletion, Depletion	237,067	378,306
Evaluated properties accumulated depletion, Foreign currency translation	(34,273)	7,026
Evaluated properties accumulated depletion, ending balance	590,203	387,409
Net book value as at ending balance	1,742,837	2,104,994
US Properties [Member]
Property, Plant and Equipment [Line Items]
Evaluated properties cost, beginning balance	4,304,622	4,304,622
Evaluated properties cost, Additions
Evaluated properties cost, Disposition	375
Evaluated properties cost, Foreign currency translation
Evaluated properties cost, ending balance	4,304,997	4,304,622
Evaluated properties accumulated depletion, beginning balance	61,551	61,551
Evaluated properties accumulated depletion, Dispositions
Evaluated properties accumulated depletion, Depletion
Evaluated properties accumulated depletion, Foreign currency translation
Evaluated properties accumulated depletion, ending balance	61,551	61,551
Net book value as at ending balance	$ 4,243,446	$ 4,243,071

EVALUATED PROPERTIES (Details N

EVALUATED PROPERTIES (Details Narrative)

12 Months Ended

Feb. 16, 2022 USD ($)

Feb. 16, 2022 CAD ($)

Oct. 31, 2021 CAD ($)

Sep. 30, 2021 CAD ($)

Aug. 21, 2021 USD ($)

Aug. 21, 2021 CAD ($) a

Jul. 06, 2021 USD ($)

Dec. 02, 2020 CAD ($)

May 01, 2020 a

Aug. 06, 2019 USD ($)

Apr. 15, 2019 USD ($)

Nov. 02, 2018 USD ($)

Sep. 17, 2018 USD ($)

Jun. 08, 2018

Jun. 01, 2018 USD ($)

Jun. 01, 2018 CAD ($)

May 09, 2018 USD ($)

Dec. 31, 2022 CAD ($)

Dec. 31, 2020 USD ($)

Dec. 31, 2022 USD ($) a MBoe

Dec. 31, 2021 USD ($)

Dec. 31, 2021 CAD ($)

Feb. 12, 2021 USD ($)

Feb. 28, 2020 USD ($)

Jan. 02, 2020 USD ($)

Sep. 30, 2019 USD ($)

Aug. 15, 2019 USD ($)

Dec. 31, 2018 USD ($)

Jun. 29, 2018 a

Jun. 01, 2018 CAD ($)

Reserve Quantities [Line Items]

Increased working interest

50%

Estimated cost

$ 5,986,283

$ 6,348,065

Area of land | a

28,000

Increased working interest

28%

Acquisition Note [Member]

Reserve Quantities [Line Items]

Debt interest rate

9%

Debt instrument description

extend the maturity date for a period six months with 10 days’ notice to Blue Sky, in the event the Company pays 25% of the principal amount of the Acquisition Note at the time of extension.

Slick Unit Dutcher Sand (“SUDS”) Field [Member]

Reserve Quantities [Line Items]

Net revenue interest percent

76.50%

Increased working interest

100%

Area of land | a

2,530

Net proved reserves | MBoe

346

Net probable reserves | MBoe

153

Acquired field description

The SUDS field is currently shut-in while the Company completes a review of the land and lease records currently being conducted by a petroleum landman. PEC has also initiated a detailed reservoir and historical waterflood sweeping pattern analysis. The Company is currently awaiting the outcome of the review of the SUDS subsurface geology. PEC is finalizing a SUDS capital budget with the intent to commence further field development in Q3 2023.

Slick Unit Dutcher Sand (“SUDS”) West [Member]

Reserve Quantities [Line Items]

Area of land | a

1,670

Slick Unit Dutcher Sand (“SUDS”) East [Member]

Reserve Quantities [Line Items]

Area of land | a

860

Twin Lakes San Andres Unit (“TLSAU”) [Member]

Reserve Quantities [Line Items]

Estimated cost

$ 1,200,000

Blue Sky [Member]

Reserve Quantities [Line Items]

Increased working interest

3%

80%

Purchase price

$ 1,096,216

$ 1,428,581

Cash payment

782,441

$ 1,022,400

Cash payment for working interest acquired

$ 150,000

Business combination, description

The total purchase price of the property was $2,000,000 (CAD), with $1,000,000 of that total due initially. The additional $1,000,000 was contingent on the future price of WTI crude. At the time WTI price exceeded $50/bbl, the Company would pay an additional $750,000 CAD. In addition, at the time WTI price exceeded $57/bbl the Company would pay an additional $250,000 CAD (for a cumulative contingent total of $1,000,000 CAD). The price of WTI crude exceeded $50/bbl on January 6, 2021 and exceeded $57/bbl on February 8, 2021. The additional payments due were netted with the accounts receivable balance from previous Joint Interest Billing statements from BSR. The total USD value of the addition was $787,250, using prevailing exchange rates on the respective dates. Included in the terms of the agreement, the Company also funded their portion of the Alberta Energy Regulator (“AER”) bond fund requirement $763,754 CAD ($563,904 USD), necessary for the wells to continue in production after the acquisition. Additional funds in the amount of $490,624 CAD ($362,245 USD) remain in the other current asset balance for future payments to BSR, related to the acquisition

Proceeds from secured royalty interest

$ 602,404.84

Blue Sky [Member] | Acquisition Note [Member]

Reserve Quantities [Line Items]

Debt instrument face amount

$ 313,775

$ 406,181

Amended and Restated Loan Agreement [Member]

Reserve Quantities [Line Items]

Cash payment for working interest acquired

$ 1,530,000

Loan Agreement [Member]

Reserve Quantities [Line Items]

Debt instrument face amount

$ 416,900

$ 50,000

$ 1,000,000

Debt interest rate

12%

10%

0%

10%

12%

Debt default percentage

19%

19%

Letter Agreement [Member]

Reserve Quantities [Line Items]

Area of land | a

28,000

Prospera Energy [Member] | Purchase and Sale Agreement and Debt Settlement Agreement [Member]

Reserve Quantities [Line Items]

Increased working interest

28%

Debt Instrument, Decrease, Forgiveness

$ 2,061,614

Convertible Debt

$ 510,000

Repayments of Convertible Debt

75,000

Assets consideration

1,622,756

Additional assets retirement cost recognized

1,711,142

Asset Retirement Obligation

2,312,897

Depletion

3,333,898

Gain on assets acquisition

$ 3,919,323

$ 4,959,512

Petrolia Canada Corporation [Member] | Letter Agreement [Member]

Reserve Quantities [Line Items]

Increased working interest

50%

Area of land | a

28,000

Assets consideration

$ 5,150,000

$ 6,500,000

Non-refundable deposit

$ 200,000

Payments to acquire property

$ 1,000,000

$ 2,000,000

Acquisition liability

$ 3,300,000

Other income

$ 200,000

Petrolia Canada Corporation [Member] | Letter Agreement [Member] | Blue Sky [Member]

Reserve Quantities [Line Items]

Increased working interest

28%

NOACK [Member] | Purchase and Sale Agreement [Member] | FlowTex Energy L.L.C. [Member]

Reserve Quantities [Line Items]

Proceeds from 2nd NOACK sale

$ 375,000

Deposit

$ 380,000

$ 20,000

Receivable for the sale

$ 25,000

25,000

Debt payment principal

$ 400,000

Gain on sale of properties

$ 400,000

Remitted a cash payment

8,995

Outstanding property tax

$ 16,005

NOACK [Member] | Crossroads Petroleum L.L.C. [Member]

Reserve Quantities [Line Items]

Net revenue interest percent

83%

Increased working interest

100%

Proceeds from 2nd NOACK sale

$ 375,000

Deposit

$ 260,000

$ 115,000

Receivable for the sale

$ 120,000

Payments for previous acquisitions forfeited

$ 255,000

Luseland, Hearts Hill and Cuthbert Fields [Member]

Reserve Quantities [Line Items]

Increased working interest

25%

Area of land | a

41,526

Vermilion Energy Inc [Member]

Reserve Quantities [Line Items]

Increased working interest

100%

SCHEDULE OF NOTES PAYABLE (Deta

SCHEDULE OF NOTES PAYABLE (Details) - USD ($)		12 Months Ended
		Dec. 31, 2022		Dec. 31, 2021	Jan. 06, 2017
Short-Term Debt [Line Items]
Notes payable		$ 398,837	[1]	$ 3,438,162
Truck Loan [Member]
Short-Term Debt [Line Items]
Interest rate		5.49%	[2]		5.49%
Date of maturity	[2]	Jan. 20, 2022
Notes payable	[2]			4,021
Notes payable					$ 683
Credit Note I [Member]
Short-Term Debt [Line Items]
Interest rate	[3]	10%
Date of maturity	[3]	Jan. 01, 2020
Notes payable	[3]	$ 426,909		831,387
Discount On Credit Note One [Member]
Short-Term Debt [Line Items]
Discount		$ (41,572)		(97,001)
Credit Note VI [Member]
Short-Term Debt [Line Items]
Interest rate	[4]	10%
Date of maturity	[4]	Dec. 31, 2022
Notes payable	[4]			2,085,432
Lee Lytton [Member]
Short-Term Debt [Line Items]
Notes payable		$ 3,500		3,500
Date of maturity		On demand
One Credit Note Six [Member]
Short-Term Debt [Line Items]
Interest rate		10%
Date of maturity		Dec. 31, 2021
Notes payable				416,900
Quinten Beasley [Member]
Short-Term Debt [Line Items]
Interest rate		10%
Date of maturity		Oct. 14, 2016
Notes payable				5,000
Jovian Petroleum Corporation [Member]
Short-Term Debt [Line Items]
Interest rate		3.50%
Date of maturity		Dec. 31, 2021
Notes payable				178,923
M Horowitz [Member]
Short-Term Debt [Line Items]
Interest rate		10%
Date of maturity		Oct. 14, 2016
Notes payable		$ 10,000		$ 10,000
[1]All notes are current (due within one year or less from December 31, 2022.)[2]On January 6, 2017, the Company purchased a truck and entered into an installment note in the amount of $ 35,677 five years 5.49% 683 2,085,432 10% December 31, 2022 25% 200,000 500,000 25% 3.5%

SCHEDULE OF NOTES PAYABLE (De_2

SCHEDULE OF NOTES PAYABLE (Details) (Parenthetical)

12 Months Ended

Dec. 01, 2021 USD ($)

Feb. 12, 2021 USD ($)

Oct. 30, 2020 USD ($) $ / shares shares

Jan. 02, 2020 USD ($) shares

Jan. 06, 2017 USD ($)

Dec. 31, 2022 USD ($)

Dec. 31, 2021 USD ($)

May 01, 2020

Feb. 28, 2020 USD ($) shares

Feb. 28, 2020 $ / shares

Jan. 02, 2020 $ / shares

Jun. 01, 2018

Apr. 12, 2018 USD ($)

Feb. 19, 2018

Feb. 09, 2018 USD ($)

Short-Term Debt [Line Items]

Notes payable current

$ 398,837

[1]

$ 3,438,162

Amortization of debt discount

$ 55,430

$ 217,699

[custom:AssetsWorkingInterest-0]

50%

Jovian Petroleum Corporation [Member]

Short-Term Debt [Line Items]

Ownership interest

25%

25%

Loan Agreement [Member]

Short-Term Debt [Line Items]

Debt face amount

$ 416,900

$ 1,000,000

$ 50,000

Debt interest rate

10%

10%

0%

12%

Origination fee

$ 120,000

Debt instrument maturity date

Dec. 31, 2021

Jun. 30, 2020

Warrants to acquire of common stock | shares

5,000,000

5,000,000

200,000

Warrant exercise price | (per share)

$ 0.05

$ 0.10

$ 0.10

Warrant expiry date

Jan. 06, 2023

Jan. 02, 2023

Mar. 01, 2022

Debt instrument, unamortized discount

$ 166,289

$ 266,674

Amortization of debt discount

$ 4,614.14

$ 11,111

Revolving line of credit agreement [Member] | Jovian Petroleum Corporation [Member]

Short-Term Debt [Line Items]

Debt interest rate

3.50%

3.50%

Revolving line of credit

$ 500,000

$ 200,000

Truck Loan [Member]

Short-Term Debt [Line Items]

Debt face amount

$ 35,677

Debt instrument, term

5 years

Debt interest rate

5.49%

5.49%

[2]

Notes payable current

$ 683

Debt instrument maturity date

[2]

Jan. 20, 2022

Credit note I, II and III [Member]

Short-Term Debt [Line Items]

Debt face amount

$ 2,085,432

Debt interest rate

10%

Debt instrument maturity date

Dec. 31, 2022

[custom:AssetsWorkingInterest-0]

25%

[1]All notes are current (due within one year or less from December 31, 2022.)[2]On January 6, 2017, the Company purchased a truck and entered into an installment note in the amount of $ 35,677 five years 5.49% 683

SCHEDULE OF FUTURE MINIMUM REPA

SCHEDULE OF FUTURE MINIMUM REPAYMENTS OF NOTES PAYABLE (Details) - Notes Payable [Member]	Dec. 31, 2022 USD ($)
Short-Term Debt [Line Items]
2023	$ 440,409
Thereafter
Total	$ 440,409

SCHEDULE OF FINANCIAL INFORMATI

SCHEDULE OF FINANCIAL INFORMATION LEASE (Details) - USD ($)	Dec. 31, 2022	Dec. 31, 2021
Leases
Right-of-use assets	$ 23,086	$ 12,821
Current lease liabilities	5,482	13,909
Non-current lease liabilities	$ 17,714

SCHEDULE OF MATURITIES LEASE LI

SCHEDULE OF MATURITIES LEASE LIABILITY (Details)	Dec. 31, 2022 USD ($)
Leases
2023	$ 5,482
2024	5,714
2025	6,539
2026	5,400
Total	23,196
Less: Imputed interest	(110)
Present value of lease liabilities	$ 23,086

SCHEDULE OF RELATED PARTY NOTES

SCHEDULE OF RELATED PARTY NOTES PAYABLE (Details) - USD ($)		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021
Defined Benefit Plan Disclosure [Line Items]
Notes payable - related party		$ 3,460,815	$ 779,373
Quinten Beasley [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest rate		10%
Date of maturity		Oct. 14, 2016
Notes payable - related party		$ 5,000
Blue Sky Resources [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest rate	[1]	3.50%
Date of maturity	[1]	Dec. 31, 2021
Notes payable - related party	[1]	$ 178,923
Blue Sky Resources 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest rate	[2]	10%
Date of maturity	[2]	Dec. 31, 2021
Notes payable - related party	[2]	$ 150,000
BlueSky Resources 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest rate	[3]	10%
Date of maturity	[3]	Dec. 31, 2022
Notes payable - related party	[3]	$ 2,085,432
Ivar Siem [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest rate	[4]	9%
Date of maturity	[4]	Dec. 31, 2021
Notes payable - related party	[4]	$ 278,435	278,435
Mark M Allen [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest rate	[5]	9%
Date of maturity	[5]	Sep. 02, 2021
Notes payable - related party	[5]	$ 55,000	55,000
Mark M Allen One [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest rate	[6]	12%
Date of maturity	[6]	Jun. 30, 2020
Notes payable - related party	[6]	$ 200,000	200,000
Mark M Allen Two [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest rate	[7]	9%
Date of maturity	[7]	Jun. 30, 2021
Notes payable - related party	[7]	$ 241,125	245,938
Joel Oppenheim [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest rate	[8]	10%
Date of maturity	[8]	Dec. 31, 2021
Notes payable - related party	[8]	$ 266,900
[1]On February 9, 2018, the Company entered into a Revolving Line of Credit Agreement (“LOC”) for $ 200,000 500,000 25% 3.5% 2,085,432 10% December 31, 2022 25% 75,000 12% 100,000 12% 1,250,000 0.08 5,000,000 0.10 50,000 0% 200,000 0.10 March 1, 2022 278,435 9% December 31, 2021 55,000 9% September 2, 2021 200,000 12% June 30, 2020 2,500,000 0.08 10,000,000 0.10 100,000 10% June 1, 2020 400,000 0.10 January 3, 2023 31,946 1,775 125,000 10 June 1, 2020 750,000 0.10 February 14, 2022 38,249 1,903 245,938 9% June 30, 2021

SCHEDULE OF RELATED PARTY NOT_2

SCHEDULE OF RELATED PARTY NOTES PAYABLE (Details) (Parenthetical)

12 Months Ended

Feb. 12, 2021 USD ($)

Jan. 01, 2021 USD ($)

Oct. 30, 2020 USD ($) $ / shares shares

Apr. 15, 2020 USD ($)

Feb. 14, 2020 USD ($) shares

Jan. 03, 2020 USD ($) shares

Jan. 02, 2020 USD ($) shares

Dec. 04, 2019 USD ($) $ / shares shares

Dec. 31, 2022 USD ($)

Dec. 31, 2021 USD ($)

Dec. 31, 2019 USD ($) $ / shares shares

Feb. 28, 2020 USD ($) shares

Feb. 28, 2020 $ / shares

Feb. 14, 2020 $ / shares

Jan. 06, 2020 $ / shares shares

Jan. 03, 2020 $ / shares

Jan. 02, 2020 $ / shares

Aug. 15, 2019 USD ($)

Jun. 01, 2018

Apr. 12, 2018 USD ($)

Feb. 19, 2018

Feb. 09, 2018 USD ($)

Amortization of debt discount

$ 55,430

$ 217,699

Jovian Petroleum Corporation [Member]

Ownership interest

25%

25%

Loan Agreement [Member]

Debt interest rate

10%

10%

0%

12%

Debt instrument face amount

$ 416,900

$ 1,000,000

$ 50,000

Warrant exercise price | (per share)

$ 0.05

$ 0.10

$ 0.10

Warrant to purchase of common stock | shares

5,000,000

5,000,000

200,000

Warrants maturity date

Jan. 06, 2023

Jan. 02, 2023

Mar. 01, 2022

Date of maturity

Dec. 31, 2021

Jun. 30, 2020

Amortization of debt discount

$ 4,614.14

$ 11,111

Loan Agreement [Member] | Warrant [Member]

Warrant exercise price | $ / shares

$ 0.10

$ 0.10

Warrant to purchase of common stock | shares

5,000,000

5,000,000

Jovian Petroleum Corporation [Member] | Revolving line of credit agreement [Member]

Revolving line of credit

$ 500,000

$ 200,000

Debt interest rate

3.50%

3.50%

Ivar Siem [Member]

Debt interest rate

[1]

9%

Date of maturity

[1]

Dec. 31, 2021

Ivar Siem [Member] | Loan Agreement [Member]

Debt interest rate

9%

12%

12%

Debt instrument face amount

$ 278,435

$ 100,000

$ 75,000

Shares issued on conversion of debt | shares

1,250,000

Conversion price | $ / shares

$ 0.08

Date of maturity

Dec. 31, 2021

Ivar Siem [Member] | Loan Agreement [Member] | Warrant [Member]

Shares issued on conversion of debt | shares

5,000,000

Warrant exercise price | $ / shares

$ 0.10

Mark M Allen [Member]

Debt interest rate

[2]

9%

Date of maturity

[2]

Sep. 02, 2021

Mark M Allen [Member] | Loan Agreement [Member]

Debt interest rate

9%

10%

10%

12%

Debt instrument face amount

$ 245,938

$ 125,000

$ 100,000

$ 200,000

Shares issued on conversion of debt | shares

2,500,000

Conversion price | $ / shares

$ 0.08

Warrant exercise price | $ / shares

$ 0.10

$ 0.10

Warrant to purchase of common stock | shares

750,000

400,000

Warrants maturity date

Feb. 14, 2022

Jan. 03, 2023

Date of maturity

Jun. 01, 2020

Jun. 01, 2020

Jun. 30, 2020

Amortization of debt discount

$ 38,249

$ 31,946

Amortization of debt

$ 1,903

$ 1,775

Mark M Allen [Member] | Loan Agreement [Member] | Warrant [Member]

Shares issued on conversion of debt | shares

10,000,000

Warrant exercise price | $ / shares

$ 0.10

Mark M Allen [Member] | Consulting Agreement [Member]

Debt interest rate

9%

Debt instrument face amount

$ 55,000

Date of maturity

Sep. 02, 2021

[1]On August 15, 2019, the Company entered into a loan agreement in the amount of $ 75,000 12% 100,000 12% 1,250,000 0.08 5,000,000 0.10 50,000 0% 200,000 0.10 March 1, 2022 278,435 9% December 31, 2021 55,000 9% September 2, 2021

SCHEDULE OF FUTURE MINIMUM RE_2

SCHEDULE OF FUTURE MINIMUM REPAYMENTS OF RELATED PARTY NOTES PAYABLE (Details) - USD ($)	Dec. 31, 2022	Dec. 31, 2021
Related Party Notes Payable
2023	$ 3,460,815
Thereafter
Total	$ 3,460,815	$ 779,373

SCHEDULE OF DERIVATIVE LIABIL_2

SCHEDULE OF DERIVATIVE LIABILITIES (Details)	12 Months Ended
	Dec. 31, 2022 USD ($)
Investments, All Other Investments [Abstract]
Beginning balance	$ 22,554
Additions
Fair value adjustments	(22,554)
Ending balance

SCHEDULE OF DERIVATIVE LIABIL_3

SCHEDULE OF DERIVATIVE LIABILITY OF FAIR VALUE ASSUMPTION (Details)	12 Months Ended
	Dec. 31, 2022
Measurement Input, Risk Free Interest Rate [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative liability, measurement input	4.12
Measurement Input, Expected Term [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative liability, expected life	0 years
Measurement Input, Expected Dividend Rate [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative liability, measurement input	0
Measurement input expected volatility [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative liability, measurement input	2.67

DERIVATIVE FINANCIAL INSTRUME_3

DERIVATIVE FINANCIAL INSTRUMENTS (Details Narrative)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Oct. 30, 2020 USD ($) $ / shares shares	Feb. 28, 2020 $ / shares shares	Jan. 06, 2020 USD ($) $ / shares shares	Jan. 02, 2020 $ / shares shares	May 18, 2018 USD ($) shares	May 18, 2018 $ / shares
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Derivative liability | $		$ 22,554
Amended and Restated Loan Agreement [Member]
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Warrants to purchase common stock | shares							320,000
Warrant exercise price | $ / shares								$ 0.10
Derivative liability | $							$ 30,012
Warrant expiry date							May 11, 2021
Loan Agreement [Member]
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Warrants to purchase common stock | shares			5,000,000	200,000		5,000,000
Warrant exercise price | (per share)			$ 0.05	$ 0.10		$ 0.10
Warrant expiry date			Jan. 06, 2023	Mar. 01, 2022		Jan. 02, 2023
Loan Agreement [Member] | Warrant [Member]
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Warrants to purchase common stock | shares			5,000,000		5,000,000
Warrant exercise price | $ / shares			$ 0.10		$ 0.10
Derivative liability | $			$ 95,352		$ 144,259

SCHEDULE OF FAIR VALUE OF ASSET

SCHEDULE OF FAIR VALUE OF ASSET RETIREMENT OBLIGATIONS (Details)	12 Months Ended
	Dec. 31, 2022
Minimum [Member]
Inflation rate	1.92%
Estimated asset life	12 years
Maximum [Member]
Inflation rate	2.15%
Estimated asset life	22 years

SCHEDULE OF CHANGE IN ASSET RET

SCHEDULE OF CHANGE IN ASSET RETIREMENT OBLIGATIONS (Details) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Property, Plant and Equipment [Line Items]
Asset retirement obligations at beginning of period	$ 2,257,027	$ 3,624,133
Plugging liability atTwin Lakes		132,000
Accretion expense	125,603	316,873
Disposition	(47,624)	(1,824,339)
Foreign currency translation	(81,671)	8,360
Accretion expense	173,603	316,873
Asset retirement obligations at end of period	2,301,335	2,257,027
Canadian Properties [Member]
Property, Plant and Equipment [Line Items]
Asset retirement obligations at beginning of period	1,186,297	2,711,909
Plugging liability atTwin Lakes
Accretion expense		290,367
Disposition		(1,824,339)
Foreign currency translation	(81,671)	8,360
Accretion expense	145,191
Asset retirement obligations at end of period	1,249,816	1,186,297
US Properties [Member]
Property, Plant and Equipment [Line Items]
Asset retirement obligations at beginning of period	1,070,730	912,225
Plugging liability atTwin Lakes		152,000
Accretion expense		26,506
Disposition	(47,624)
Foreign currency translation
Accretion expense	28,412
Asset retirement obligations at end of period	$ 1,051,518	$ 1,070,730

ASSET RETIREMENT OBLIGATIONS (D

ASSET RETIREMENT OBLIGATIONS (Details Narrative) - USD ($)	Apr. 08, 2021	Dec. 31, 2022	Dec. 31, 2021	Dec. 30, 2021	Dec. 31, 2020
Asset Retirement Obligation Disclosure [Abstract]
Legal penalties	$ 35,100
Asset retirement obligations additional liabilities		$ 2,301,335	$ 2,257,027	$ 792,000	$ 3,624,133

SCHEDULE Of COMMON STOCK PURCHA

SCHEDULE Of COMMON STOCK PURCHASE WARRANTS ISSUED AND OUTSTANDING (Details) - $ / shares	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Equity [Abstract]
Warrants Outstanding, Beginning balance	29,700,000	40,764,666
Weighted Average Exercise Price, Beginning balance	$ 0.13	$ 0.13
Warrants outstanding, granted	1,000,000	9,400,000
Weighted average exercise price, granted	$ 0.10	$ 0.09
Warrants outstanding, expired	(6,730,000)	(20,464,666)
Weighted average exercise price, expired	$ 0.11	$ 0.11
Warrants Outstanding, Ending balance	23,970,000	29,700,000
Weighted Average Exercise Price, Ending balance	$ 0.13	$ 0.13

SCHEDULE OF WARRANTS ISSUANCE D

SCHEDULE OF WARRANTS ISSUANCE DURING PERIOD (Details) - shares	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Accumulated Other Comprehensive Income (Loss) [Line Items]
Number of Warrants granted	1,000,000	9,400,000
Warrant [Member] | Finance Arrangement [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Number of Warrants granted	1,000,000	1,000,000
Warrant [Member] | Loan Agreement [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Number of Warrants granted		5,400,000
Warrant [Member] | Board of Directors and Advisory Board Service [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Number of Warrants granted		3,000,000

SCHEDULE OF FAIR VALUE OF ASSUM

SCHEDULE OF FAIR VALUE OF ASSUMPTION OF WARRANTS (Details)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Expected dividend rate	0%	0%
Measurement Input, Expected Term [Member]
Expected life	3 years
Minimum [Member]
Risk-free interest rate	249%	16%
Expected life		2 years
Expected volatility	267%	277%
Maximum [Member]
Risk-free interest rate	422%	0.97%
Expected life		3 years
Expected volatility	299%	356%

EQUITY (Details Narrative)

EQUITY (Details Narrative) - USD ($)					1 Months Ended		12 Months Ended
	Mar. 31, 2021	Mar. 30, 2021	Jan. 29, 2021	Jan. 07, 2021	Jan. 25, 2021	Oct. 30, 2020	Dec. 31, 2022	Dec. 31, 2021
Bow Energy Ltd [Member] | Stock Options [Member]
Class of Stock [Line Items]
Warrants to purchase common stock	5,400,000					5,000,000
Warrant exercise price	$ 0.08					$ 0.05
Warrant term	3 years					3 years
Warrants outstanding	$ 135,000
Warrant [Member]
Class of Stock [Line Items]
Warrants outstanding, weighted-average remaining contractual life							9 months 21 days	1 year 8 months 15 days
Warrants outstanding, intrinsic value							$ 0	$ 0
Mark Allen [Member]
Class of Stock [Line Items]
Unpaid contract wages		$ 30,000
Converted shares of common stock		333,333
Conversion price		$ 0.09
Mark Allen [Member] | Secured Debt [Member]
Class of Stock [Line Items]
Converted shares of common stock		5,400,000
Secured debt		$ 135,000
Accrued interest		9,888
Guaranteed return secured loan		$ 135,000
Warrant to purchase of common stock		5,400,000
Warrant exercise price		$ 0.08
Warrants and rights outstanding, term		36 months
Joel Oppenheim [Member]
Class of Stock [Line Items]
Number of common stock issued				316,491	316,491
Gain on related party nature of transaction				$ 53,670
Conversion price				$ 0.02
Settlement and Mutual Release Agreement [Member] | Paul Deputy [Member]
Class of Stock [Line Items]
Description on agreement terms			Paul Deputy was reinstated Interim Chief Financial Officer and signed a Settlement and Mutual Release Agreement. In exchange for releasing the Company for any current, outstanding payroll and/or service-related liability on January 29, 2021, the Company agreed to pay Mr. Deputy $50,000, to be paid in $2,500 monthly increments, starting April 1, 2021. In addition, Mr. Deputy was issued 250,000 shares of Petrolia common stock on January 29, 2021.
Officer compensation, per month			$ 50,000
Number of shares to be issued			250,000
Paul Deputy [Member]
Class of Stock [Line Items]
Number of common stock issued			250,000
Shares issued price per share			$ 0.033
Gain on related party nature of transaction			$ 134,270
Repayments of related party debt							$ 45,000
Executive Salary Payable Agreement [Member]
Class of Stock [Line Items]
Issuance of common stock related shares					1,992,272
Settlement and Mutual Release Agreement [Member] | Paul Deputy [Member]
Class of Stock [Line Items]
Shares issued price per share			$ 0.033
Series A Preferred Stock [Member]
Class of Stock [Line Items]
Preferred stock, dividend rate							9%
Stock conversion price							$ 0.28
Preferred stock conversion, description							the value of each dollar of preferred stock (based on a $10 per share price) will convert into 7.1429 common shares (which results in a $0.14 per common share conversion rate)
Cumulative cash dividends							$ 179,190	179,190
Series C Preferred Stock [Member]
Class of Stock [Line Items]
Preferred stock, dividend rate							8%
Preferred stock conversion, description							the value of each dollar of Series C Preferred Stock (based on a $10 per share price) will convert into 100 common shares (which results in a $0.01 per common share conversion rate)
Cumulative cash dividends							$ 8,696	$ 779

RELATED PARTY TRANSACTIONS (Det

RELATED PARTY TRANSACTIONS (Details Narrative)

1 Months Ended

12 Months Ended

Oct. 31, 2021 CAD ($)

Sep. 30, 2021 CAD ($)

Aug. 31, 2021 CAD ($)

Aug. 21, 2021 USD ($) a

Aug. 21, 2021 CAD ($) a

Mar. 31, 2021 USD ($) $ / shares shares

Mar. 30, 2021 USD ($) $ / shares shares

Jan. 29, 2021 USD ($) $ / shares shares

Jan. 11, 2021 USD ($) $ / shares shares

Jan. 07, 2021 USD ($) $ / shares shares

May 29, 2020 USD ($) a

May 29, 2020 CAD ($)

Nov. 30, 2021 USD ($) shares

Oct. 31, 2021 USD ($) shares

Oct. 25, 2021 USD ($)

Jan. 25, 2021 shares

Dec. 31, 2022 USD ($)

Dec. 31, 2021 USD ($)

Dec. 31, 2021 CAD ($)

Dec. 31, 2020 USD ($)

Dec. 31, 2020 CAD ($)

Dec. 31, 2021 CAD ($)

May 29, 2020 CAD ($) a

Related Party Transaction [Line Items]

Payment of contingent consideration liability

$ 1,000,000

$ 1,000,000

West texas intermediate terms description

At the time WTI price exceeded $50/bbl, the Company would pay an additional $750,000. In addition, at the time WTI price exceeded $57/bbl the Company would pay an additional $250,000 (for a cumulative contingent total of $1,000,000).

At the time WTI price exceeded $50/bbl, the Company would pay an additional $750,000. In addition, at the time WTI price exceeded $57/bbl the Company would pay an additional $250,000 (for a cumulative contingent total of $1,000,000).

At the time WTI price exceeded $50/bbl, the Company would pay an additional $750,000 CAD. In addition, at the time WTI price exceeded $57/bbl the Company would pay an additional $250,000 CAD (for a cumulative contingent total of $1,000,000 CAD). The price of WTI crude exceeded $50/bbl on January 6, 2021 and exceeded $57/bbl on February 8, 2021

At the time WTI price exceeded $50/bbl, the Company would pay an additional $750,000 CAD. In addition, at the time WTI price exceeded $57/bbl the Company would pay an additional $250,000 CAD (for a cumulative contingent total of $1,000,000 CAD). The price of WTI crude exceeded $50/bbl on January 6, 2021 and exceeded $57/bbl on February 8, 2021

Other assets, current

$ 5,641

$ 5,641

Share based compensation

$ 211,481

Series B Preferred Stock [Member]

Related Party Transaction [Line Items]

Variable interest entity, qualitative or quantitative information, ownership percentage

60%

Preferred stock for cash

$ 50,799

Leo Womack [Member]

Related Party Transaction [Line Items]

Preferred stock, shares issued | shares

2,500

2,500

Preferred stock for cash

$ 25,000

$ 25,000

Letter Agreement [Member]

Related Party Transaction [Line Items]

Area of land | a

28,000

28,000

Assets acquistion consideration

$ 5,150,000

$ 6,500,000

Working interest percentage

28%

28%

Non refundable deposits

$ 200,000

Assets acquired and liabilities assumed, contingent liability

$ 1,000,000

$ 2,000,000

$ 3,300,000

Other payable

$ 200,000

Letter Agreement [Member] | Chief Executive Officer [Member]

Related Party Transaction [Line Items]

Working interest percentage

50%

50%

Joel Oppenheim [Member]

Related Party Transaction [Line Items]

Preferred stock, shares issued | shares

316,491

316,491

Share based compensation

$ 60,000

Conversion price | $ / shares

$ 0.02

Related party transaction amounts

$ 53,670

Zel Khan [Member]

Related Party Transaction [Line Items]

Preferred stock, shares issued | shares

1,992,272

Conversion price | $ / shares

$ 0.025

Related party transaction amounts

$ 275,193

Accrued salaries

$ 325,000

Paul Deputy [Member]

Related Party Transaction [Line Items]

Preferred stock, shares issued | shares

250,000

Related party transaction amounts

$ 134,270

Accrued salaries

$ 192,520.04

Debt periodic payment months

20

Debt instrument, periodic payment

$ 2,500

Share issued price per share | $ / shares

$ 0.033

Mark Allen [Member]

Related Party Transaction [Line Items]

Preferred stock, shares issued | shares

5,400,000

Conversion price | $ / shares

$ 0.033

$ 0.033

Related party transaction amounts

$ 98,690

$ 19,001

Conversion of stock shares converted | shares

333,333

Sale of price per share | $ / shares

$ 0.09

Unpaid contract wages

$ 30,000

Loan payable

135,000

Accrued interest

9,888

Consulting fees

$ 135,000

Class of warrant right shares | shares

5,400,000

Warrant exercise price | $ / shares

$ 0.08

Warrants and rights outstanding

$ 200,378

Alberta Enegry Regulator [Member]

Related Party Transaction [Line Items]

Amount of acquisition fund requirement

$ 563,904

$ 765,752

Other assets, current

$ 362,245

$ 490,624

Blue Sky Resources Ltd [Member]

Related Party Transaction [Line Items]

Business acquisition percentage of voting interests acquired

50%

50%

Area of land | a

28,000

28,000

Payments to acquire businesses gross

$ 2,000,000

Proceeds from Prevailing exchange rates

$ 787,250

$ 787,250

Blue Sky Resources Ltd [Member] | Zel C. Khan [Member]

Related Party Transaction [Line Items]

Ownership percentage

100%

100%

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Details Narrative) - USD ($)		12 Months Ended
	Nov. 04, 2022	Dec. 31, 2022	Dec. 31, 2021
Commitments and Contingencies Disclosure [Abstract]
Operating lease payments	$ 500	$ 978	$ 2,783
Percentage of increase in value of lease	7%

SCHEDULE OF INCOME TAX EXPENSES

SCHEDULE OF INCOME TAX EXPENSES (Details) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Income tax (benefit) expense computed at statutory rates	$ (384,000)	$ 405,000
Non-deductible items	(4,000)	49,000
Change in statutory, foreign tax, foreign exchange rates and other	(384,000)	(559,000)
Change in valuation allowance	24,000	105,000
Income tax provision (benefit)

SCHEDULE OF DEFERRED TAX ASSETS

SCHEDULE OF DEFERRED TAX ASSETS (Details) - USD ($)	Dec. 31, 2022	Dec. 31, 2021
Deferred tax assets
Net operating loss carryforwards	$ 6,226,000	$ 6,038,000
Asset retirement obligation	508,000	498,000
Oil and gas properties	(739,000)	(593,000)
Property and equipment
Other
Total deferred tax assets (liabilities)	5,995,000	5,943,000
Less: Valuation allowance	(5,995,000)	(5,943,000)
Net deferred tax assets (liabilities)

INCOME TAXES (Details Narrative

INCOME TAXES (Details Narrative) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Operating losses valuation allowance	100%	100%
Federal statutory income tax rate	21%	21%
Income tax description	The Tax Cuts and Jobs Act was signed into law on December 22, 2017 and reduced the corporate income tax rate from 34% to 21%
UNITED STATES
Operating losses	$ 28.5
Operating losses expiration, description		begin to expire if not utilized beginning in the year 2033
CANADA
Accumulated non-capital tax losses	$ 1
Accumulated non-capital tax losses, expiration description		expire in 2039

SCHEDULE OF LONG-LIVED ASSETS (

SCHEDULE OF LONG-LIVED ASSETS (Details) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting Information [Line Items]
Total long-lived assets	$ 5,986,283	$ 6,349,183
Operating Segments [Member]
Segment Reporting Information [Line Items]
Revenue	6,847,800	5,895,228
Production costs	(6,790,478)	(5,347,490)
Depreciation, depletion, amortization, and accretion	(411,787)	(720,018)
Results of operations from producing activities	(354,465)	(172,280)
Total long-lived assets	5,986,283	6,349,182
Operating Segments [Member] | CANADA
Segment Reporting Information [Line Items]
Revenue	6,841,721	5,882,499
Production costs	(6,651,673)	(5,281,740)
Depreciation, depletion, amortization, and accretion	(382,258)	(668,672)
Results of operations from producing activities	(192,210)	(67,913)
Total long-lived assets	1,742,837	2,104,993
Operating Segments [Member] | UNITED STATES
Segment Reporting Information [Line Items]
Revenue	6,079	12,729
Production costs	(138,805)	(65,750)
Depreciation, depletion, amortization, and accretion	(29,529)	(51,346)
Results of operations from producing activities	(162,255)	(104,367)
Total long-lived assets	$ 4,243,466	$ 4,244,189

SCHEDULE OF REVENUES (Details)

SCHEDULE OF REVENUES (Details) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Revenue, Major Customer [Line Items]
Total revenues	$ 6,847,800	$ 5,895,228
Customer A [Member]
Revenue, Major Customer [Line Items]
Total revenues		796,176
Customer B [Member]
Revenue, Major Customer [Line Items]
Total revenues	6,079	12,729
Customer C [Member]
Revenue, Major Customer [Line Items]
Total revenues	4,793,138	5,086,323
Customer D [Member]
Revenue, Major Customer [Line Items]
Total revenues	$ 2,048,583

SEGMENT REPORTING (Details Narr

SEGMENT REPORTING (Details Narrative)	12 Months Ended
	Dec. 31, 2022 Integer
Segment Reporting [Abstract]
Number of reportable segments	1

SCHEDULE OF COSTS INCURRED IN O

SCHEDULE OF COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION,EXPLORATION AND DEVELOPMENT (Details) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Extractive Industries [Abstract]
Property acquisitions		$ 787,250
Unevaluated
Evaluated
Exploration
Development
Total costs incurred		$ 787,250

SCHEDULE OF CAPITALIZED COSTS I

SCHEDULE OF CAPITALIZED COSTS IN OIL AND GAS PROPERTY ACQUISITION,EXPLORATION AND DEVELOPMENT (Details) - USD ($)	Dec. 31, 2022	Dec. 31, 2021
Capitalized costs:
Unevaluated properties
Evaluated properties	5,414,771	5,511,480
Gross capitalized costs	5,414,771	5,511,480
Less: Accumulated DD&A	(651,754)	(448,960)
Net capitalized costs	$ 4,763,017	$ 5,062,520

SCHEDULE OF PROVED OIL AND GAS

SCHEDULE OF PROVED OIL AND GAS RESERVES (Details) - bbl	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Extractive Industries [Abstract]
Proved oil and gas reserves, beginning	1,449,853	1,311,672
Proved oil and gas reserves, revisions of prior estimates	(232,950)	292,335
Proved oil and gas reserves, purchases of reserves in place
Proved oil and gas reserves, disposition of mineral in place	(71,380)	(57,070)
Proved oil and gas reserves, production	(80,333)	(97,084)
Proved oil and gas reserves, ending	1,065,190	1,449,853

SCHEDULE OF PROVED DEVELOPMENT

SCHEDULE OF PROVED DEVELOPMENT AND UNDEVELOPED RESERVES (Details) - bbl	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Reserve Quantities [Line Items]
Estimated quantities of proved undeveloped reserves	1,065,190	1,449,853
Proved oil and gas reserves, beginning	1,449,853	1,311,672
Revision of prior estimates	(232,950)	292,335
Production	(80,333)	(97,084)
Proved oil and gas reserves, ending	1,065,190	1,449,853
Proved Developed Reserve [Member]
Reserve Quantities [Line Items]
Estimated quantities of proved undeveloped reserves	1,043,830	1,449,853
Proved oil and gas reserves, beginning	1,449,853
Proved oil and gas reserves, ending	1,043,830	1,449,853
Proved Undeveloped Reserves [Member]
Reserve Quantities [Line Items]
Estimated quantities of proved undeveloped reserves	21,360
Proved oil and gas reserves, beginning
Proved oil and gas reserves, ending	21,360
Proved Developed Reserve and Non-producing [Member]
Reserve Quantities [Line Items]
Estimated quantities of proved undeveloped reserves	1,043,830	1,449,853
Proved oil and gas reserves, beginning	1,449,853
Revision of prior estimates	(325,690)
Production	(80,334)
Proved oil and gas reserves, ending	1,043,830	1,449,853
Proved Undeveloped Reserve [Member]
Reserve Quantities [Line Items]
Estimated quantities of proved undeveloped reserves	21,360
Proved oil and gas reserves, beginning
Revision of prior estimates	21,360
Proved oil and gas reserves, ending	21,360

SCHEDULE OF STANDARDIZED MEASUR

SCHEDULE OF STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (Details) - USD ($)	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Extractive Industries [Abstract]
Future cash inflows	$ 95,454,352	$ 93,082,624
Future production costs	(49,218,382)	(45,892,778)
Future development costs	(2,622,876)	(1,867,485)
Future income taxes
Future net cash flows	43,613,094	45,322,361
Discount of future net cash flows at 10% per annum```	(20,782,000)	(27,929,984)
Standardized measure of discounted future net cash flows	$ 22,831,094	$ 17,392,377	$ 7,956,920

SCHEDULE OF STANDARDIZED MEAS_2

SCHEDULE OF STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (Details) (Parenthetical)	12 Months Ended
	Dec. 31, 2022
Extractive Industries [Abstract]
Discount of future net cash flows interest rate	10%

SCHEDULE OF CHANGES IN STANDARD

SCHEDULE OF CHANGES IN STANDARDIZED MEASURE OF DISCONTINUED FUTURE CASH FLOWS (Details) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Extractive Industries [Abstract]
Beginning of year	$ 17,392,377	$ 7,956,920
Sales and transfers of oil & gas produced, net of production costs	(660,629)	(539,927)
Net changes in prices and production costs	(1,278,130)	(865,805)
Changes in estimated future development costs	537,696	(565,870)
Acquisitions/dispositions of minerals in place, net of production costs	(367,027)	(231,470)
Revision of previous estimates	(11,820,528)	1,194,016
Change in discount
Change in production rate or other	19,027,334	10,444,513
End of year	$ 22,831,094	$ 17,392,377

SUPPLEMENTAL INFORMATION RELA_3

SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details Narrative)		12 Months Ended
	May 29, 2020 USD ($)	Dec. 31, 2022	Dec. 31, 2020 USD ($)	Dec. 31, 2020 CAD ($)
Property, Plant and Equipment [Line Items]
Payment of contingent consideration liability	$ 1,000,000			$ 1,000,000
West texas intermediate terms description	At the time WTI price exceeded $50/bbl, the Company would pay an additional $750,000. In addition, at the time WTI price exceeded $57/bbl the Company would pay an additional $250,000 (for a cumulative contingent total of $1,000,000).		At the time WTI price exceeded $50/bbl, the Company would pay an additional $750,000 CAD. In addition, at the time WTI price exceeded $57/bbl the Company would pay an additional $250,000 CAD (for a cumulative contingent total of $1,000,000 CAD). The price of WTI crude exceeded $50/bbl on January 6, 2021 and exceeded $57/bbl on February 8, 2021	At the time WTI price exceeded $50/bbl, the Company would pay an additional $750,000 CAD. In addition, at the time WTI price exceeded $57/bbl the Company would pay an additional $250,000 CAD (for a cumulative contingent total of $1,000,000 CAD). The price of WTI crude exceeded $50/bbl on January 6, 2021 and exceeded $57/bbl on February 8, 2021
Discount of future net cash flows interest rate		10%
Blue Sky Resources Ltd [Member]
Property, Plant and Equipment [Line Items]
Proceeds from prevailing exchange rates	$ 787,250		$ 787,250
Utikuma Field [Member]
Property, Plant and Equipment [Line Items]
Assets acquired, percentage			50%
Purchase price			$ 678,765
Asset retirement obligation			$ 906,146