Petrolia Energy (BBLSQ) 10-K 9 Dec 22 2021 FY Annual report Financial data

Cover

Cover - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 09, 2022	Jun. 30, 2021
Cover [Abstract]
Document Type	10-K
Amendment Flag	false
Document Annual Report	true
Document Transition Report	false
Document Period End Date	Dec. 31, 2021
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2021
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
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	No
Entity Interactive Data Current	No
Entity Filer Category	Non-accelerated Filer
Entity Small Business	true
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float			$ 3,103,828
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, 2021	Dec. 31, 2020
Current assets
Cash	$ 14,058	$ 155,045
Accounts receivable	5,942	5,000
Other current assets	5,641	39,443
Total current assets	25,641	199,488
Oil and gas, on the basis of full cost accounting:
Evaluated Properties	6,797,025	8,619,427
Furniture, equipment & software	155,293	201,110
Less accumulated depreciation & depletion	(603,135)	(2,868,453)
Net property and equipment	6,349,183	5,952,084
Other assets
Operating Lease Right-of-Use Asset	12,821	23,145
Other assets	1,450,841	985,187
Total Assets	7,838,486	7,159,904
Current liabilities
Accounts payable	320,088	1,067,841
Accounts payable - related parties	57,363	587
Operating Lease Liability	13,909	13,107
Accrued liabilities	1,149,012	1,572,055
Accrued liabilities - related parties	862,158	751,949
Notes payable - short term	3,438,162	3,037,737
Notes payable - related party	779,373	1,035,329
Total current liabilities	6,620,065	7,478,605
Asset retirement obligations	2,257,027	3,624,133
Operating Lease Liability		13,909
Notes payable		573
Derivative liability	22,554	183,798
Total Liabilities	8,899,646	11,301,018
Stockholders’ Equity (Deficit)
Common stock, $0.001 par value; 400,000,000 shares authorized; 176,988,322 and 168,696,226 shares issued and outstanding	176,988	168,696
Additional paid in capital	60,216,722	59,044,519
Accumulated other comprehensive income (loss)	(269,155)	(266,432)
Accumulated deficit	(61,339,161)	(63,088,096)
Total Stockholders’ Equity (Deficit)	(1,061,160)	(4,141,114)
Total Liabilities and Stockholders’ Equity (Deficit)	7,838,486	7,159,904
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
Series C Preferred Stock [Member]
Stockholders’ Equity (Deficit)
Preferred stock value	$ 850

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2021	Dec. 31, 2020
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	168,696,226
Common stock, shares outstanding	176,988,322	168,696,226
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	0
Preferred stock, shares outstanding	3	0
Preferred stock, no par value	$ 0	$ 0
Series C Preferred Stock [Member]
Preferred stock, par value	$ 0.10	$ 0.10
Preferred stock, shares authorized	11,000	11,000
Preferred stock, shares issued	8,500	0
Preferred stock, shares outstanding	8,500	0

Consolidated Statements of Oper

Consolidated Statements of Operations and Comprehensive Loss - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Total revenue	$ 5,895,228	$ 2,892,241
Operating expenses
Lease operating expense	5,346,287	3,627,541
Production tax	1,203	3,066
General and administrative expenses	1,107,517	864,583
Depreciation, depletion and amortization	403,145	1,147,281
Asset retirement obligation accretion	316,873	287,758
Loss on forfeiture	132,000	6,255,103
Impairment of oil and gas properties		396,922
Total operating expenses	7,307,025	12,582,254
Loss from operations	(1,411,797)	(9,690,013)
Other income (expenses)
Interest expense	(638,569)	(735,622)
Change in fair value of derivative liabilities	161,244	(159,289)
Other income (expense)	(101,297)	275,905
Gain on sale of assets	3,919,323
Total other income (expenses)	3,340,701	(619,006)
Net income (loss) before taxes	1,928,904	(10,309,019)
Income tax provision (benefit)
Net income (loss)	1,928,904	(10,309,019)
Series A preferred dividends	(179,190)	(178,699)
Series C preferred dividends	(779)
Net income (loss) attributable to common stockholders	1,748,935	(10,487,718)
Other comprehensive income, net of tax
Foreign currency translation adjustments	(2,723)	(47,867)
Comprehensive income (loss)	$ 1,746,212	$ (10,535,585)
Gain (loss) per share
(Basic and diluted)	$ 0.01	$ (0.06)
Weighted average number of common shares outstanding, basic and diluted	175,434,139	165,389,389
Oil and Gas Sales [Member]
Total revenue	$ 5,895,228	$ 2,892,241

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Cash Flows from Operating Activities
Net income (loss)	$ 1,928,904	$ (10,309,019)
Adjustment to reconcile net loss to net cash used in operating activities:
Depletion, depreciation and amortization	403,145	1,147,281
Asset retirement obligation accretion	316,873	287,758
Operating Lease Accrual	(2,783)	1,054
Amortization of debt discount	217,699	209,570
Change in fair value of derivative liabilities	(161,244)	159,289
Warrants as finance fees	18,061	34,867
Stock-based compensation expense	211,481	244,520
PPP loan forgiven	(56,680)
Gain on sale of assets	(3,919,323)
Impairment of oil and gas properties		396,922
Loss on forfeiture	132,000	6,255,103
Accounts receivable	(1,097)
Prepaids and other current assets	33,802	346,114
Accounts payable	88,190	462,979
Accounts payable – related parties	56,776	(25,000)
Accrued liabilities	178,194	792,578
Accrued liabilities – related parties	450,424	(281,615)
Net cash used in operating activities	(105,578)	(277,599)
Cash Flows from Investing Activities
Cash used in investing activities
Cash Flows from Financing Activities
Proceeds from issuance of Series C preferred stock	85,000
Proceeds from notes payable		10,000
Proceeds from Paycheck Protection Loan		56,680
Repayments of notes payable	(120,890)	(68,367)
Proceeds from related party notes payable		657,470
Repayments of related party notes payable		(334,268)
Proceeds from exercise of warrants		119,375
Cash provided by financing activities	(35,890)	440,890
Foreign currency remeasurement	481	(42,759)
Net change in cash	(140,987)	120,532
Cash at beginning of period	155,045	34,513
Cash at end of period	14,058	155,045
SUPPLEMENTAL DISCLOSURES
Interest paid	239,384	187,662
Income taxes paid
NON-CASH INVESTING AND FINANCIAL DISCLOSURES
Settlement of related party accrued liabilities for common shares	527,520	77,500
Settlement of notes payable related party for common shares	144,888
Modification of related party debt	181,791
Debt discount on warrant issue		499,170
Shares to be issued		119,375
Shares issued for related party expense		20,000
Issuing of previous shares to be issued		55,375
Accrued Series A preferred dividends	179,190	178,699
Accrued Series C preferred dividends	779
Series B Preferred Stock issued to directors	152,397
Utikuma acquisition – purchase price		678,675
Utikuma acquisition – initial ARO		906,146
Utikuma acquisition – extra cost triggered by WTI	787,250
Third party loan for Utikuma purchase		1,120,000
Related party loan payments on Company’s behalf		170,000
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
Beginning balance, value at Dec. 31, 2019	$ 199			$ 164,549	$ 57,985,359	$ 55,375	$ (218,565)	$ (52,600,378)	$ 5,386,539
Beginning balance, shares at Dec. 31, 2019	199,100			164,548,726
Common shares issued for the exercise of warrants				$ 2,650	116,725				119,375
Common shares issued for the exercise of warrants, shares				2,650,000
Stock based compensation					244,520				244,520
Shares issued for extinguishment of debt				$ 656	89,344				90,000
Shares issued for extinguishment of debt, shares				656,250
Warrants issued as financing fee					34,867				34,867
Common shares issued for services				$ 250	19,750				20,000
Common shares issued for services, shares				250,000
Series A preferred dividends								(178,699)	(178,699)
Shares to be issued				$ 591	54,784	(55,375)
Shares to be issued, shares				591,250
Warrants issued for loans					499,170				499,170
Other comprehensive income (loss)							(47,867)		(47,867)
Net income (loss)								(10,309,019)	(10,309,019)
Ending balance, value at Dec. 31, 2020	$ 199			$ 168,696	59,044,519		(266,432)	(63,088,096)	(4,141,114)
Ending 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
Warrants issued as financing fee					18,061				18,061
Series A preferred dividends								(179,190)	(179,190)
Other comprehensive income (loss)							(2,723)		(2,723)
Net income (loss)								1,928,904	1,928,904
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
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
Ending balance, value at Dec. 31, 2021	$ 199	$ 152,397	$ 850	$ 176,988	$ 60,216,722		$ (269,155)	$ (61,339,161)	$ (1,061,160)
Ending balance, shares at Dec. 31, 2021	199,100	3	8,500	176,988,322

ORGANIZATION AND BASIS OF PRESE

ORGANIZATION AND BASIS OF PRESENTATION	12 Months Ended
	Dec. 31, 2021
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, 2021
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, 2021, 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 has 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 2021 and 2020. 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, 2020 Derivative liabilities — — 183,798 183,798 ARO liabilities — — 3,624,133 3,624,133 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 other than those discussed below. Leases In February 2016, the FASB issued ASU 2016-02, “Leases” Under ASU 2016-02, each lease agreement will be evaluated to identify the lease components and non-lease components at lease inception. The total consideration in the lease agreement will be allocated to the lease and non-lease components based on their relative standalone selling prices. In July 2018, the FASB issued ASU 2018-11, “Leases – Targeted Improvements” The Company adopted ASU 2016-02 on January 1, 2019 using the modified retrospective method, whereby a cumulative effect adjustment will be made as of that day with no retrospective effect. The Company applied the package of practical expedients such that for any expired or existing leases it will not reassess lease classification, initial direct costs or whether any expired or existing contracts are or contain leases. Note that the Company had no outstanding leases as of December 31, 2019. In 2020, we entered a lease with a related party, that is accounted for and disclosed using the framework of ASC 842. See Note 6 for more details.

GOING CONCERN

GOING CONCERN	12 Months Ended
	Dec. 31, 2021
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 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, 2021
Extractive Industries [Abstract]
EVALUATED PROPERTIES	NOTE 4. EVALUATED PROPERTIES The acquired properties and current properties can be summarized as follows: SCHEDULE OF COMPANY’S CURRENT PROPERTIES Cost Canadian properties US properties Total As of December 31, 2019 2,563,434 $ 10,350,538 $ 12,913,972 Additions 678,765 — 678,765 Dispositions — (5,648,994 ) (5,648,994 ) Impairment of oil and gas properties (396,922 ) (396,922 ) Asset retirement cost additions 906,146 — 906,146 Foreign currency translations 166,460 — 166,460 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 Accumulated depletion As of December 31, 2019 1,458,976 61,551 1,520,347 Depletion 1,115,595 — 1,115,595 Foreign currency translations 57,178 — 57,178 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 Net book value as at December 31, 2021 $ 2,104,994 $ 4,243,071 $ 6,348,065 Net book value as at December 31, 2020 $ 1,683,056 $ 4,243,071 $ 5,926,127 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 Sands (“SUDS”) Field The SUDS Field is a 2604-acre lease located in Creek County, Oklahoma. The field was first discovered in 1918 by SOHIO Oil Company utilizing over 100 wells with the primary objective to produce from the Dutcher Sands at an average well depth of 3,100 ft. The SUDS field is currently shut in due to damage from a grass fire. U.S. properties – Twin Lakes San Andres Unit (“TLSAU”) Field TLSAU is located 45 miles from Roswell, Chaves County, New Mexico. On July 27, 2020 the Company entered into a settlement agreement with their Trustee pursuant to which nine leases totaling approximately 3,800 4,880 56% 943,820 10,175,456 5,648,994 10,175,456 56% 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% ) working interest in the Cuthbert, Luseland and Heart Hills assets in Saskatchewan and Alberta. Under these agreements Prospera will forgive $ 2,061,614 CAD in accounts payable from the Company, arising from joint interest billings. Prospera will also issue a $ 510,000 CAD convertible debenture to Petrolia Canada, which can be converted to common share units. Lastly, Prospera will pay the Company $ 75,000 CAD in five equal installments. The original purchase price of the assets was $ 1,622,756 CAD, with an additional $ 1,711,142 CAD of Asset Retirement Cost recognized at the time of purchase. On the effective date of the sale, the Asset Retirement Obligation was $ 2,312,897 CAD and the Accumulated Depletion was $ 3,333,898 CAD. The transaction resulted in a gain of $ 4,959,512 CAD ($ 3,919,323 USD) See Form 8-K reference in Exhibits section below. The agreement was effective on October 1, 2021. 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 ($602,423 USD), necessary for the wells to continue in production after the acquisition. Additional funds ($386,989 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 June 13, 2022, a new Letter Agreement was signed between Blue Sky Resources Ltd. (“BSR”) and Petrolia Energy Corporation whereby Petrolia Canada Corporation (“PCC”) will sell to Blue Sky Resources its 50%

NOTES PAYABLE

NOTES PAYABLE	12 Months Ended
	Dec. 31, 2021
Debt Disclosure [Abstract]
NOTES PAYABLE	NOTE 5. NOTES PAYABLE SCHEDULE OF NOTES PAYABLE Interest rate Date of maturity December 31, 2021 December 31, 2020 Truck loan (ii) 5.49 % January 20, 2022 $ 4,021 $ 9,916 Credit note I (iii) 12 % May 11, 2021 — 800,000 Credit note II (iv) 12 % October 17, 2019 — 346,038 Credit note III (v) 15 % April 25, 2021 — 750,000 Discount on credit note III — — — (5,976 ) Credit note IV (vi) 10 % January 01, 2020 831,387 937,019 Discount on credit note IV (97,001 ) (285,767 ) Credit note V (vii) 10 % December 31, 2022 2,085,432 — Lee Lytton On demand 3,500 3,500 Joel Oppenheim (viii) 10 % On demand — 161,900 Joel Oppenheim (viii) 10 % On demand — 15,000 Joel Oppenheim (viii) 10 % October 17, 2018 — 240,000 Credit note VI (viii) 10 % December 31, 2021 416,900 — Origin Bank (PPP loan) (ix) — 56,680 Quinten Beasley 10 % October 14, 2016 5,000 — Jovian Petroleum Corporation (x) 3.5 % December 31, 2021 178,923 — M. Hortwitz 10 % October 14, 2016 10,000 10,000 $ 3,438,162 (1) $ 3,038,310 (i) All notes are current (due within one year or less from December 31, 2021.) (ii) On January 6, 2017, the Company purchased a truck and entered into an installment note in the amount of $ 35,677 5.49% 683 (iii) On May 9, 2018, Bow entered into an Amended and Restated Loan Agreement with a third party. The Loan Agreement increased by $ 800,000 1,530,000 12% 19% May 11, 2021 10,000 710,000 800,000 25% 41,526 730,000 In order to induce the Lender to enter into the Loan Agreement, the Company agreed to issue the Lender 500,000 2,320,000 320,000 0.10 May 15, 2021 500,000 0.12 May 15, 2021 1,500,000 0.10 May 15, 2020 500,000 47,500 30,012 182,650 260,162 On January 1, 2021, the Lender signed an amended loan agreement, combining Credit note I and $ 200,000 On December 1, 2021, the Lender signed another amended loan agreement, combining the new note with the combined note of Credit note III and $ 146,038 (iv) On September 17, 2018, the Company entered into a loan agreement with a third party for $ 200,000 3% 12% October 17, 2019 6,000 3% 146,000 346,038 (v) On April 25, 2019, the Company entered into a promissory note (an “Acquisition Note”) with a third-party in the amount of $ 750,000 9% April 25, 2021 500,000 0.12 May 1, 2021 38,249 8,366 146,038 On December 1, 2021, the Lender signed another amended loan agreement, combining the new note with the combined note of Credit note I and $ 200,000 (vi) On January 2, 2020, the Company entered into a loan agreement in the amount of $ 1,000,000 120,000 10% 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 (vii) On December 1, 2021, the Company signed an amended loan agreement with third party for $ 2,085,432 10% December 31, 2022 25% (viii) Various shareholder advances provided by Mr. 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 (ix) On April 23, 2020, the Company was granted a $ 56,680 July 26, 2021 (x) 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, 2021: SCHEDULE OF FUTURE MINIMUM REPAYMENTS OF NOTES PAYABLE 2022 $ 3,535,163 Thereafter — Total $ 3,535,163

LEASES

LEASES	12 Months Ended
	Dec. 31, 2021
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, 2021 and 2020, 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, 2021 December 31, 2020 Right-of-use assets Other long-term assets 12,821 23,145 Current lease liabilities Other current liabilities 13,909 13,107 Non-current lease liabilities Other long-term liabilities — 13,909 As of December 31, 2021, our maturities of our lease liability are as follows: SCHEDULE OF MATURITIES LEASE LIABILITY 2022 $ 13,909 Total $ 13,909 Less: Imputed interest (1,088 ) Present value of lease liabilities $ 12,821

RELATED PARTY NOTES PAYABLE

RELATED PARTY NOTES PAYABLE	12 Months Ended
	Dec. 31, 2021
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, 2021 and 2020. SCHEDULE OF RELATED PARTY NOTES PAYABLE Interest rate Date of maturity December 31, 2021 December 31, 2020 Quinten Beasley 10 % October 14, 2016 — 5,000 Jovian Petroleum Corporation (i) 3.5 % December 31, 2021 — 188,285 Ivar Siem (ii) 12 % On demand — 200,000 Ivar Siem (ii) No interest On demand — 50,000 Ivar Siem (ii) 9 % December 31, 2021 278,435 — Mark Allen (iii) 9 % September 2, 2021 55,000 55,000 Mark Allen (iv) 10 % June 30, 2021 — 135,000 Mark Allen (v) 12 % June 30, 2020 200,000 200,000 Mark Allen (vi) 10 % June 30, 2020 — 100,000 Discount on note ($100K) — (11,536 ) Mark Allen (vi) 10 % June 30, 2020 — 125,000 Discount on note ($125K) — (11,420 ) Mark Allen (vi) 9 % June 30, 2021 245,938 — $ 779,373 $ 1,035,329 (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 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 21, 2021 (iii) 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% August 15, 2021 (iv) On January 6, 2020, the Company entered into a consulting agreement with Mark Allen, that included a funding clause where the Company borrowed $ 135,000 62,000 45,000 28,000 10% June 30, 2020 (v) During 2019, the Company entered into a loan agreement in the amount of $ 200,000 12% 2,500,000 0.08 10,000,000 0.10 (vi) On January 3, 2020, the Company entered into a loan agreement in the amount of $ 100,000 10% 400,000 0.10 January 3, 2023 31,946 1,775 125,000 750,000 0.10 38,249 1,903 245,938 9% June 30, 2021 The following is a schedule of future minimum repayments of related party notes payable as of December 31, 2021: SCHEDULE OF FUTURE MINIMUM REPAYMENTS OF RELATED PARTY NOTES PAYABLE 2022 $ 779,373 Thereafter — Total $ 779,373

DERIVATIVE FINANCIAL INSTRUMENT

DERIVATIVE FINANCIAL INSTRUMENTS	12 Months Ended
	Dec. 31, 2021
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 On January 06, 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 A summary of the activity of the derivative liabilities is shown below: SCHEDULE OF DERIVATIVE LIABILITIES Balance, December 31, 2020 $ 183,798 Additions — Fair value adjustments (161,244 ) As of December 31, 2021 $ 22,554 Derivative liability classified warrants in the years ended December 31, 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 DERIVATIVE LIABILITY OF FAIR VALUE ASSUMPTION December 31, 2021 Risk-free interest rate 0.39 % Expected life 1 Expected dividend rate 0 % Expected volatility 365 %

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Dec. 31, 2021
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, 2021 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, 2021, and 2020: SCHEDULE OF ASSET RETIREMENT OBLIGATIONS Canadian properties United States properties Total Asset retirement obligations, December 31, 2019 $ 1,445,991 $ 277,373 1,723,364 Acquisition of Canadian property - Utikuma 906,146 — 906,146 Plugging liability at Twin Lakes — 606,109 606,109 Accretion expense 259,016 28,742 287,758 Disposition — — — Foreign currency translation 100,756 — 100,756 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

EQUITY

EQUITY	12 Months Ended
	Dec. 31, 2021
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 Preferred Stock, cumulative dividends of $ 179,190 178,699 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 $ 779 0 Common stock During the year ended December 31, 2019, the Company closed private placements for $ 0.08 1,875,000 150,000 Each 2019 Unit was comprised of one common share and two warrants entitling the holder to exercise such warrant for one common share for a period of two years from the date of issuance. The warrants have exercise price of $ 0.10 On July 23, 2019, director Joel Martin Oppenheim purchased additional 2019 private placements for $ 0.08 156,250 12,500 0.10 2,500 10,000 On August 8, 2019, director Joel Martin Oppenheim exercised warrants to purchase 150,000 15,000 0.10 On August 14, 2019, director Joel Martin Oppenheim exercised warrants to purchase 10,000 1,000 0.10 During 2019, a Mark Allen exercised warrants to purchase 275,000 26,875 0.098 On January 20, 2020, a related party, purchased 1 unit of the debt private placement with gross proceeds of $12,500 156,250 312,500 0.08 On February 29, 2020, the Company signed a consulting agreement with Mark Allen to provide Management services related to the SUDS field. The compensation related terms included the issuance of 250,000 On September 1, 2020, the Company entered into an employment agreement with Mark Allen, to serve as President for a period of six months (with monthly extensions). The President was to be paid a salary of $ 15,000 2,000,000 1,000,000 1,000,000 1,000,000 0.08 equally vesting over 24 months 36 On December 15, 2020, President Mark Allen exercised warrants to purchase 1,650,000 69,375 0.04 On December 22, 2020, prior CFO Tariq Chaudhary was issued 500,000 77,500 0.15 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 obligation was 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 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 and $ 9,888 135,000 5,400,000 5,400,000 0.08 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, 2019 57,043,836 $ 0.14 Granted 18,650,000 0.15 Exercised (1,650,000 ) 0.08 Expired (33,279,170 ) 0.19 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 As of December 31, 2021, the weighted-average remaining contractual life of warrants outstanding was 1.71 1.39 As of December 31, 2021, the intrinsic value of warrants outstanding is $ 0 0 The table below summarizes warrant issuances during the years ended December 31, 2020, and 2020: SCHEDULE OF WARRANTS ISSUANCE DURING PERIOD Year ended December 31, 2021 2020 Warrants granted: Board of directors and advisory board service 3,000,000 5,250,000 Pursuant to employment agreements — 1,000,000 Pursuant to financing arrangements 1,000,000 1,000,000 Pursuant to consulting agreements — 250,000 Pursuant to loan agreements 5,400,000 11,150,000 Total 9,400,000 18,650,000 Warrants granted in the years ended December 31, 2021, and 2020 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 December 31, 2021 December 31, 2020 Risk-free interest rate 0.16 0.97 % 1.65% 2.38 % Expected life 2.0 3.0 1.0 3.0 Expected dividend rate 0 % 0 % Expected volatility 277 356 % 240 274 % 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, 2021
Related Party Transactions [Abstract]
RELATED PARTY TRANSACTIONS	NOTE 11. RELATED PARTY TRANSACTIONS On January 20, 2020, Jovian Petroleum, a related party, purchased 1 unit of the debt private placement with gross proceeds of $ 12,500 156,250 312,500 0.08 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 $ 1,000,000 787,250 602,423 386,989 On December 15, 2020, President Mark Allen exercised warrants to purchase 1,650,000 69,375 0.04 On August 21, 2019, Leo Womack, a related party, purchased 2 units of the debt private placement with gross proceeds of $ 25,000 312,500 625,000 0.08 31,033 On September 1, 2020, the Company entered into an employment agreement with Mark Allen, to serve as President for a period of six months (with monthly extensions). The President was to be paid a salary of $ 15,000 2,000,000 1,000,000 1,000,000 1,000,000 0.08 36 On December 15, 2020, President Mark Allen exercised warrants to purchase 1,650,000 69,375 0.04 On December 15, 2020, in accordance with the Mark Allen’s Consulting agreement that was signed prior to the Employment agreement, the Company issued Mr. Allen 250,000 On December 22, 2020, prior CFO Tariq Chaudhary was issued 500,000 77,500 0.15 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%) of the total vote on all shareholder matters, voting separately as a class. This stock was valued by and independent party at $50,799 per share. For further information, see Form 8-K reference in Exhibits section. 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, 2021
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	NOTE 12. COMMITMENTS AND CONTINGENCIES Environmental Matters – Office Lease 1,500 As mentioned in Note 6, the Company holds 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.

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2021
Income Tax Disclosure [Abstract]
INCOME TAXES	NOTE 13. INCOME TAXES There was no provision for income taxes for 2021 and 2020 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 $ 405,000 $ (2,078,000 ) Non-deductible items 49,000 85,000 Change in statutory, foreign tax, foreign exchange rates and other (559,000 ) (2,427,000 ) Change in valuation allowance (105,000 ) 4,420,000 Total $ — $ — The significant components of the net deferred tax asset were as follows: SCHEDULE OF DEFERRED TAX ASSETS 2021 2020 December 31, 2021 2020 Deferred tax assets Net operating loss carryforwards $ 6,038,000 $ 5,772,000 Asset retirement obligation 498,000 679,000 Oil and gas properties (593,000 ) (644,000 ) Property and equipment — 6,000 Other — — Total deferred tax assets (liabilities) 5,943,000 5,813,000 Less: Valuation allowance (5,943,000 ) (5,813,000 ) 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 $ 2.2 begin to expire if not utilized beginning in the year 2033 27.5 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, 2021
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, 2020 Revenue $ 2,860,324 $ 31,917 $ 2,892,241 Production costs (3,377,055 ) (253,552 ) (3,630,607 ) Depreciation, depletion, amortization and accretion (1,374,611 ) (60,429 ) (1,435,040 ) Results of operations from producing activities $ (1,891,342 ) $ (282,064 ) $ (2,173,406 ) Total long-lived assets $ 1,683,055 $ 4,767,628 $ 5,952,083 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 The Company’s revenues are derived from the following major customers: SCHEDULE OF REVENUES December 31, 2021 December 31, 2020 Customer A $ 796,176 $ 2,860,324 Customer B 12,729 31,917 Customer C 5,086,323 — Total revenues $ 5,895,228 $ 2,892,241

SUPPLEMENTAL INFORMATION RELATI

SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)	12 Months Ended
	Dec. 31, 2021
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, 2021 Fiscal Year Ended December 31, 2020 Property acquisitions $ 787,250 $ 678,765 Unevaluated — — Evaluated — — Exploration — — Development — — Total costs incurred $ 787,250 $ 678,765 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, 2021 December 31, 2020 Capitalized costs: Unevaluated properties $ — $ — Evaluated properties 5,511,480 6,456,367 Gross capitalized costs 5,511,480 6,456,367 Less: Accumulated DD&A (448,960 ) (2,693,300 ) Net capitalized costs $ 5,062,520 $ 3,763,067 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, 2021 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, 2020. 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 Oil (Bbls) December 31, 2019 1,800,457 Revisions of prior estimates (860,450 ) Purchases of reserves in place 466,800 Disposition of mineral in place — Production (95,135 ) 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 SCHEDULE OF PROVED DEVELOPMENT AND UNDEVELOPED RESERVES December 31, 2021 December 31, 2020 Estimated quantities of proved developed reserves – Oil (Bbls) 1,449,853 1,245,512 Estimated quantities of proved undeveloped reserves – Oil (Bbls) — 66,160 Proved developed and proved undeveloped reserves increased from December 31, 2020 to December 31, 2021, primarily due the revision of prior estimates, partially offset by the disposition of the CONA asset. 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 Oil (bbls) December 31, 2020 1,245,512 Acquired reserves — Disposition of reserves — Revision of prior estimates 301,425 Production (97,084 ) December 31, 2021 1,449,853 Proved undeveloped reserves Oil (bbls) December 31, 2020 66,160 Disposition of reserves (66,160 ) Revisions to prior estimates — December 31, 2021 — 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, 2021 December 31, 2020 Future cash inflows $ 93,082,624 $ 47,647,500 Future production costs (45,892,778 ) (25,203,830 ) Future development costs (1,867,485 ) (2,148,510 ) Future income taxes — — Future net cash flows 45,322,361 20,295,160 Discount of future net cash flows at 10% 27,929,984 ) (12,339,240 ) Standardized measure of discounted future net cash flows $ 17,392,377 $ 7,956,920 Changes in standardized measure of discounted future cash flows SCHEDULE OF CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE CASH FLOWS December 31, 2021 December 31, 2020 Beginning of year $ 7,956,920 $ 25,824,730 Sales and transfers of oil & gas produced, net of production costs (539,927 ) (735,300 ) Net changes in prices and production costs (865,805 ) (249,508 Changes in estimated future development costs (565,870 ) 96,780 Acquisitions/dispositions of minerals in place, net of production costs (231,470 ) — Revision of previous estimates 1,194,016 (14,938,598 ) Change in discount — 436,490 Change in production rate or other 10,444,513 (2,477,674 ) End of year $ 17,392,377 $ 7,956,920

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	12 Months Ended
	Dec. 31, 2021
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	NOTE 16. SUBSEQUENT EVENTS On February 16, 2022, the Company entered into both a Purchase and Sale Agreement and a Debt Settlement Agreement with Prospera Energy, effective as of October 1, 2021. Prospera agreed to purchase the Company’s twenty-eight percent ( 28% 1,720,613 CAD 510,000 75,000 On March 11, 2022, the Company filed a lawsuit in Harris County Texas against Jovian Petroleum Corporation, Zel Khan and Quinten Beasley. The lawsuit claims fraud and breach of contract against all named defendants, as well as breach of fiduciary duty claims against Zel Khan and Quinten Beasley. Petrolia and Petrolia Canada are demanding a jury trial and are seeking monetary relief of more than $ 1 5,000 On March 16, 2022, Petrolia Canada Corporation received a Notice of Intention to Retain Collateral Pursuant to Section 62 of the Personal Property Security Act (Alberta) from the counsel of Blue Sky Resources Ltd. related to a Loan Agreement and General Security Agreement between Petrolia Canada Corporation and Emmett Lescroart. Petrolia Canada Corporation was notified that Blue Sky Resources Ltd., as assignee of the Emmet Lescroart loan, intends to retain the Utikuma loan collateral pursuant to the General Security Agreement with Petrolia Canada Corporation. On March 30, 2022, Petrolia Canada Corporation’s counsel responded to Blue Sky Resources, Ltd. with a Notice of Objection. On June 13, 2022, a Letter Agreement was signed between Blue Sky Resources Ltd. (“BSR”) and Petrolia Energy Corporation whereby Petrolia Canada Corporation (“PCC”) will sell to Blue Sky Resources its 50% Effective June 15, 2022, Heather Monk was promoted from Corporate Controller to Interim Chief Financial Officer.

SUMMARY OF SIGNIFICANT ACCOUN_2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2021
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, 2021, 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 has 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 2021 and 2020. 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, 2020 Derivative liabilities — — 183,798 183,798 ARO liabilities — — 3,624,133 3,624,133 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 other than those discussed below. Leases In February 2016, the FASB issued ASU 2016-02, “Leases” Under ASU 2016-02, each lease agreement will be evaluated to identify the lease components and non-lease components at lease inception. The total consideration in the lease agreement will be allocated to the lease and non-lease components based on their relative standalone selling prices. In July 2018, the FASB issued ASU 2018-11, “Leases – Targeted Improvements” The Company adopted ASU 2016-02 on January 1, 2019 using the modified retrospective method, whereby a cumulative effect adjustment will be made as of that day with no retrospective effect. The Company applied the package of practical expedients such that for any expired or existing leases it will not reassess lease classification, initial direct costs or whether any expired or existing contracts are or contain leases. Note that the Company had no outstanding leases as of December 31, 2019. In 2020, we entered a lease with a related party, that is accounted for and disclosed using the framework of ASC 842. See Note 6 for more details.

SUMMARY OF SIGNIFICANT ACCOUN_3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2020 Derivative liabilities — — 183,798 183,798 ARO liabilities — — 3,624,133 3,624,133

EVALUATED PROPERTIES (Tables)

EVALUATED PROPERTIES (Tables)	12 Months Ended
	Dec. 31, 2021
Extractive Industries [Abstract]
SCHEDULE OF COMPANY’S CURRENT PROPERTIES	The acquired properties and current properties can be summarized as follows: SCHEDULE OF COMPANY’S CURRENT PROPERTIES Cost Canadian properties US properties Total As of December 31, 2019 2,563,434 $ 10,350,538 $ 12,913,972 Additions 678,765 — 678,765 Dispositions — (5,648,994 ) (5,648,994 ) Impairment of oil and gas properties (396,922 ) (396,922 ) Asset retirement cost additions 906,146 — 906,146 Foreign currency translations 166,460 — 166,460 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 Accumulated depletion As of December 31, 2019 1,458,976 61,551 1,520,347 Depletion 1,115,595 — 1,115,595 Foreign currency translations 57,178 — 57,178 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 Net book value as at December 31, 2021 $ 2,104,994 $ 4,243,071 $ 6,348,065 Net book value as at December 31, 2020 $ 1,683,056 $ 4,243,071 $ 5,926,127

NOTES PAYABLE (Tables)

NOTES PAYABLE (Tables)	12 Months Ended
	Dec. 31, 2021
Debt Disclosure [Abstract]
SCHEDULE OF NOTES PAYABLE	SCHEDULE OF NOTES PAYABLE Interest rate Date of maturity December 31, 2021 December 31, 2020 Truck loan (ii) 5.49 % January 20, 2022 $ 4,021 $ 9,916 Credit note I (iii) 12 % May 11, 2021 — 800,000 Credit note II (iv) 12 % October 17, 2019 — 346,038 Credit note III (v) 15 % April 25, 2021 — 750,000 Discount on credit note III — — — (5,976 ) Credit note IV (vi) 10 % January 01, 2020 831,387 937,019 Discount on credit note IV (97,001 ) (285,767 ) Credit note V (vii) 10 % December 31, 2022 2,085,432 — Lee Lytton On demand 3,500 3,500 Joel Oppenheim (viii) 10 % On demand — 161,900 Joel Oppenheim (viii) 10 % On demand — 15,000 Joel Oppenheim (viii) 10 % October 17, 2018 — 240,000 Credit note VI (viii) 10 % December 31, 2021 416,900 — Origin Bank (PPP loan) (ix) — 56,680 Quinten Beasley 10 % October 14, 2016 5,000 — Jovian Petroleum Corporation (x) 3.5 % December 31, 2021 178,923 — M. Hortwitz 10 % October 14, 2016 10,000 10,000 $ 3,438,162 (1) $ 3,038,310 (i) All notes are current (due within one year or less from December 31, 2021.) (ii) On January 6, 2017, the Company purchased a truck and entered into an installment note in the amount of $ 35,677 5.49% 683 (iii) On May 9, 2018, Bow entered into an Amended and Restated Loan Agreement with a third party. The Loan Agreement increased by $ 800,000 1,530,000 12% 19% May 11, 2021 10,000 710,000 800,000 25% 41,526 730,000 In order to induce the Lender to enter into the Loan Agreement, the Company agreed to issue the Lender 500,000 2,320,000 320,000 0.10 May 15, 2021 500,000 0.12 May 15, 2021 1,500,000 0.10 May 15, 2020 500,000 47,500 30,012 182,650 260,162 On January 1, 2021, the Lender signed an amended loan agreement, combining Credit note I and $ 200,000 On December 1, 2021, the Lender signed another amended loan agreement, combining the new note with the combined note of Credit note III and $ 146,038 (iv) On September 17, 2018, the Company entered into a loan agreement with a third party for $ 200,000 3% 12% October 17, 2019 6,000 3% 146,000 346,038 (v) On April 25, 2019, the Company entered into a promissory note (an “Acquisition Note”) with a third-party in the amount of $ 750,000 9% April 25, 2021 500,000 0.12 May 1, 2021 38,249 8,366 146,038 On December 1, 2021, the Lender signed another amended loan agreement, combining the new note with the combined note of Credit note I and $ 200,000 (vi) On January 2, 2020, the Company entered into a loan agreement in the amount of $ 1,000,000 120,000 10% 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 (vii) On December 1, 2021, the Company signed an amended loan agreement with third party for $ 2,085,432 10% December 31, 2022 25% (viii) Various shareholder advances provided by Mr. 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 (ix) On April 23, 2020, the Company was granted a $ 56,680 July 26, 2021 (x) 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, 2021: SCHEDULE OF FUTURE MINIMUM REPAYMENTS OF NOTES PAYABLE 2022 $ 3,535,163 Thereafter — Total $ 3,535,163

LEASES (Tables)

LEASES (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021 December 31, 2020 Right-of-use assets Other long-term assets 12,821 23,145 Current lease liabilities Other current liabilities 13,909 13,107 Non-current lease liabilities Other long-term liabilities — 13,909
SCHEDULE OF MATURITIES LEASE LIABILITY	As of December 31, 2021, our maturities of our lease liability are as follows: SCHEDULE OF MATURITIES LEASE LIABILITY 2022 $ 13,909 Total $ 13,909 Less: Imputed interest (1,088 ) Present value of lease liabilities $ 12,821

RELATED PARTY NOTES PAYABLE (Ta

RELATED PARTY NOTES PAYABLE (Tables)	12 Months Ended
	Dec. 31, 2021
Related Party Notes Payable
SCHEDULE OF RELATED PARTY NOTES PAYABLE	The chart below summarizes the related party Notes Payable as of December 31, 2021 and 2020. SCHEDULE OF RELATED PARTY NOTES PAYABLE Interest rate Date of maturity December 31, 2021 December 31, 2020 Quinten Beasley 10 % October 14, 2016 — 5,000 Jovian Petroleum Corporation (i) 3.5 % December 31, 2021 — 188,285 Ivar Siem (ii) 12 % On demand — 200,000 Ivar Siem (ii) No interest On demand — 50,000 Ivar Siem (ii) 9 % December 31, 2021 278,435 — Mark Allen (iii) 9 % September 2, 2021 55,000 55,000 Mark Allen (iv) 10 % June 30, 2021 — 135,000 Mark Allen (v) 12 % June 30, 2020 200,000 200,000 Mark Allen (vi) 10 % June 30, 2020 — 100,000 Discount on note ($100K) — (11,536 ) Mark Allen (vi) 10 % June 30, 2020 — 125,000 Discount on note ($125K) — (11,420 ) Mark Allen (vi) 9 % June 30, 2021 245,938 — $ 779,373 $ 1,035,329 (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 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 21, 2021 (iii) 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% August 15, 2021 (iv) On January 6, 2020, the Company entered into a consulting agreement with Mark Allen, that included a funding clause where the Company borrowed $ 135,000 62,000 45,000 28,000 10% June 30, 2020 (v) During 2019, the Company entered into a loan agreement in the amount of $ 200,000 12% 2,500,000 0.08 10,000,000 0.10 (vi) On January 3, 2020, the Company entered into a loan agreement in the amount of $ 100,000 10% 400,000 0.10 January 3, 2023 31,946 1,775 125,000 750,000 0.10 38,249 1,903 245,938 9% June 30, 2021
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, 2021: SCHEDULE OF FUTURE MINIMUM REPAYMENTS OF RELATED PARTY NOTES PAYABLE 2022 $ 779,373 Thereafter — Total $ 779,373

DERIVATIVE FINANCIAL INSTRUME_2

DERIVATIVE FINANCIAL INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2020 $ 183,798 Additions — Fair value adjustments (161,244 ) As of December 31, 2021 $ 22,554
SCHEDULE OF DERIVATIVE LIABILITY OF FAIR VALUE ASSUMPTION	SCHEDULE OF DERIVATIVE LIABILITY OF FAIR VALUE ASSUMPTION December 31, 2021 Risk-free interest rate 0.39 % Expected life 1 Expected dividend rate 0 % Expected volatility 365 %

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2021
Asset Retirement Obligation Disclosure [Abstract]
SCHEDULE OF FAIR VALUE OF ASSET RETIREMENT OBLIGATIONS	SCHEDULE OF FAIR VALUE OF ASSET RETIREMENT OBLIGATIONS December 31, 2021 Inflation rate 1.92 2.15 % Estimated asset life 12 22
SCHEDULE OF ASSET RETIREMENT OBLIGATIONS	SCHEDULE OF ASSET RETIREMENT OBLIGATIONS Canadian properties United States properties Total Asset retirement obligations, December 31, 2019 $ 1,445,991 $ 277,373 1,723,364 Acquisition of Canadian property - Utikuma 906,146 — 906,146 Plugging liability at Twin Lakes — 606,109 606,109 Accretion expense 259,016 28,742 287,758 Disposition — — — Foreign currency translation 100,756 — 100,756 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

EQUITY (Tables)

EQUITY (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2019 57,043,836 $ 0.14 Granted 18,650,000 0.15 Exercised (1,650,000 ) 0.08 Expired (33,279,170 ) 0.19 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
SCHEDULE OF WARRANTS ISSUANCE DURING PERIOD	The table below summarizes warrant issuances during the years ended December 31, 2020, and 2020: SCHEDULE OF WARRANTS ISSUANCE DURING PERIOD Year ended December 31, 2021 2020 Warrants granted: Board of directors and advisory board service 3,000,000 5,250,000 Pursuant to employment agreements — 1,000,000 Pursuant to financing arrangements 1,000,000 1,000,000 Pursuant to consulting agreements — 250,000 Pursuant to loan agreements 5,400,000 11,150,000 Total 9,400,000 18,650,000
SCHEDULE OF FAIR VALUE OF ASSUMPTION	Warrants granted in the years ended December 31, 2021, and 2020 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 December 31, 2021 December 31, 2020 Risk-free interest rate 0.16 0.97 % 1.65% 2.38 % Expected life 2.0 3.0 1.0 3.0 Expected dividend rate 0 % 0 % Expected volatility 277 356 % 240 274 %

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2021
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 $ 405,000 $ (2,078,000 ) Non-deductible items 49,000 85,000 Change in statutory, foreign tax, foreign exchange rates and other (559,000 ) (2,427,000 ) Change in valuation allowance (105,000 ) 4,420,000 Total $ — $ —
SCHEDULE OF DEFERRED TAX ASSETS	The significant components of the net deferred tax asset were as follows: SCHEDULE OF DEFERRED TAX ASSETS 2021 2020 December 31, 2021 2020 Deferred tax assets Net operating loss carryforwards $ 6,038,000 $ 5,772,000 Asset retirement obligation 498,000 679,000 Oil and gas properties (593,000 ) (644,000 ) Property and equipment — 6,000 Other — — Total deferred tax assets (liabilities) 5,943,000 5,813,000 Less: Valuation allowance (5,943,000 ) (5,813,000 ) Net deferred tax assets (liabilities) $ — $ —

SEGMENT REPORTING (Tables)

SEGMENT REPORTING (Tables)	12 Months Ended
	Dec. 31, 2021
Segment Reporting [Abstract]
SCHEDULE OF LONG-LIVED ASSETS	SCHEDULE OF LONG-LIVED ASSETS Canada United States Total Year ended December 31, 2020 Revenue $ 2,860,324 $ 31,917 $ 2,892,241 Production costs (3,377,055 ) (253,552 ) (3,630,607 ) Depreciation, depletion, amortization and accretion (1,374,611 ) (60,429 ) (1,435,040 ) Results of operations from producing activities $ (1,891,342 ) $ (282,064 ) $ (2,173,406 ) Total long-lived assets $ 1,683,055 $ 4,767,628 $ 5,952,083 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
SCHEDULE OF REVENUES	The Company’s revenues are derived from the following major customers: SCHEDULE OF REVENUES December 31, 2021 December 31, 2020 Customer A $ 796,176 $ 2,860,324 Customer B 12,729 31,917 Customer C 5,086,323 — Total revenues $ 5,895,228 $ 2,892,241

SUPPLEMENTAL INFORMATION RELA_2

SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021 Fiscal Year Ended December 31, 2020 Property acquisitions $ 787,250 $ 678,765 Unevaluated — — Evaluated — — Exploration — — Development — — Total costs incurred $ 787,250 $ 678,765
SCHEDULE OF CAPITALIZED COSTS IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT	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, 2021 December 31, 2020 Capitalized costs: Unevaluated properties $ — $ — Evaluated properties 5,511,480 6,456,367 Gross capitalized costs 5,511,480 6,456,367 Less: Accumulated DD&A (448,960 ) (2,693,300 ) Net capitalized costs $ 5,062,520 $ 3,763,067
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 Oil (Bbls) December 31, 2019 1,800,457 Revisions of prior estimates (860,450 ) Purchases of reserves in place 466,800 Disposition of mineral in place — Production (95,135 ) 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
SCHEDULE OF PROVED DEVELOPMENT AND UNDEVELOPED RESERVES	SCHEDULE OF PROVED DEVELOPMENT AND UNDEVELOPED RESERVES December 31, 2021 December 31, 2020 Estimated quantities of proved developed reserves – Oil (Bbls) 1,449,853 1,245,512 Estimated quantities of proved undeveloped reserves – Oil (Bbls) — 66,160 Proved developed and proved undeveloped reserves increased from December 31, 2020 to December 31, 2021, primarily due the revision of prior estimates, partially offset by the disposition of the CONA asset. 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 Oil (bbls) December 31, 2020 1,245,512 Acquired reserves — Disposition of reserves — Revision of prior estimates 301,425 Production (97,084 ) December 31, 2021 1,449,853 Proved undeveloped reserves Oil (bbls) December 31, 2020 66,160 Disposition of reserves (66,160 ) Revisions to prior estimates — December 31, 2021 —
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, 2021 December 31, 2020 Future cash inflows $ 93,082,624 $ 47,647,500 Future production costs (45,892,778 ) (25,203,830 ) Future development costs (1,867,485 ) (2,148,510 ) Future income taxes — — Future net cash flows 45,322,361 20,295,160 Discount of future net cash flows at 10% 27,929,984 ) (12,339,240 ) Standardized measure of discounted future net cash flows $ 17,392,377 $ 7,956,920
SCHEDULE OF CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE CASH FLOWS	Changes in standardized measure of discounted future cash flows SCHEDULE OF CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE CASH FLOWS December 31, 2021 December 31, 2020 Beginning of year $ 7,956,920 $ 25,824,730 Sales and transfers of oil & gas produced, net of production costs (539,927 ) (735,300 ) Net changes in prices and production costs (865,805 ) (249,508 Changes in estimated future development costs (565,870 ) 96,780 Acquisitions/dispositions of minerals in place, net of production costs (231,470 ) — Revision of previous estimates 1,194,016 (14,938,598 ) Change in discount — 436,490 Change in production rate or other 10,444,513 (2,477,674 ) End of year $ 17,392,377 $ 7,956,920

SCHEDULE OF DERIVATIVE LIABILIT

SCHEDULE OF DERIVATIVE LIABILITIES MEASURED AT FAIR VALUE ON RECURRING BASIS (Details) - USD ($)	Dec. 31, 2021	Dec. 31, 2020
Defined Benefit Plan Disclosure [Line Items]
Derivative liabilities	$ 22,554	$ 183,798
ARO liabilities	2,257,027	3,624,133
Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Derivative liabilities
ARO liabilities
Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Derivative liabilities
ARO liabilities
Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Derivative liabilities	22,554	183,798
ARO liabilities	$ 2,257,027	$ 3,624,133

SUMMARY OF SIGNIFICANT ACCOUN_4

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Accounting Policies [Abstract]
Cash equivalents	$ 0
Income tax, interest or penalties	$ 0	$ 0

SCHEDULE OF COMPANY_S CURRENT P

SCHEDULE OF COMPANY’S CURRENT PROPERTIES (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment [Line Items]
Evaluated properties, beginning balance	$ 8,619,427	$ 12,913,972
Cost, Additions	787,250	678,765
Cost, Disposition	(2,563,434)	(5,648,994)
Cost, Impairment of oil and gas properties		396,922
Cost, Impairment of oil and gas properties		(396,922)
Cost, Asset retirement cost additions		906,146
Cost, Foreign currency translation	(46,218)	166,460
Evaluated properties, ending balance	6,797,025	8,619,427
Oil and Gas Property, Full Cost Method, Depletion, beginning balance	2,693,300	1,520,347
Accumulated depletion, Depletion	378,306	1,115,595
Accumulated depletion, Foreign currency translation	7,026	57,178
Accumulated depletion, Dispositions	(2,629,672)
Oil and Gas Property, Full Cost Method, Depletion, ending balance	448,960	2,693,300
Net book value as at ending balance	6,348,065	5,926,127
Canadian Properties [Member]
Property, Plant and Equipment [Line Items]
Evaluated properties, beginning balance	4,314,805	2,563,434
Cost, Additions	787,250	678,765
Cost, Disposition	(2,563,434)
Cost, Asset retirement cost additions		906,146
Cost, Foreign currency translation	(46,218)	166,460
Evaluated properties, ending balance	2,492,403	4,314,805
Oil and Gas Property, Full Cost Method, Depletion, beginning balance	2,631,749	1,458,976
Accumulated depletion, Depletion	378,306	1,115,595
Accumulated depletion, Foreign currency translation	7,026	57,178
Accumulated depletion, Dispositions		(2,629,672)
Oil and Gas Property, Full Cost Method, Depletion, ending balance	387,409	2,631,749
Net book value as at ending balance	2,104,994	1,683,056
US Properties [Member]
Property, Plant and Equipment [Line Items]
Evaluated properties, beginning balance	4,304,622	10,350,538
Cost, Additions
Cost, Disposition		(5,648,994)
Cost, Impairment of oil and gas properties		(396,922)
Cost, Impairment of oil and gas properties		396,922
Cost, Asset retirement cost additions
Cost, Foreign currency translation
Evaluated properties, ending balance	4,304,622	4,304,622
Oil and Gas Property, Full Cost Method, Depletion, beginning balance	61,551	61,551
Accumulated depletion, Depletion
Accumulated depletion, Foreign currency translation
Accumulated depletion, Dispositions
Oil and Gas Property, Full Cost Method, Depletion, ending balance	61,551	61,551
Net book value as at ending balance	$ 4,243,071	$ 4,243,071

EVALUATED PROPERTIES (Details N

EVALUATED PROPERTIES (Details Narrative)

3 Months Ended

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, 2021 CAD ($)

Dec. 31, 2021 USD ($) a

Dec. 31, 2020 USD ($)

Jun. 13, 2022

Dec. 31, 2021 CAD ($) a

Feb. 12, 2021 USD ($)

Jul. 27, 2020 USD ($) a shares

May 29, 2020 a

Feb. 28, 2020 USD ($)

Jan. 02, 2020 USD ($)

Sep. 30, 2019 USD ($)

Aug. 15, 2019 USD ($)

Apr. 25, 2019 USD ($)

Dec. 31, 2018 USD ($)

Jun. 29, 2018 a

Jun. 01, 2018 CAD ($)

Jan. 06, 2017

Reserve Quantities [Line Items]

Area of land | a

28,000

Debt interest rate

5.49%

Increased working interest

28%

50%

28%

Asset Retirement Obligation

$ 2,257,027

$ 3,624,133

Acquisition Note [Member]

Reserve Quantities [Line Items]

Debt instrument face amount

$ 750,000

Debt interest rate

9%

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.

Blue Sky [Member]

Reserve Quantities [Line Items]

Percentage of working interest acquired

3%

80%

Purchase price

$ 1,096,216

$ 1,428,581

Cash payment

782,441

$ 1,022,400

Debt instrument face amount

$ 313,775

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 ($602,423 USD), necessary for the wells to continue in production after the acquisition. Additional funds ($386,989 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

$ 406,181

Blue Sky Resources Ltd [Member]

Reserve Quantities [Line Items]

Area of land | a

28,000

Settlement Agreement [Member]

Reserve Quantities [Line Items]

Reserves forfeited percentage

56%

[custom:PoolsReservesForfeited-0] | shares

943,820

Net property balance

$ 10,175,456

Property write down value

$ 5,648,994

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

$ 200,000

$ 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

Other income

$ 200,000

Letter Agreement [Member] | Blue Sky Resources Ltd [Member]

Reserve Quantities [Line Items]

Increased working interest

50%

Moon Company [Member] | Settlement Agreement [Member]

Reserve Quantities [Line Items]

Area of land | a

3,800

TLSAU [Member]

Reserve Quantities [Line Items]

Area of land | a

4,880

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

Reserve Quantities [Line Items]

Debt Instrument, Decrease, Forgiveness

$ 2,061,614

$ 1,720,613

Convertible Debt

510,000

Repayments of Convertible Debt

75,000

Assets consideration

1,622,756

[custom:AdditionalAssetRetirementCostRecognized]

1,711,142

Asset Retirement Obligation

2,312,897

Depletion

3,333,898

[custom:GainOnAssetsAcquistion]

$ 4,959,512

$ 3,919,323

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

Reserve Quantities [Line Items]

Area of land | a

28,000

Increased working interest

50%

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]

Leasehold net revenue interest, percentage

83%

Assets 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

SUDS [Member]

Reserve Quantities [Line Items]

Acquired field, description

The SUDS Field is a 2604-acre lease located in Creek County, Oklahoma. The field was first discovered in 1918 by SOHIO Oil Company utilizing over 100 wells with the primary objective to produce from the Dutcher Sands at an average well depth of 3,100 ft. The SUDS field is currently shut in due to damage from a grass fire.

Luseland, Hearts Hill and Cuthbert Fields [Member]

Reserve Quantities [Line Items]

Assets working interest

25%

Area of land | a

41,526

Luseland, Hearts Hill and Cuthbert Fields [Member] | Loan Agreement [Member]

Reserve Quantities [Line Items]

Assets working interest

25%

25%

Area of land | a

41,526

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, 2021	Dec. 31, 2020	Jan. 06, 2017
Short-term Debt [Line Items]
Interest rate				5.49%
Notes payable		$ 3,438,162	$ 3,038,310
Truck Loan [Member]
Short-term Debt [Line Items]
Interest rate	[1]	5.49%
Date of maturity	[1]	Jan. 20, 2022
Notes payable	[1]	$ 4,021	9,916
Credit Note I [Member]
Short-term Debt [Line Items]
Interest rate	[2]	12%
Date of maturity	[2]	May 11, 2021
Notes payable	[2]		800,000
Credit Note II [Member]
Short-term Debt [Line Items]
Interest rate	[3]	12%
Date of maturity	[3]	Oct. 17, 2019
Notes payable	[3]		346,038
Credit Note III [Member]
Short-term Debt [Line Items]
Interest rate	[4]	15%
Date of maturity	[4]	Apr. 25, 2021
Notes payable	[4]		750,000
Discount on Credit Note III [Member]
Short-term Debt [Line Items]
Discount			5,976
Discount			(5,976)
Credit Note IV [Member]
Short-term Debt [Line Items]
Interest rate	[5]	10%
Date of maturity	[5]	Jan. 01, 2020
Notes payable	[5]	$ 831,387	937,019
Discount on Credit Note IV [Member]
Short-term Debt [Line Items]
Discount		97,001	285,767
Discount		$ (97,001)	(285,767)
Credit Note V [Member]
Short-term Debt [Line Items]
Interest rate	[6]	10%
Date of maturity	[6]	Dec. 31, 2022
Notes payable	[6]	$ 2,085,432
Lee Lytton [Member]
Short-term Debt [Line Items]
Notes payable		$ 3,500	3,500
Joel Oppenheim [Member]
Short-term Debt [Line Items]
Interest rate	[7]	10%
Notes payable	[7]		161,900
Joel Oppenheim I [Member]
Short-term Debt [Line Items]
Interest rate	[7]	10%
Notes payable	[7]		15,000
Joel Oppenheim II [Member]
Short-term Debt [Line Items]
Interest rate	[7]	10%
Date of maturity		Oct. 17, 2018
Notes payable	[7]		240,000
Credit Note VI [Member]
Short-term Debt [Line Items]
Interest rate	[7]	10%
Date of maturity	[7]	Dec. 31, 2021
Notes payable	[7]	$ 416,900
Origin Bank (PPP Loan) [Member]
Short-term Debt [Line Items]
Notes payable	[8]		56,680
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	[9]	3.50%
Date of maturity	[9]	Dec. 31, 2021
Notes payable	[9]	$ 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]On January 6, 2017, the Company purchased a truck and entered into an installment note in the amount of $ 35,677 5.49% 683 800,000 1,530,000 12% 19% May 11, 2021 10,000 710,000 800,000 25% 41,526 730,000 200,000 3% 12% October 17, 2019 6,000 3% 146,000 346,038 750,000 9% April 25, 2021 500,000 0.12 May 1, 2021 38,249 8,366 146,038 1,000,000 120,000 10% 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 2,085,432 10% December 31, 2022 25% 416,900 10% December 31, 2021 56,680 July 26, 2021 200,000 500,000 25% 3.5%

SCHEDULE OF NOTES PAYABLE (De_2

SCHEDULE OF NOTES PAYABLE (Details) (Parenthetical)

12 Months Ended

Dec. 02, 2021 USD ($)

Feb. 12, 2021 USD ($)

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

Apr. 23, 2020 USD ($)

Jan. 02, 2020 USD ($) shares

Apr. 25, 2019 USD ($) $ / shares shares

Sep. 17, 2018 USD ($)

May 18, 2018 $ / shares shares

May 09, 2018 USD ($) $ / shares shares

Dec. 31, 2021 USD ($) a

Dec. 31, 2020 USD ($)

Dec. 12, 2021 USD ($)

Jan. 02, 2021 USD ($)

May 01, 2020 a

Feb. 28, 2020 USD ($) shares

Feb. 28, 2020 $ / shares

Jan. 02, 2020 $ / shares

Jun. 29, 2018 a

Jun. 08, 2018

Jun. 01, 2018

Apr. 12, 2018 USD ($)

Feb. 19, 2018

Feb. 09, 2018 USD ($)

Jan. 06, 2017 USD ($)

Short-term Debt [Line Items]

Debt interest rate

5.49%

Notes payable current

$ 3,438,162

$ 3,037,737

$ 683

Repayment of notes

120,890

68,367

Area of land | a

28,000

Notes payable

3,438,162

3,038,310

Number of common stock issued, value

119,375

Fair value of warrants issued

18,061

34,867

Working interest percentage

3%

Amortization of debt discount

$ 217,699

209,570

Jovian Petroleum Corporation [Member]

Short-term Debt [Line Items]

Ownership interest

25%

25%

Jovian Petroleum Corporation [Member]

Short-term Debt [Line Items]

Debt interest rate

[1]

3.50%

Debt maturity date

[1]

Dec. 31, 2021

Luseland, Hearts Hill and Cuthbert Fields [Member]

Short-term Debt [Line Items]

Assets working interest

25%

Area of land | a

41,526

Amended and Restated Loan Agreement [Member]

Short-term Debt [Line Items]

Warrants to acquire of common stock | shares

320,000

Warrant exercise price | $ / shares

$ 0.10

Loan Agreement [Member]

Short-term Debt [Line Items]

Debt face amount

$ 416,900

$ 1,000,000

$ 200,000

$ 50,000

Debt interest rate

10%

10%

0%

12%

Debt default interest rate

19%

Debt maturity date

Dec. 31, 2021

Oct. 17, 2019

Warrants to acquire of common stock | shares

5,000,000

5,000,000

200,000

Warrant exercise price | (per share)

$ 0.10

$ 0.10

$ 0.10

Warrant expiry date

Jan. 02, 2023

Mar. 01, 2022

Working interest percentage

3%

Loan interest percentage

12%

Debt instrument, periodic payment

$ 6,000

Debt instrument, unamortized discount

$ 266,674

Amortization of debt discount

11,111

Origination fee

$ 120,000

Loan Agreement [Member] | Jovian Resources LLC [Member]

Short-term Debt [Line Items]

Revolving line of credit

146,000

Line of credit facility, current borrowing capacity

346,038

Loan Agreement [Member] | Warrant [Member]

Short-term Debt [Line Items]

Warrants to acquire of common stock | shares

5,000,000

Warrant exercise price | $ / shares

$ 0.05

Debt instrument, unamortized discount

$ 166,289

Amortization of debt discount

$ 4,614.14

Warrant expiring date

Jan. 06, 2023

Loan Agreement [Member] | Blue Sky Resources Ltd [Member]

Short-term Debt [Line Items]

Notes payable

$ 730,000

Loan Agreement [Member] | Luseland, Hearts Hill and Cuthbert Fields [Member]

Short-term Debt [Line Items]

Assets working interest

25%

Area of land | a

41,526

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 interest rate

[2]

5.49%

Debt maturity date

[2]

Jan. 20, 2022

Notes payable

[2]

$ 4,021

9,916

Credit Note I [Member]

Short-term Debt [Line Items]

Debt interest rate

[3]

12%

Debt maturity date

[3]

May 11, 2021

Notes payable

[3]

800,000

Credit Note I [Member] | Amended and Restated Loan Agreement [Member] | Bow Energy Ltd [Member]

Short-term Debt [Line Items]

Debt face amount

$ 800,000

Debt interest rate

12%

Notes payable current

$ 710,000

Increase in loan amount

$ 1,530,000

Debt default interest rate

19%

Debt maturity date

May 11, 2021

Repayment of notes

$ 10,000

Credit Note I [Member] | Loan Agreement [Member]

Short-term Debt [Line Items]

Number of common stock issued | shares

500,000

Number of common stock issued, value

$ 47,500

Fair value of warrants issued

30,012

Loss on extinguishment of debt

260,162

Credit Note I [Member] | Loan Agreement [Member] | Canadian Dollars [Member]

Short-term Debt [Line Items]

Fair value of warrants issued

$ 182,650

Credit Note I [Member] | Loan Agreement [Member] | Lender [Member] | Warrant [Member]

Short-term Debt [Line Items]

Warrants to acquire of common stock | shares

2,320,000

Credit Note I [Member] | Loan Agreement [Member] | Lender [Member] | Loan Warrant I [Member]

Short-term Debt [Line Items]

Warrants to acquire of common stock | shares

320,000

Warrant exercise price | $ / shares

$ 0.10

Warrant expiry date

May 15, 2021

Credit Note I [Member] | Loan Agreement [Member] | Lender [Member] | Loan Warrant II [Member]

Short-term Debt [Line Items]

Warrants to acquire of common stock | shares

500,000

Warrant exercise price | $ / shares

$ 0.12

Warrant expiry date

May 15, 2021

Credit Note I [Member] | Loan Agreement [Member] | Lender [Member] | Loan Warrant III [Member]

Short-term Debt [Line Items]

Warrants to acquire of common stock | shares

1,500,000

Warrant exercise price | $ / shares

$ 0.10

Warrant expiry date

May 15, 2020

Credit Note I [Member] | Loan Agreement [Member] | Lender [Member] | Restricted Stock [Member]

Short-term Debt [Line Items]

Number of common stock issued | shares

500,000

Credit Note III and II [Member]

Short-term Debt [Line Items]

Debt face amount

$ 200,000

$ 146,038

Acquisition Note [Member]

Short-term Debt [Line Items]

Debt face amount

$ 750,000

Debt interest rate

9%

9%

Debt maturity date

Apr. 25, 2021

Warrants to acquire of common stock | shares

500,000

Warrant exercise price | $ / shares

$ 0.12

Warrant expiry date

May 01, 2021

Debt instrument, unamortized discount

$ 38,249

Amortization of debt discount

8,366

Credit Note II [Member]

Short-term Debt [Line Items]

Debt face amount

$ 146,038

Debt interest rate

[4]

12%

Debt maturity date

[4]

Oct. 17, 2019

Notes payable

[4]

$ 346,038

Credit note I, II and III [Member]

Short-term Debt [Line Items]

Debt face amount

$ 2,085,432

Debt interest rate

10%

Debt maturity date

Dec. 31, 2022

Assets working interest

25%

Paycheck Protection Program [Member]

Short-term Debt [Line Items]

Debt face amount

$ 56,680

Debt maturity date

Jul. 26, 2021

[1]On February 9, 2018, the Company entered into a Revolving Line of Credit Agreement (“LOC”) for $ 200,000 500,000 25% 3.5% 35,677 5.49% 683 800,000 1,530,000 12% 19% May 11, 2021 10,000 710,000 800,000 25% 41,526 730,000 200,000 3% 12% October 17, 2019 6,000 3% 146,000 346,038

SCHEDULE OF FUTURE MINIMUM REPA

SCHEDULE OF FUTURE MINIMUM REPAYMENTS OF NOTES PAYABLE (Details)	Dec. 31, 2021 USD ($)
Debt Disclosure [Abstract]
2022	$ 3,535,163
Thereafter
Total	$ 3,535,163

SCHEDULE OF FINANCIAL INFORMATI

SCHEDULE OF FINANCIAL INFORMATION LEASE (Details) - USD ($)	Dec. 31, 2021	Dec. 31, 2020
Leases
Right-of-use assets	$ 12,821	$ 23,145
Current lease liabilities	13,909	13,107
Non-current lease liabilities		$ 13,909

SCHEDULE OF MATURITIES LEASE LI

SCHEDULE OF MATURITIES LEASE LIABILITY (Details)	Dec. 31, 2021 USD ($)
Leases
2022	$ 13,909
Total	13,909
Less: Imputed interest	(1,088)
Present value of lease liabilities	$ 12,821

SCHEDULE OF RELATED PARTY NOTES

SCHEDULE OF RELATED PARTY NOTES PAYABLE (Details) - USD ($)		12 Months Ended
		Dec. 31, 2021		Dec. 31, 2020	Jan. 06, 2017
Defined Benefit Plan Disclosure [Line Items]
Interest rate					5.49%
Notes payable - related party		$ 779,373		$ 1,035,329
Quinten Beasley [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest rate		10%
Date of maturity		Oct. 14, 2016
Notes payable - related party				5,000
Jovian Petroleum Corporation [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest rate	[1]	3.50%
Date of maturity	[1]	Dec. 31, 2021
Notes payable - related party	[1]		[2]	188,285
Ivar Siem [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest rate	[2]	12%
Notes payable - related party	[2]			200,000
Ivar Siem One [Member]
Defined Benefit Plan Disclosure [Line Items]
Notes payable - related party	[2]			50,000
Ivar Siem Two [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest rate	[2]	9%
Date of maturity	[2]	Dec. 31, 2021
Notes payable - related party	[2]	$ 278,435
Mark M Allen [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest rate	[3]	9%
Date of maturity	[3]	Sep. 02, 2021
Notes payable - related party	[3]	$ 55,000		55,000
Mark M Allen One [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest rate	[4]	10%
Date of maturity	[4]	Jun. 30, 2021
Notes payable - related party	[4]			135,000
Mark M Allen Two [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest rate	[5]	12%
Date of maturity	[5]	Jun. 30, 2020
Notes payable - related party	[5]	$ 200,000		200,000
Mark M Allen Three [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest rate	[6]	10%
Date of maturity	[6]	Jun. 30, 2020
Notes payable - related party	[6]			100,000
Mark Allen One [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount on related party notes				(11,536)
Discount on related party notes				11,536
Mark M Allen Four [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest rate	[6]	10%
Date of maturity	[6]	Jun. 30, 2020
Notes payable - related party	[6]			125,000
Discount on Mark M Allen One[Member]
Defined Benefit Plan Disclosure [Line Items]
Discount on related party notes				(11,420)
Discount on related party notes				11,420
Mark Allen [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest rate	[6]	9%
Date of maturity	[6]	Jun. 30, 2021
Notes payable - related party	[6]	$ 245,938
[1]On February 9, 2018, the Company entered into a Revolving Line of Credit Agreement (“LOC”) for $ 200,000 500,000 25% 3.5% 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 21, 2021 55,000 9% August 15, 2021 135,000 62,000 45,000 28,000 10% June 30, 2020 200,000 12% 2,500,000 0.08 10,000,000 0.10 100,000 10% 400,000 0.10 January 3, 2023 31,946 1,775 125,000 750,000 0.10 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. 02, 2021 USD ($)

Jan. 02, 2021 USD ($)

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

Apr. 15, 2020 USD ($)

Feb. 14, 2020 USD ($) $ / shares shares

Jan. 06, 2020 USD ($)

Jan. 03, 2020 USD ($) shares

Jan. 02, 2020 USD ($) shares

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

Sep. 17, 2018 USD ($)

Dec. 31, 2021 USD ($)

Dec. 31, 2020 USD ($)

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

Jun. 26, 2020 USD ($)

May 18, 2020 USD ($)

Feb. 28, 2020 USD ($) shares

Feb. 28, 2020 $ / 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 ($)

Jan. 06, 2017

Defined Benefit Plan Disclosure [Line Items]

Debt interest rate

5.49%

Amortization of debt discount

$ 217,699

$ 209,570

Jovian Petroleum Corporation [Member]

Defined Benefit Plan Disclosure [Line Items]

Ownership interest

25%

25%

Loan Agreement [Member]

Defined Benefit Plan Disclosure [Line Items]

Debt interest rate

10%

10%

0%

12%

Debt instrument face amount

$ 416,900

$ 1,000,000

$ 200,000

$ 50,000

Warrant exercise price | (per share)

$ 0.10

$ 0.10

$ 0.10

Warrant to purchase of common stock | shares

5,000,000

5,000,000

200,000

Warrants maturity date

Jan. 02, 2023

Mar. 01, 2022

Debt maturity date

Dec. 31, 2021

Oct. 17, 2019

Amortization of debt discount

$ 11,111

Loan Agreement [Member] | Warrant [Member]

Defined Benefit Plan Disclosure [Line Items]

Warrant exercise price | $ / shares

$ 0.05

Warrant to purchase of common stock | shares

5,000,000

Amortization of debt discount

$ 4,614.14

Jovian Petroleum Corporation [Member]

Defined Benefit Plan Disclosure [Line Items]

Debt interest rate

[1]

3.50%

Debt maturity date

[1]

Dec. 31, 2021

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

Defined Benefit Plan Disclosure [Line Items]

Revolving line of credit

$ 500,000

$ 200,000

Debt interest rate

3.50%

3.50%

Ivar Siem [Member]

Defined Benefit Plan Disclosure [Line Items]

Debt interest rate

[2]

12%

Ivar Siem [Member] | Loan Agreement [Member]

Defined Benefit Plan Disclosure [Line Items]

Debt interest rate

9%

9%

12%

12%

Debt instrument face amount

$ 278,435

$ 278,435

$ 100,000

$ 75,000

Shares issued on conversion of debt | shares

1,250,000

Debt maturity date

Dec. 21, 2021

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

Defined Benefit Plan Disclosure [Line Items]

Shares issued on conversion of debt | shares

5,000,000

Warrant exercise price | $ / shares

$ 0.10

Mark M Allen [Member]

Defined Benefit Plan Disclosure [Line Items]

Debt interest rate

[3]

9%

Debt maturity date

[3]

Sep. 02, 2021

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

Defined Benefit Plan Disclosure [Line Items]

Debt interest rate

9%

9%

10%

12%

Debt instrument face amount

$ 245,938

$ 245,938

$ 125,000

$ 100,000

$ 200,000

Shares issued on conversion of debt | shares

2,500,000

Conversion price | $ / shares

$ 0.08

$ 0.08

Warrant exercise price | (per share)

$ 0.10

$ 0.10

Warrant to purchase of common stock | shares

750,000

400,000

Warrants maturity date

Jan. 03, 2023

Debt maturity date

Jun. 30, 2021

Amortization of debt discount

$ 38,249

$ 31,946

Amortization of debt

$ 1,903

$ 1,775

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

Defined Benefit Plan Disclosure [Line Items]

Shares issued on conversion of debt | shares

10,000,000

Warrant exercise price | $ / shares

$ 0.10

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

Defined Benefit Plan Disclosure [Line Items]

Debt interest rate

9%

10%

Debt instrument face amount

$ 55,000

$ 135,000

Debt maturity date

Aug. 15, 2021

Jun. 30, 2020

Third Party [Member] | Consulting Agreement [Member]

Defined Benefit Plan Disclosure [Line Items]

Debt instrument face amount

$ 62,000

$ 28,000

$ 45,000

[1]On February 9, 2018, the Company entered into a Revolving Line of Credit Agreement (“LOC”) for $ 200,000 500,000 25% 3.5% 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 21, 2021 55,000 9% August 15, 2021

SCHEDULE OF FUTURE MINIMUM RE_2

SCHEDULE OF FUTURE MINIMUM REPAYMENTS OF RELATED PARTY NOTES PAYABLE (Details) - USD ($)	Dec. 31, 2021	Dec. 31, 2020
Related Party Notes Payable
2022	$ 779,373
Thereafter
Total	$ 779,373	$ 1,035,329

SCHEDULE OF DERIVATIVE LIABIL_2

SCHEDULE OF DERIVATIVE LIABILITIES (Details)	12 Months Ended
	Dec. 31, 2021 USD ($)
Investments, All Other Investments [Abstract]
Derivative Liability	$ 183,798
Additions
Fair value adjustments	(161,244)
Derivative Liability	$ 22,554

SCHEDULE OF DERIVATIVE LIABIL_3

SCHEDULE OF DERIVATIVE LIABILITY OF FAIR VALUE ASSUMPTION (Details)	12 Months Ended
	Dec. 31, 2021
Measurement Input, Risk Free Interest Rate [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative liability, measurement input	0.39
Measurement Input, Expected Term [Member]
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative liability, expected life	1 year
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	3.65

DERIVATIVE FINANCIAL INSTRUME_3

DERIVATIVE FINANCIAL INSTRUMENTS (Details Narrative)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	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 shares
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Derivative liability	$ 22,554	$ 183,798
Amended and Restated Loan Agreement [Member]
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Warrants to acquire of common stock | shares							320,000
Warrant exercise price | $ / shares							$ 0.10
Derivative liability							$ 30,012
Acquisition Note [Member]
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Warrants to acquire of common stock | shares					5,000,000
Warrant exercise price | $ / shares					$ 0.10
Derivative liability					$ 144,259
Loan Agreement [Member]
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Warrants to acquire of common stock | shares			5,000,000	200,000		5,000,000
Warrant exercise price | (per share)			$ 0.10	$ 0.10		$ 0.10
Derivative liability			$ 95,352

SCHEDULE OF FAIR VALUE OF ASSET

SCHEDULE OF FAIR VALUE OF ASSET RETIREMENT OBLIGATIONS (Details)	12 Months Ended
	Dec. 31, 2021
Minimum [Member]
Inflation rate	1.92%
Estimated asset life	12 years
Maximum [Member]
Inflation rate	2.15%
Estimated asset life	22 years

SCHEDULE OF ASSET RETIREMENT OB

SCHEDULE OF ASSET RETIREMENT OBLIGATIONS (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment [Line Items]
Asset retirement obligations at beginning of period	$ 3,624,133	$ 1,723,364
Acquisition of Canadian property - Utikuma		906,146
Accretion expense		606,109
Accretion expense	316,873	287,758
Disposition	(1,824,339)
Foreign currency translation	8,360	100,756
Plugging liability at twin lakes	132,000
Asset retirement obligations at end of period	2,257,027	3,624,133
Canadian Properties [Member]
Property, Plant and Equipment [Line Items]
Asset retirement obligations at beginning of period	2,711,909	1,445,991
Acquisition of Canadian property - Utikuma		906,146
Accretion expense
Accretion expense	290,367	259,016
Disposition	(1,824,339)
Foreign currency translation	8,360	100,756
Plugging liability at twin lakes
Asset retirement obligations at end of period	1,186,297	2,711,909
US Properties [Member]
Property, Plant and Equipment [Line Items]
Asset retirement obligations at beginning of period	912,225	277,373
Accretion expense		606,109
Accretion expense	26,506	28,742
Disposition
Foreign currency translation
Plugging liability at twin lakes	152,000
Asset retirement obligations at end of period	$ 1,070,730	$ 912,225

ASSET RETIREMENT OBLIGATIONS (D

ASSET RETIREMENT OBLIGATIONS (Details Narrative) - USD ($)	Apr. 08, 2021	Dec. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment [Line Items]
Legal penalties	$ 35,100
Liabilities		$ 8,899,646	$ 11,301,018
Oil and Gas Properties [Member]
Property, Plant and Equipment [Line Items]
Liabilities	$ 792,000

SCHEDULE OF COMMON STOCK PURCHA

SCHEDULE OF COMMON STOCK PURCHASE WARRANTS ISSUED AND OUTSTANDING (Details) - $ / shares	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Equity [Abstract]
Warrants Outstanding, Beginning balance	40,764,666	57,043,836
Weighted Average Exercise Price, Beginning balance	$ 0.13	$ 0.14
Warrants Outstanding, Granted	9,400,000	18,650,000
Weighted Average Exercise Price, Granted	$ 0.09	$ 0.15
Warrants Outstanding, Exercised		(1,650,000)
Weighted Average Exercise Price, Exercised		$ 0.08
Warrants Outstanding, Expired	(20,464,666)	(33,279,170)
Weighted Average Exercise Price, Expired	$ 0.11	$ 0.19
Warrants Outstanding, Ending balance	29,700,000	40,764,666
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, 2021	Dec. 31, 2020
Accumulated Other Comprehensive Income (Loss) [Line Items]
Number of Warrants granted	9,400,000	18,650,000
Warrant [Member] | Employment Agreement [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Number of Warrants granted		1,000,000
Warrant [Member] | Financing Agreement [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Number of Warrants granted	1,000,000	1,000,000
Warrant [Member] | Consulting Agreement [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Number of Warrants granted		250,000
Warrant [Member] | Loan Agreement [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Number of Warrants granted	5,400,000	11,150,000
Warrant [Member] | Board of Directors and Advisory Board Service [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Number of Warrants granted	3,000,000	5,250,000

SCHEDULE OF FAIR VALUE OF ASSUM

SCHEDULE OF FAIR VALUE OF ASSUMPTION (Details)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Expected dividend rate	0%	0%
Minimum [Member]
Risk-free interest rate	16%	1.65%
Expected life	2 years	1 year
Expected volatility	277%	240%
Maximum [Member]
Risk-free interest rate	97%	2.38%
Expected life	3 years	3 years
Expected volatility	356%	274%

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

Dec. 22, 2020

Dec. 15, 2020

Sep. 01, 2020

Feb. 29, 2020

Jan. 20, 2020

Aug. 14, 2019

Aug. 08, 2019

Jul. 23, 2019

Jan. 25, 2021

Oct. 30, 2020

Dec. 31, 2021

Dec. 31, 2020

Dec. 31, 2019

Class of Stock [Line Items]

Stock conversion price

$ 0.28

Proceeds from warrant exercise

$ 119,375

Warrants expire term

1 year 8 months 15 days

1 year 4 months 20 days

Number of warrant exercised

1,650,000

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

Consulting Agreement [Member]

Class of Stock [Line Items]

Issuance of common stock related shares

250,000

Executive Salary Payable Agreement [Member]

Class of Stock [Line Items]

Issuance of common stock related shares

1,992,272

Warrant [Member]

Class of Stock [Line Items]

Intrinsic value

$ 0

$ 0

Joel Oppenheim [Member]

Class of Stock [Line Items]

Number of shares issued

316,491

316,491

Proceeds from private placement

$ 12,500

Warrant exercise price

$ 0.08

Shares issued on conversion of debt

156,250

Cash payment of debt

$ 2,500

Debt instrument, forgiveness amount

$ 10,000

Conversion price

$ 0.02

Gain on related party nature of transaction

$ 53,670

Jovian [Member]

Class of Stock [Line Items]

Private placement, description

purchased 1 unit of the debt private placement with gross proceeds of $12,500

Warrant exercise price

$ 0.08

Shares issued on conversion of debt

156,250

Warrants to purchase common stock

312,500

Tariq Chaudhary [Member]

Class of Stock [Line Items]

Number of shares issued

500,000

Accrued salaries

$ 77,500

Conversion price

$ 0.15

Paul Deputy [Member]

Class of Stock [Line Items]

Number of shares issued

250,000

Accrued salaries

$ 192,520.04

Conversion price

$ 0.033

Gain on related party nature of transaction

$ 134,270

Joel Oppenheim [Member]

Class of Stock [Line Items]

Warrant exercise price

$ 0.10

$ 0.10

$ 0.10

Warrants to purchase common stock

10,000

150,000

Proceeds from warrant exercise

$ 1,000

$ 15,000

Mark Allen [Member]

Class of Stock [Line Items]

Number of shares issued

5,400,000

Warrant exercise price

$ 0.08

$ 0.098

Warrants to purchase common stock

275,000

Warrant to purchase of common stock

5,400,000

Conversion price

$ 0.09

Unpaid contract wages

$ 30,000

Converted shares of common stock

333,333

Secured debt

$ 135,000

Accrued interest

9,888

Guaranteed return secured loan

$ 135,000

Mark Allen [Member] | Employment Agreement [Member]

Class of Stock [Line Items]

Warrant exercise price

$ 0.04

$ 0.08

Proceeds from warrant exercise

$ 69,375

Salary

$ 15,000

Shares issued for compensation

2,000,000

Warrant to purchase of common stock

1,000,000

Vesting, description

equally vesting over 24 months

Warrants expire term

36 months

Number of warrant exercised

1,650,000

Mark Allen [Member] | Employment Agreement [Member] | Issued Upon Signing [Member]

Class of Stock [Line Items]

Shares issued for compensation

1,000,000

Mark Allen [Member] | Employment Agreement [Member] | At Completion of 6 Month Probationary Period [Member]

Class of Stock [Line Items]

Shares issued for compensation

1,000,000

Mark Allen [Member] | Warrant [Member]

Class of Stock [Line Items]

Proceeds from warrant exercise

$ 26,875

Paul Deputy [Member] | Settlement and Mutual Release Agreement [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

Series A Preferred Stock [Member]

Class of Stock [Line Items]

Preferred stock, dividend rate

9%

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

178,699

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

$ 779

$ 0

2019 Units [Member] | Private Placement [Member]

Class of Stock [Line Items]

Share issued price per share

$ 0.08

Number of shares issued

1,875,000

Proceeds from private placement

$ 150,000

Private placement, description

Each 2019 Unit was comprised of one common share and two warrants entitling the holder to exercise such warrant for one common share for a period of two years from the date of issuance. The warrants have exercise price of $0.10 per share. See additional description of the detail transactions concerning those warrants in Note 7: Related Party Transactions

RELATED PARTY TRANSACTIONS (Det

RELATED PARTY TRANSACTIONS (Details Narrative)

1 Months Ended

3 Months Ended

12 Months Ended

Sep. 30, 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

Dec. 22, 2020 USD ($) $ / shares shares

Dec. 15, 2020 USD ($) $ / shares shares

Sep. 02, 2020 USD ($) $ / shares shares

May 29, 2020 USD ($) a

May 29, 2020 CAD ($)

Jan. 20, 2020 USD ($) $ / shares shares

Aug. 21, 2019 USD ($) $ / shares shares

Sep. 17, 2018

Nov. 30, 2021 USD ($) shares

Oct. 31, 2021 USD ($) shares

Jan. 25, 2021 shares

Dec. 31, 2021 CAD ($)

Dec. 31, 2021 USD ($) shares

Dec. 31, 2020 USD ($) shares

Dec. 31, 2020 CAD ($) shares

Dec. 31, 2021 CAD ($)

Oct. 31, 2021 CAD ($)

Jul. 23, 2019 $ / shares

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

$ 39,443

Warrants to purchase of common stock shares, exercised | shares

1,650,000

1,650,000

Proceeds from warrant exercise

$ 119,375

Warrants to purchase shares of common stock, granted | shares

9,400,000

18,650,000

18,650,000

Warrant term

1 year 8 months 15 days

1 year 4 months 20 days

1 year 8 months 15 days

Share based compensation

$ 211,481

$ 244,520

Working interest percentage

3%

Preferred stock for cash

119,375

Leo Womack [Member]

Related Party Transaction [Line Items]

Number of 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 consideration

$ 5,150,000

$ 6,500,000

Working interest percentage

28%

28%

Non refundable deposits

$ 200,000

Remaining payments

$ 2,000,000

Contingenet liabilities

$ 3,300,000

$ 1,000,000

Other income

$ 200,000

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

Related Party Transaction [Line Items]

Working interest percentage

50%

50%

Alberta Enegry Regulator [Member]

Related Party Transaction [Line Items]

Amount of acquisition fund requirement

$ 602,423

Other assets, current

$ 386,989

Blue Sky Resources Ltd [Member]

Related Party Transaction [Line Items]

Business acquisition percentage of voting interests acquired

50%

Area of land | a

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%

Jovian Petroleum Corporation [Member] | Debt Private Placements [Member]

Related Party Transaction [Line Items]

Proceeds from issuance of debt

$ 12,500

Number of shares issued | shares

156,250

Warrant to purchase of common stock | shares

312,500

Warrant exercise price | $ / shares

$ 0.08

Mark Allen [Member]

Related Party Transaction [Line Items]

Number of shares issued | shares

5,400,000

250,000

2,000,000

Warrant exercise price | $ / shares

$ 0.08

$ 0.04

$ 0.08

Warrants to purchase of common stock shares, exercised | shares

1,650,000

Proceeds from warrant exercise

$ 69,375

Salary

$ 15,000

Warrants to purchase shares of common stock, granted | shares

1,000,000

Warrant term

36 months

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

Warrants and Rights Outstanding

$ 200,378

Mark Allen [Member] | Issued Upon Signing [Member]

Related Party Transaction [Line Items]

Number of shares issued | shares

1,000,000

Leo Womack [Member] | Debt Private Placements [Member]

Related Party Transaction [Line Items]

Proceeds from issuance of debt

$ 25,000

Number of shares issued | shares

312,500

Warrant to purchase of common stock | shares

625,000

Warrant exercise price | $ / shares

$ 0.08

Fair value of warrants issued

$ 31,033

Tariq Chaudhary [Member]

Related Party Transaction [Line Items]

Number of shares issued | shares

500,000

Accrued salaries

$ 77,500

Conversion price | $ / shares

$ 0.15

Joel Oppenheim [Member]

Related Party Transaction [Line Items]

Number of shares issued | shares

316,491

316,491

Warrant exercise price | $ / shares

$ 0.08

Conversion price | $ / shares

$ 0.02

Share based compensation

$ 60,000

Related party transaction amounts

$ 53,670

Zel Khan [Member]

Related Party Transaction [Line Items]

Number of shares issued | shares

1,992,272

Accrued salaries

$ 325,000

Conversion price | $ / shares

$ 0.025

Related party transaction amounts

$ 275,193

Paul Deputy [Member]

Related Party Transaction [Line Items]

Number of shares issued | shares

250,000

Accrued salaries

$ 192,520.04

Conversion price | $ / shares

$ 0.033

Related party transaction amounts

$ 134,270

Debt periodic payment months

20

Debt instrument, periodic payment

$ 2,500

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Details Narrative)	Dec. 31, 2020 USD ($)
Houston [Member]
Financing Receivable, Impaired [Line Items]
Minimum contractual lease payments	$ 1,500

SCHEDULE OF INCOME TAX EXPENSES

SCHEDULE OF INCOME TAX EXPENSES (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Federal statutory income tax rate		21%	21%
Income tax (benefit) expense computed at statutory rates	$ 405,000	$ (2,078,000)
Non-deductible items	49,000	85,000
Change in statutory, foreign tax, foreign exchange rates and other	(559,000)	(2,427,000)
Change in valuation allowance	(105,000)	4,420,000
Total

SCHEDULE OF DEFERRED TAX ASSETS

SCHEDULE OF DEFERRED TAX ASSETS (Details) - USD ($)	Dec. 31, 2021	Dec. 31, 2020
Deferred tax assets
Net operating loss carryforwards	$ 6,038,000	$ 5,772,000
Asset retirement obligation	498,000	679,000
Oil and gas properties	(593,000)	(644,000)
Property and equipment		6,000
Other
Total deferred tax assets (liabilities)	5,943,000	5,813,000
Less: Valuation allowance	(5,943,000)	(5,813,000)
Net deferred tax assets (liabilities)

INCOME TAXES (Details Narrative

INCOME TAXES (Details Narrative) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Operating losses valuation allowance	100%	100%
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	$ 2.2
Operating losses expiration, description	begin to expire if not utilized beginning in the year 2033
CANADA
Accumulated non-capital tax losses	$ 27.5
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, 2021	Dec. 31, 2020
Segment Reporting Information [Line Items]
Total long-lived assets	$ 6,349,183	$ 5,952,084
Operating Segments [Member]
Segment Reporting Information [Line Items]
Revenue	5,895,228	2,892,241
Production costs	(5,347,490)	(3,630,607)
Depreciation, depletion, amortization, and accretion	(720,018)	(1,435,040)
Results of operations from producing activities	(172,280)	(2,173,406)
Total long-lived assets	6,349,182	5,952,083
Operating Segments [Member] | CANADA
Segment Reporting Information [Line Items]
Revenue	5,882,499	2,860,324
Production costs	(5,281,740)	(3,377,055)
Depreciation, depletion, amortization, and accretion	(668,672)	(1,374,611)
Results of operations from producing activities	(67,913)	(1,891,342)
Total long-lived assets	2,104,993	1,683,055
Operating Segments [Member] | UNITED STATES
Segment Reporting Information [Line Items]
Revenue	12,729	31,917
Production costs	(65,750)	(253,552)
Depreciation, depletion, amortization, and accretion	(51,346)	(60,429)
Results of operations from producing activities	(104,367)	(282,064)
Total long-lived assets	$ 4,244,189	$ 4,767,628

SCHEDULE OF REVENUES (Details)

SCHEDULE OF REVENUES (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Revenue, Major Customer [Line Items]
Total revenues	$ 5,895,228	$ 2,892,241
Total revenues	5,895,228	2,892,241
Customer A [Member]
Revenue, Major Customer [Line Items]
Total revenues	796,176	2,860,324
Customer B [Member]
Revenue, Major Customer [Line Items]
Total revenues	12,729	31,917
Customer C [Member]
Revenue, Major Customer [Line Items]
Total revenues	$ 5,086,323

SEGMENT REPORTING (Details Narr

SEGMENT REPORTING (Details Narrative)	12 Months Ended
	Dec. 31, 2021 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, 2021	Dec. 31, 2020
Extractive Industries [Abstract]
Property acquisitions	$ 787,250	$ 678,765
Unevaluated
Evaluated
Exploration
Development
Total costs incurred	$ 787,250	$ 678,765

SCHEDULE OF CAPITALIZED COSTS I

SCHEDULE OF CAPITALIZED COSTS IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT (Details) - USD ($)	Dec. 31, 2021	Dec. 31, 2020
Capitalized costs:
Unevaluated properties
Evaluated properties	5,511,480	6,456,367
Gross capitalized costs	5,511,480	6,456,367
Less: Accumulated DD&A	(448,960)	(2,693,300)
Net capitalized costs	$ 5,062,520	$ 3,763,067

SCHEDULE OF PROVED OIL AND GAS

SCHEDULE OF PROVED OIL AND GAS RESERVES (Details) - bbl	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Extractive Industries [Abstract]
Proved oil and gas reserves, beginning	1,311,672	1,800,457
Proved oil and gas reserves, revisions of prior estimates	292,335	(860,450)
Proved oil and gas reserves, purchases of reserves in place		466,800
Proved oil and gas reserves, disposition of mineral in place	(57,070)
Proved oil and gas reserves, production	(97,084)	(95,135)
Proved oil and gas reserves, ending	1,449,853	1,311,672

SCHEDULE OF PROVED DEVELOPMENT

SCHEDULE OF PROVED DEVELOPMENT AND UNDEVELOPED RESERVES (Details) - bbl	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Reserve Quantities [Line Items]
Estimated quantities of proved undeveloped reserves	1,449,853	1,311,672
Proved oil and gas reserves, beginning	1,311,672	1,800,457
Acquired reserves		466,800
Disposition of reserves	(57,070)
Revision of prior estimates	292,335	(860,450)
Production	(97,084)	(95,135)
Proved oil and gas reserves, ending	1,449,853	1,311,672
Proved Developed Reserve [Member]
Reserve Quantities [Line Items]
Estimated quantities of proved undeveloped reserves	1,449,853	1,245,512
Proved oil and gas reserves, beginning	1,245,512
Proved oil and gas reserves, ending	1,449,853	1,245,512
Proved Undeveloped Reserves [Member]
Reserve Quantities [Line Items]
Estimated quantities of proved undeveloped reserves		66,160
Proved oil and gas reserves, beginning	66,160
Proved oil and gas reserves, ending		66,160
Proved Developed Reserve and Non-producing [Member]
Reserve Quantities [Line Items]
Estimated quantities of proved undeveloped reserves	1,449,853	1,245,512
Proved oil and gas reserves, beginning	1,245,512
Acquired reserves
Disposition of reserves
Revision of prior estimates	301,425
Production	(97,084)
Proved oil and gas reserves, ending	1,449,853	1,245,512
Proved Undeveloped Reserve [Member]
Reserve Quantities [Line Items]
Estimated quantities of proved undeveloped reserves		66,160
Proved oil and gas reserves, beginning	66,160
Disposition of reserves	(66,160)
Revision of prior estimates
Proved oil and gas reserves, ending		66,160

SCHEDULE OF STANDARDIZED MEASUR

SCHEDULE OF STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (Details) - USD ($)	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Extractive Industries [Abstract]
Future cash inflows	$ 93,082,624	$ 47,647,500
Future production costs	(45,892,778)	(25,203,830)
Future development costs	(1,867,485)	(2,148,510)
Future income taxes
Future net cash flows	45,322,361	20,295,160
Discount of future net cash flows at 10% per annum	27,929,984	(12,339,240)
Standardized measure of discounted future net cash flows	$ 17,392,377	$ 7,956,920	$ 25,824,730

SCHEDULE OF STANDARDIZED MEAS_2

SCHEDULE OF STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (Details) (Parenthetical)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Extractive Industries [Abstract]
Discount of future net cash flows interest rate	10%	10%

SCHEDULE OF CHANGES IN STANDARD

SCHEDULE OF CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE CASH FLOWS (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Extractive Industries [Abstract]
Beginning of year	$ 7,956,920	$ 25,824,730
Sales and transfers of oil & gas produced, net of production costs	(539,927)	(735,300)
Net changes in prices and production costs	(865,805)	(249,508)
Changes in estimated future development costs	(565,870)	96,780
Acquisitions/dispositions of minerals in place, net of production costs	(231,470)
Revision of previous estimates	1,194,016	(14,938,598)
Change in discount		436,490
Change in production rate or other	10,444,513	(2,477,674)
End of year	$ 17,392,377	$ 7,956,920

SUPPLEMENTAL INFORMATION RELA_3

SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Details Narrative)		12 Months Ended
	May 29, 2020 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2020 CAD ($)
Property, Plant and Equipment [Line Items]
Asset retirement obligation		$ 2,257,027	$ 3,624,133
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%	10%	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

SUBSEQUENT EVENTS (Details Narr

SUBSEQUENT EVENTS (Details Narrative) - Subsequent Event [Member]				1 Months Ended
	Mar. 11, 2022 USD ($)	Feb. 16, 2022 USD ($)	Feb. 16, 2022 CAD ($)	Sep. 30, 2022 USD ($)	Jun. 13, 2022
Subsequent Event [Line Items]
Repayments of debt				$ 5,000,000,000
Minimum [Member]
Subsequent Event [Line Items]
Breach of contract defendants	$ 1,000,000
Purchase and Sale Agreement and Debt Settlement Agreement [Member] | Prospera Energy [Member]
Subsequent Event [Line Items]
Working capital interest			28%
Debt forgiveness amount		$ 2,061,614	$ 1,720,613
Convertible debt			510,000
Payments on convertible debt			$ 75,000
Letter Agreement [Member] | Blue Sky Resources Ltd [Member]
Subsequent Event [Line Items]
Sale on working interest					50%