Petrolia Energy Corp - Quarter Report: 2023 March (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

☒ Quarterly Report Pursuant To Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended March 31, 2023

☐ Transition Report Under Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from __________ to __________

Commission File Number: 000-52690

PETROLIA ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

(832) 723-1266

(Registrants telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act: None.

Indicate by check mark whether the registrant: (1) filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the past 12 months (or for such shorter period that the issuer was required to file such reports); and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See definition of “large accelerated filer,” accelerated filer” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act:

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

State the number of shares outstanding of each of the issuer’s classes of common equity, as of the latest practicable date: 176,988,322 shares of common stock as of May 15, 2023.

TABLE OF CONTENTS

FORWARD-LOOKING STATEMENTS

This Report contains statements which, to the extent that they do not recite historical fact, constitute forward-looking statements. These statements can be identified by the fact that they do not relate strictly to historical or current facts and may include the words “may,” “will,” “could,” “should,” “would,” “believe,” “expect,” “anticipate,” “estimate,” “intend,” “plan” or other words or expressions of similar meaning. We have based these forward-looking statements on our current expectations about future events. The forward-looking statements include statements that reflect management’s beliefs, plans, objectives, goals, expectations, anticipations and intentions with respect to our financial condition, results of operations, future performance and business, including statements relating to our business strategy and our current and future development plans.

The potential risks and uncertainties that could cause our actual financial condition, results of operations and future performance to differ materially from those expressed or implied in this report include:

Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot guarantee future results, levels of activity, performance, or achievements. Many factors discussed in this report, some of which are beyond our control, will be important in determining our future performance. Consequently, actual results may differ materially from those that might be anticipated from the forward-looking statements. In light of these and other uncertainties, you should not regard the inclusion of a forward-looking statement in this Report as a representation by us that our plans and objectives will be achieved, and you should not place undue reliance on such forward-looking statements. We undertake no obligation to publicly update any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law.

You should read the matters described in “Risk Factors” and the other cautionary statements made in this Report as being applicable to all related forward-looking statements wherever they appear in this Report. We cannot assure you that the forward-looking statements in this Report will prove to be accurate and therefore prospective investors are encouraged not to place undue reliance on forward-looking statements. Other than as required by law, we undertake no obligation to update or revise these forward-looking statements, even though our situation may change in the future.

PART I: Financial Information

Item 1. Financial Statements

PETROLIA ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

The accompanying notes are an integral part of these condensed consolidated interim financial statements.

PETROLIA ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

(Unaudited)

The accompanying notes are an integral part of these condensed consolidated interim financial statements.

PETROLIA ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ DEFICIT

(Unaudited)

The accompanying notes are an integral part of these condensed consolidated interim financial statements.

PETROLIA ENERGY CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

SUPPLEMENTAL DISCLOSURES

The accompanying notes are an integral part of these condensed consolidated interim financial statements.

PETROLIA ENERGY CORPORATION

NOTES TO CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

FOR THE THREE MONTHS ENDED MARCH 31, 2023 AND 2022

(Unaudited)

NOTE 1. ORGANIZATION AND BASIS OF PRESENTATION:

Petrolia Energy Corporation (the “Company”, Petrolia” or “PEC”) is in the business of oil and gas exploration, development, and production.

Basis of Presentation

The accompanying unaudited condensed consolidated interim financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America (“US GAAP”) and the rules of the Securities and Exchange Commission (“SEC”), and should be read in conjunction with the audited financial statements and notes thereto contained in the Company’s latest Annual Report filed with the SEC on Form 10-K. In the opinion of management, all adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of the results of operations for the interim periods presented have been reflected herein. The results of operations for such interim periods are not necessarily indicative of operations for a full year. Notes to the consolidated financial statements which would substantially duplicate the disclosure contained in the audited financial statements for the year ended December 31, 2022, as reported in the Form 10-K, have been omitted.

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 10), income taxes, and the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom.

Cash and cash equivalents

The Company considers all highly liquid instruments purchased with an original maturity date of three months or less to be cash equivalents. As of December 31, 2022, the Company did not hold any cash equivalents.

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. This update creates a five-step model that requires entities to exercise judgment when considering the terms of the contract(s) which includes (i) identifying the contract(s) with the customer, (ii) identifying the separate performance obligations in the contract, (iii) determining the transaction price, (iv) allocating the transaction price to the separate performance obligations, and (v) recognizing revenue as each performance obligation is satisfied. The Company adopted this standard on a modified retroactive basis on January 1, 2018. No financial statement impact occurred upon adoption.

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. Stock-based compensation to employees is measured at the grant date, based on the fair value of the award, and is recognized as expense over the requisite employee service period. The Company accounts for stock-based compensation to other than employees in accordance with FASB ASC 505-50. Equity instruments issued to other than employees are valued at the earlier of a commitment date or upon completion of the services, based on the fair value of the equity instruments, and are recognized as expense over the service period. The Company estimates the fair value of stock-based payments using the Black-Sholes Option Pricing Model for common stock options and warrants and the closing price of the Company’s common stock for common share issuances. The Company may grant stock to employees and non-employees in exchange for goods, services or for settlement of liabilities. Shares granted to employees in exchange for goods, services or settlement of liabilities are measured based on the fair value of the shares issued. Shares granted to non-employees in exchange for goods or services are measured based on the fair value of the consideration received or the fair value of the shares issued, whichever is more reliably measurable.

Income taxes

Income taxes are accounted for pursuant to ASC 740, Income Taxes, which requires recognition of deferred income tax liabilities and assets for the expected future tax consequences of events that have been recognized in the Company’s financial statements or tax returns. The Company provides for deferred taxes on temporary differences between the financial statements and tax basis of assets using the enacted tax rates that are expected to apply to taxable income when the temporary differences are expected to reverse. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount expected to be realized.

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 interest or penalties recognized for the three months ended March 31, 2023 and 2022.

The Company is required to file federal income tax returns in the United States and Canada, and in various state and local jurisdictions. The Company’s tax returns are subject to examination by taxing authorities in the jurisdictions in which it operates in accordance with the normal statutes of limitations in the applicable jurisdiction.

Earnings (loss) per share

Basic earnings (loss) per share have been calculated based on the weighted-average number of common shares outstanding. The treasury stock method is used to compute the dilutive effect of the Company’s share-based compensation awards. Under this method, the incremental number of shares used in computing diluted earnings per share (“EPS”) is the difference between the number of shares assumed issued and purchased using assumed proceeds. Diluted EPS amounts would include the effect of outstanding stock options, warrants, and other convertible securities if including such potential shares of common stock is dilutive. Basic and diluted earnings per share are the same in all periods presented as all outstanding instruments are anti-dilutive.

Concentration of credit risk

The Company is subject to credit risk resulting from the concentration of its oil receivables with significant purchasers. Three purchasers accounted for all of the Company’s oil sales revenues for 2023 and 2022. 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 of Financial Instruments

Fair value of financial instruments requires disclosure of the fair value information, whether or not recognized in the balance sheet, where it is practicable to estimate that value. As of March 31, 2023, the amounts reported for cash, accrued interest and other expenses, notes payable, convertible notes, and derivative liability approximate the fair value because of their short maturities.

We adopted ASC Topic 820 for financial instruments measured as fair value on a recurring basis. ASC Topic 820 defines fair value, established a framework for measuring fair value in accordance with accounting principles generally accepted in the United States and expands disclosures about 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:

We measure certain financial instruments at fair value on a recurring basis. Assets and liabilities measured at fair value on a recurring basis are as follows as of March 31, 2023, and December 31,2022.

 SCHEDULE OF DERIVATIVE LIABILITIES MEASURED AT FAIR VALUE ON RECURRING BASIS

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 (Topic 805): Clarifying the Definition of a Business. The ASU provides an updated model for determining if acquired assets and liabilities constitute a business. In a business combination, the acquired assets and liabilities are recognized at fair value and goodwill could be recognized. In an asset acquisition, the assets are allocated value based on relative fair value and no goodwill is recognized. The ASU narrows the definition of a business. The Company adopted this standard on January 1, 2018. ASU 2017-01 did not have a material impact on our financial statements on adoption.

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.

NOTE 3. GOING CONCERN

The Company has suffered recurring losses from operations and currently has a working capital deficit. These conditions raise substantial doubt about the Company’s ability to continue as a going concern. The Company plans to generate profits by reducing overhead costs and reworking its existing oil or gas wells, as needed, funding permitting. The Company may need to raise funds through either the sale of its securities, issuance of corporate bonds, joint venture agreements and/or bank financing to accomplish its goals.

If additional financing is not available when needed, we may need to cease operations. The Company may not be successful in raising the capital needed to drill and/or rework existing oil wells. Any additional wells that the Company may drill may be non-productive. Management believes that actions presently being taken to secure additional funding for the reworking of its existing assets will provide the opportunity for the Company to continue as a going concern. Since the Company has an oil producing asset, its goal is to increase the production rate by optimizing its current infrastructure. The accompanying financial statements have been prepared assuming the Company will continue as a going concern; no adjustments to the financial statements have been made to account for this uncertainty.

NOTE 4. NOTES RECEIVABLE

On February 16, 2022, Petrolia Canada Corporation (PCC), a wholly-owned subsidiary of Petrolia Energy Corporation (PEC), entered into a Purchase and Sale Agreement (PSA) and Debt Settlement Agreement (DSA) with Prospera Energy, Inc. (Prospera) whereby PCC sold its 28% working interest in the Luseland, Hearts Hill and Cuthbert fields. The PSA and DSA agreements were effective as of October 1, 2021. The DSA included a convertible debenture for $510,000 (CAD) with an interest rate of 8% per annum, compounded quarterly for a term of two years.

The debenture was convertible at PCC’s option into common shares of Prospera at a conversion price of $0.05 (CAD) per share in the first year, from March 1, 2022 to March 31, 2023 and $0.10 (CAD) in the second year from April 1, 2023 to March 31, 2024. Applicable interest will be payable in cash or shares of Prospera at the current market price. For more information, please see Form 8-K filed on February 28, 2022.

NOTE 5. HELD FOR TRADING SECURITIES

We measure all equity investments that do not result in consolidation and are not accounted for under the equity method at fair value with the change in fair value included in net income. We use quoted market prices to determine the fair value of equity securities with readily determinable fair values.

As previously reported, on February 16, 2022, Petrolia Canada Corporation (PCC), a wholly-owned subsidiary of Petrolia Energy Corporation (PEC), entered into a Purchase and Sale Agreement (PSA) and Debt Settlement Agreement (DSA) with Prospera Energy, Inc. (Prospera) whereby PCC sold its 28% working interest in the Luseland, Hearts Hill and Cuthbert fields. The PSA and DSA agreements were effective as of October 1, 2021. In January of 2023, the Company converted $210,000 (CAD) ($157,315 USD using prevailing rates at that date) of our debenture from Prospera into shares of Prospera Common stock at a conversion rate of $0.05 (CAD) per share.

NOTE 6. EVALUATED PROPERTIES

The Company’s current properties can be summarized as follows.

 SCHEDULE OF COMPANY’S CURRENT PROPERTIES

U.S. Properties – Slick Unit Dutcher Sand (“SUDS”) Field

The Slick Unit Dutcher Sand (SUDS) field is located in Creek County, Oklahoma. Petrolia owns a 100% working interest (WI) with an approximately 76.5% net revenue interest (NRI) in the 2,530 acre field. The SUDS West unit is approximately 1,670 acres and the SUDS East unit is approximately 860 acres.

As of December 31, 2022, SUDS total estimated net proved reserves were approximately 346 thousand barrels of oil equivalent (MBoe) and total estimated net probable reserves were approximately 153 thousand barrels of oil equivalent (MBoe).

On January 13, 2023, the Company received an Incident and Complaint Investigation Report issued by the Oklahoma Corporation Commission (OCC) due to a mineral owner complaint. The OCC issued a plug or produce order for SUDS West unit and SUDS East unit. The Company has received two extensions of time and is working with the OCC to implement a production plan to bring both units into compliance.

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

U.S. Properties – Twin Lakes San Andres Unit (“TLSAU”) Field

The Twin Lakes San Andres Unit (TLSAU) field is located in Chaves County, New Mexico. As of December 31, 2022, it was determined that PEC does not own any TLSAU leases, and therefore has no reserves. It is estimated that PEC has 29 wells that need to be plugged and abandoned, plus surface remediated. The estimated cost of the TLSAU well plugging and abandonment, and surface remediation obligations are approximately $1.2 million.

Utikuma Field

On May 1, 2020, Petrolia Energy Corporation acquired a 50% working interest in approximately 28,000 acres located in the Utikuma Lake area in Alberta, Canada. The property is an oil-weighted asset historically producing approximately 500 barrels of oil per day (bpd) of light oil. The working interest was acquired from Blue Sky Resources Ltd (“Blue Sky”). in an affiliated party transaction as Zel C. Khan, the Company’s former Chief Executive Officer, is related to the ownership of Blue Sky.

Blue Sky acquired a 100% working interest in the Canadian Property from Vermilion Energy Inc. via Vermilion’s subsidiary Vermilion Resources. The effective date of the acquisition was May 1, 2020. 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 West Texas Intermediate (WTI) crude. At the time the WTI price exceeded $50/bbl, the Company would pay an additional $750,000 CAD. In addition, at the time the 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 per barrel (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 Blue Sky Resources (BSR). The total USD value of the addition was $787,250, using prevailing exchange rates on the respective dates. Included in the terms of the agreement, the Company also funded their portion of the Alberta Energy Regulator (“AER”) bond fund requirement $763,754 CAD ($564,363 USD), necessary for the wells to continue in production after the acquisition. Additional funds in the amount of $490,624 CAD ($362,539 USD) remain in the other current asset balance for future payments to BSR, related to the acquisition.

On May 5, 2023, the Company was notified by BSR, the operator of our Utikuma asset that the Province of Alberta has declared a state of emergency due to wildfires in Alberta. We were informed that because of wildfires in the vicinity of our oilfield assets, the field was shut in and all personnel were evacuated, and that the highway to the Slave Lake area has been closed. Early assessments of the situation indicate that our Utikuma facilities may have incurred some damage.

NOTE 7. 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 a right-of-use (ROU) asset and a corresponding lease liability. The 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 March 31, 2023, we did not have any short-term leases.

The tables below present financial information associated with our lease.

 SCHEDULE OF FINANCIAL INFORMATION LEASE

As of March 31, 2023, the maturities of our lease liability are as follows:

 SCHEDULE OF MATURITIES LEASE LIABILITY

NOTE 8. NOTES PAYABLE

The following table summarizes the Company’s notes payable:

 SCHEDULE OF NOTES PAYABLE

The following is a schedule of future minimum repayments of notes payable as of March 31, 2023:

 SCHEDULE OF FUTURE MINIMUM REPAYMENTS OF NOTES PAYABLE

NOTE 9. RELATED PARTY NOTES PAYABLE

The following table summarizes the Company’s related party notes payable:

SCHEDULE OF RELATED PARTY NOTES PAYABLE 

The following is a schedule of future minimum repayments of related party notes payable as of March 31, 2023:

 SCHEDULE OF FUTURE MINIMUM REPAYMENTS OF RELATED PARTY NOTES PAYABLE

NOTE 10. 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.

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.

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 to plug these wells in 2020.

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.

For the purpose of determining the fair value of AROs incurred during the years presented, the Company used the following assumptions:

 SCHEDULE OF FAIR VALUE OF ASSET RETIREMENT OBLIGATIONS

The following table shows the change in the Company’s ARO liability:

 SCHEDULE OF CHANGE IN ASSET RETIREMENT OBLIGATIONS

NOTE 11. EQUITY

Preferred stock

The holders of Series A Preferred Stock are entitled to receive cumulative dividends at a rate of 9% per annum. The Preferred Stock will automatically convert into common stock when the Company’s common stock market price equals or exceeds $0.28 per share for 30 consecutive days. At conversion, 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 $44,798 were declared for the three months ended March 31, 2023, and $44,797 for the three months ended March 31, 2022.

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 the Board of Directors of the Company shall have any voting rights.

The holders of Series C Preferred Stock are entitled to receive cumulative dividends at a rate of 8% per annum. If any shares of Series C Preferred Stock remain outstanding as of December 31, 2023, the dividend rate will increase to 11% per annum. The Series C Preferred Stock will automatically convert into common stock upon any registered public offering of the Company’s common stock. At conversion, 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 $2,170 and $2,066 were declared for the three months ended March 31, 2023, and March 31, 2022, respectively.

Common stock

The common stock of Petrolia Energy Corporation is currently not publicly traded.

Warrants

On September 24, 2015, the Board of Directors of the Company approved the adoption of the 2015 Stock Incentive Plan (the “Plan”). The Plan provides an opportunity, subject to approval of our Board of Directors, of individual grants and awards, for any employee, officer, director or consultant of the Company. The maximum aggregate number of shares of common stock which may be issued pursuant to awards under the Plan, as amended on November 7, 2017, was 40,000,000 shares. The plan was ratified by the stockholders of the Company on April 14, 2016.

Continuity of the Company’s common stock purchase warrants issued and outstanding is as follows:

 SCHEDULE OF COMMON STOCK PURCHASE WARRANTS ISSUED AND OUTSTANDING

As of March 31, 2023, the weighted-average remaining contractual life of warrants outstanding was 0.84 years (December 31, 2022 – 0.81 years).

As of March 31, 2023, the intrinsic value of warrants outstanding is $0.00 (December 31, 2022 - $0.00).

The table below summarizes warrant issuances during the three months ended March 31, 2023, and year ended December 31, 2022:

 SCHEDULE OF WARRANTS ISSUANCE DURING PERIOD

The warrants were valued using the Black Scholes Option Pricing Model with the range of assumptions outlined below. Expected life was determined based on historical data of the Company.

 SCHEDULE OF FAIR VALUE OF ASSUMPTION OF WARRANTS

NOTE 12. RELATED PARTY TRANSACTIONS

On January 31, 2022, Board Member Leo Womack purchased 2,500 shares of Series C Preferred Stock for cash of $25,000.

NOTE 13. SEGMENT REPORTING

The Company has a single reportable operating segment, Oil and Gas Exploration and Production, which includes exploration, development, and production of current and potential oil and gas properties. Results of operations from producing activities were as follows:

 SCHEDULE OF LONG-LIVED ASSETS

NOTE 14. SUBSEQUENT EVENTS

On April 3, 2023, the Company converted the remaining $300,000 (CAD) ($223,248 USD using prevailing rates at that date) of our debenture from Prospera into shares of Prospera Common stock at a conversion rate of $0.05 (CAD) per share.

On April 20, 2023, Petrolia Canada Corporation filed a Statement of Defense to Counterclaim, Reply to Defense, and Amended Statement of Claim, adding Zel Khan and Quinten Beasley as defendants in the Court File Number 2301-01310 matter filed in the Calgary Court of King’s Bench of Alberta.

On May 5, 2023, the Company was notified by Blue Sky Resources (BSR), the operator of our Utikuma asset that the Province of Alberta has declared a state of emergency due to wildfires in Alberta. We were informed that because of wildfires in the vicinity of our oilfield assets, the field was shut in and all personnel were evacuated, and that the highway to the Slave Lake area has been closed. Early assessments of the situation indicate that our Utikuma facilities may have incurred some damage.

Item 2 Management’s Discussion and Analysis of Financial Condition and Results of Operations

Introduction

Please see the “Glossary of Oil and Gas Terms” in our Annual Report on Form 10-K for the year ended December 31, 2022, filed with the SEC on May 12, 2023 (the “2022 Annual Report”) for a list of abbreviations and definitions used throughout this Report.

This information should be read in conjunction with the unaudited condensed consolidated interim financial statements and the notes thereto included in this Quarterly Report on Form 10-Q and Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in our 2022 Annual Report.

Certain capitalized terms used below and otherwise defined below, have the meanings given to such terms in the footnotes to our consolidated financial statements included above under “Part I – Financial Information” – “Item 1. Consolidated Financial Statements”.

Unless the context requires otherwise, references to the “Company,” “we,” “us,” “our,” “Petrolia”, “PEC” and “Petrolia Energy Corp.” refer specifically to Petrolia Energy Corp. and its wholly-owned subsidiaries.

In addition, unless the context otherwise requires and for the purposes of this Report only:

Background

The Company was incorporated in Colorado in 2002. In 2015, the Company became active in the exploration and production of oil and gas properties. In 2016 the Company formally changed its name to Petrolia Energy Corporation and redomiciled from Colorado to Texas.

Petrolia Energy Corporation explores for, develops, and produces crude oil, natural gas liquids (NGLs) and natural gas in producing basins in the United States of America and Canada. PEC’s principal oil and gas assets are further described in the “Plan of Operation” below. As of December 31, 2022, PEC’s total estimated net proved reserves were 1,065 thousand barrels of oil equivalent (MBoe), of which approximately 1,060 thousand barrels (MBbl) were crude oil and condensate reserves and approximately 29 million cubic feet (MMcf), or 5 MBoe, were natural gas reserves.

As of December 31, 2022, approximately 32% of PEC’s net proved reserves, on a crude oil equivalent basis, were located in the United States of America, and approximately 68% were located in Canada. Crude oil equivalent volumes are determined using a ratio of 1.0 barrel of crude oil and condensate to 6.0 thousand cubic feet (Mcf) of natural gas. PEC’s operations are crude oil and natural gas exploration and production related. For information regarding the risks associated with PEC’s oil and gas operations, See ITEM 1A, Risk Factors.

Plan of Operation

Since 2015, PEC has established a clearly defined strategy to acquire, enhance and redevelop high-quality oil and gas assets. The Company has been focusing on assets in the United States and Canada while actively pursuing its strategy to offer low-cost operational solutions in established oil and gas regions. We believe our mix of oil-in-place conventional plays, low-risk resource plays and the redevelopment of our late-stage plays is a solid foundation for growth. Maintaining the lowest possible operating cost structure, coupled with efficient and safe operations, is integral in the implementation of PEC’s strategy.

With respect to information on PEC’s working interest in wells or acreage, “net” oil and gas wells or acreage are determined by multiplying “gross” oil and gas wells or acreage by PEC’s working interest in the wells or acreage.

Slick Unit Dutcher Sand (“SUDS”) Field

The Slick Unit Dutcher Sand (SUDS) field is located in Creek County, Oklahoma. Petrolia owns a 100% working interest (WI) with an approximately 76.5% net revenue interest (NRI) in the 2,530 acre field. The SUDS West unit is approximately 1,670 acres and the SUDS East unit is approximately 860 acres.

As of December 31, 2022, SUDS total estimated net proved reserves were approximately 346 thousand barrels of oil equivalent (MBoe) and total estimated net probable reserves were approximately 153 thousand barrels of oil equivalent (MBoe).

On January 13, 2023, the Company received an Incident and Complaint Investigation Report issued by the Oklahoma Corporation Commission (OCC) due to a mineral owner complaint. The OCC issued a plug or produce order for SUDS West unit and SUDS East unit. The Company has received two extensions of time and is working with the OCC to implement a production plan to bring both units into compliance.

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

Twin Lakes San Andres Unit (“TLSAU”) Field

The Twin Lakes San Andres Unit (TLSAU) field is located in Chaves County, New Mexico. As of December 31, 2022, it was determined that PEC does not own any TLSAU leases, and therefore has no reserves.

It is estimated that PEC has 29 wells that need to be plugged and abandoned, plus surface remediated. The estimated cost of the TLSAU well plugging and abandonment, and surface remediation obligations are approximately $1.2 million.

The majority of the TLSAU leases were terminated through the Stipulated Declaratory Judgement dated July 27, 2020 in the litigation between Moon Company, Trustee of the O’Brien Mineral Trust (Plaintiff) vs. Petrolia Energy Corporation (Defendant). Additional lease acreage was lost through the Stephanie Garcia Richard, Commissioner of Public Lands of the State of New Mexico (Plaintiff) vs. Oxy USA WTP, LP; Petrolia Energy Corp.; and Blue Sky NM Inc. (Defendants) litigation (Case No. D-101-CV-2021-00462).

The Twin Lakes San Andres Unit was terminated by the State of New Mexico Commissioner of Public Lands on August 28, 2019.

Askarii Resources, LLC

Effective February 1, 2016, the Company acquired 100% of the issued and outstanding interests of Askarii Resources LLC, a private Texas based oil and gas service company for the aggregate value of $50,000. The Company does not intend to further invest in the Askarii Resources, LLC acquisition.

Utikuma Lake field

On May 1, 2020, Petrolia Energy Corporation acquired a 50% working interest in approximately 28,000 acres located in the Utikuma Lake area in Alberta, Canada. The property is an oil-weighted asset historically producing a total of approximately 500 bpd of light oil.

The working interest was acquired from Blue Sky Resources Ltd. in an affiliated party transaction as Zel C. Khan, the Company’s former Chief Executive Officer, is related to the ownership of Blue Sky. Blue Sky acquired a 100% working interest in the Canadian Property from Vermilion Energy Inc. via Vermilion’s subsidiary Vermilion Resources. The effective date of the acquisition was May 1, 2020. The total purchase price of the property was $2,000,000 (CAD), with $1,000,000 of that total due initially. The additional $1,000,000 was contingent on the future price of WTI crude. At the time WTI price exceeded $50/bbl, the Company would pay an additional $750,000 CAD. In addition, at the time WTI price exceeded $57/bbl the Company would pay an additional $250,000 CAD (for a cumulative contingent total of $1,000,000 CAD). The price of WTI crude exceeded $50/bbl on January 6, 2021 and exceeded $57/bbl on February 8, 2021. The additional payments due were netted with the accounts receivable balance from previous Joint Interest Billing statements from BSR. The total USD value of the addition was $787,250, using prevailing exchange rates on the respective dates. Included in the terms of the agreement, the Company also funded their portion of the Alberta Energy Regulator (“AER”) bond fund requirement $763,754 CAD ($564,363 USD), necessary for the wells to continue in production after the acquisition. Additional funds in the amount of $490,624 CAD ($362,539 USD) remain in the other current asset balance for future payments to BSR, related to the acquisition.

As of December 31, 2022, Utikuma total estimated net proved reserves were approximately 719 thousand barrels of oil equivalent (MBoe) and total estimated net probable reserves were approximately 177 thousand barrels of oil equivalent (MBoe).

On May 5, 2023, the Company was notified by Blue Sky Resources (BSR), the operator of our Utikuma asset that the Province of Alberta has declared a state of emergency due to wildfires in Alberta. We were informed that because of wildfires in the vicinity of our Utikuma oilfield assets, the field was shut in and all personnel were evacuated, and that the highway to the Slave Lake area has been closed. Early assessments of the situation indicate that our Utikuma facilities may have incurred some damage.

Results of Operations

Revenues

Our oil and gas revenue reported for the three months ended March 31, 2023 was $1,376,317, a decrease of $460,043 from the three months ended March 31, 2022. The decrease was due to decreased production at the Utikuma field, as well as lower sales prices for the oil sold.

Operating Expenses

Operating expenses increased by $494,213, to $2,013,328 for the three-month period ended March 31, 2023, compared to $1,519,115 for the three months ended March 31, 2022. Operating expenses at Utikuma were higher, and increased funds were spent on repairs and maintenance as well. General and administrative expenses were also higher, due to payments to our auditors as we caught up on our SEC filings, and payments to lawyers related to our ongoing litigation, described in Item 1 of Part II of this report.

Other income (expense)

The Company had net other income of $152,585 for the three-month period ended March 31, 2023, compared to a net other expense of $101,931 for the three-month ended March 31, 2022. The main driver of this change was the unrealized gain on held-for-trading securities, described in more detail in Note 5. Our interest expense was lower, as debt has been paid down. We also sold scrap tubing at our Twin Lakes field, as we worked on plugging two wells.

Foreign exchange loss was $5,037 for the three-month period ended March 31, 2023, compared to a gain of $29,857 for the three-month period ended March 31, 2022. The increase resulted from fluctuations in the value of the United States dollar against the Canadian dollar.

Net Income (Loss)

Net loss for the three months ended March 31, 2023, was $484,426, compared to net income of $215,314 for the three months ended March 31, 2022. The primary reasons for the change were decreased production and increased operating expenses at the Utikuma field, and our increased general and administrative expenses described above.

Liquidity and Capital Resources

As of March 31, 2023, we had total current assets of $1,417,221 and total assets of $8,569,540. Our total current liabilities as of March 31, 2023 were $9,525,711 and total liabilities of $11,892,566. We had negative working capital of $8,108,490 as of March 31, 2023. All of our notes payable are past their maturity dates, and we owe a balance to the operator of the Utikuma asset.

Our material asset balances are made up of oil and gas properties and related equipment. We also held $1,012,859 of cash, and $403,458 of held-for-trading securities. Our most significant liabilities are notes payable and notes payable related party of $3,552,933 along with accounts payable and accrued liabilities totaling $5,967,122. Our largest accounts payable balance is with the operator of the Utikuma asset. The largest accrued liabilities are $1,045,488 of accrued dividends on our preferred stock and $980,677 owed to related parties for board fees and other compensation.

Net cash generated (used) by operating activities was $(92,957) and $75,496 for the three months ended March 31, 2023, and 2022, respectively. The primary cause for the change was payment of fees to outside parties for legal and auditing services.

Net cash from investing activities was $0.00 for the three months ended March 31, 2023, and the three months ended March 31, 2022.

Net cash used by financing activities was $320,576 for the three months ended March 31, 2023; net cash provided by financing activities was $15,544 for the three months ended March 31, 2022. We paid down $320,576 in debt during the three months ended March 31, 2023. The cash provided in 2022 was proceeds from issuance of preferred stock, offset by payments of $9,456 to notes payable.

During the three months ended March 31, 2023, the Company operated at a negative cash flow from operations of approximately $31,000 per month, and our auditors have raised a going concern.

The Company has suffered recurring losses from operations. These conditions raise substantial doubt about the Company’s ability to continue as a going concern. We plan to generate profits by working over existing wells, reducing general and administrative expenses and resolving ongoing litigation. However, we may need to raise additional funds to workover wells through the sale of our securities, through loans from third parties or from third parties willing to pay our share of drilling and completing the wells. We do not have any commitments or arrangements from any person to provide us with any additional capital.

If additional financing is not available when needed, we may need to cease operations. There can be no assurance that we will be successful in raising the capital needed to recomplete oil or gas wells nor that any such additional financing will be available to us on acceptable terms or at all.

Management believes that actions presently being taken to obtain additional funding provide the opportunity for the Company to continue as a going concern. 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.

Trends Affecting Future Operations

The factors that will most significantly affect our results of operations will be (i) the sale prices of crude oil and natural gas, (ii) the amount of production sold from oil or gas wells in which we have an interest, and (iii) lease operating expenses. Our revenues will also be significantly impacted by our ability to maintain or increase oil or gas production through exploration and development activities, and the availability of funding to complete such activities.

It is expected that our principal source of cash flow will be from the production and sale of crude oil and natural gas reserves which are depleting assets. Cash flow from the sale of oil and gas production depends upon the quantity of production and the price obtained for the production. An increase in prices will permit us to finance our operations to a greater extent with internally generated funds, may allow us to obtain equity financing more easily or on better terms, and lessen the difficulty of obtaining financing. However, price increases may heighten the competition for oil and gas prospects and may increase the costs of exploration and development.

A decline in oil and gas prices (i) will reduce the cash flow internally generated by the Company which in turn will reduce the funds available for exploring for and replacing oil and gas reserves, (ii) will increase the difficulty of obtaining equity and debt financing and worsen the terms on which such financing may be obtained, (iii) will reduce the number of oil and gas prospects which have reasonable economic terms, (iv) may cause us to permit leases to expire based upon the value of potential oil and gas reserves in relation to the costs of exploration, (v) may result in marginally productive oil and gas wells being abandoned as non-commercial, and (vi) may increase the difficulty of obtaining financing. However, price declines reduce the competition for oil and gas properties and correspondingly reduce the prices paid for leases and prospects.

Critical Accounting Policies and New Accounting Pronouncements

In December 2001, the SEC requested that all registrants list their most “critical accounting polices” in the Management Discussion and Analysis. The SEC indicated that a “critical accounting policy” is one which is both important to the portrayal of a company’s financial condition and results, and requires management’s most difficult, subjective, or complex judgments, often as a result of the need to make estimates about the effect of matters that are inherently uncertain.

Going concern – The accompanying financial statements have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. The Company has incurred cumulative net losses of $63,544,521 since its inception and requires capital for its contemplated operational and marketing activities to take place. The Company’s ability to raise additional capital through the future sales of common stock is unknown. The obtainment of additional financing, the successful development of the Company’s contemplated plan of operations, and its transition, ultimately, to the attainment of profitable operations are necessary for the Company to continue operations. The ability to successfully resolve these factors raise substantial doubt about the Company’s ability to continue as a going concern. The consolidated financial statements of the Company do not include any adjustments that may result from the outcome of these aforementioned uncertainties.

Item 3 Quantitative and Qualitative Disclosures about Market Risk

Pursuant to Item 305(e) of Regulation S-K (§ 229.305(e)), the Company is not required to provide the information required by this Item as it is a “smaller reporting company,” as defined by Rule 229.10(f)(1).

Item 4 Controls and Procedures

(a) Disclosure Controls and Procedures. The Company’s Chief Executive Officer (the principal executive officer) and Interim Chief Financial Officer (principal financial/accounting officer) have evaluated the effectiveness of the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of March 31, 2023. Based upon such evaluation, the Chief Executive Officer and the interim Chief Financial Officer have concluded that, as of the end of such period, the Company’s disclosure controls and procedures were not effective to provide reasonable assurance that information required to be disclosed in our reports filed with the Commission pursuant to the Exchange Act, is recorded properly, processed, summarized and reported within the time periods specified in the rules and forms of the Commission and that such information is accumulated and communicated to our management, including our CEO and CFO, to allow timely decisions regarding required disclosures.

In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints, and that management is required to apply its judgment in evaluating the benefits of possible controls and procedures relative to their costs.

(b) Changes in Internal Controls. There were no changes in our internal controls over financial reporting during the quarter ended March 31, 2023 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II: OTHER INFORMATION

Item 1 Legal Proceedings

On January 28, 2022, the Securities and Exchange Commission filed an Order Instituting Administrative Proceedings and Notice of Hearing Pursuant to Section 12(j) of the Securities Exchange Act of 1934 to suspend for a period not exceeding twelve months or revoke the registration of each class of securities registered pursuant to Section 12 of the Exchange Act of the Company. The Division of Enforcement at the Securities and Exchange Commission (the “Division”) filed a Motion for Summary Disposition in this matter and the Company filed a Response to the Motion for Summary Disposition in April 2022. On May 5, 2022, the Division filed its Response in Support of its Motion for Summary Disposition. On April 18, 2023, the Company was ordered to submit a brief by May 16, 2023, regarding the Company’s remedial efforts since these proceedings were instituted. The Company plans to submit such brief by May 16, 2023. The ultimate outcome of the proceeding is unknown and could result in the termination of the Exchange Act registration of the Company’s common stock pursuant to Section 12(j) of the Exchange Act.

The Company and Petrolia Canada Corporation (“Petrolia Canada”), an affiliate of Petrolia, filed a lawsuit in the 133^rd Judicial District Court, Harris County Texas (Cause No. 2022-15278), against Jovian Petroleum Corporation, Zel Khan (“Khan”) and Quinten Beasley (“Beasley”) (collectively, the “Defendants”).

In the petition against the Defendants, Petrolia and Petrolia Canada alleged causes of action for fraud and breach of contract against all the named Defendants and breach of fiduciary duty claims against Defendants Zel Khan and Quinten Beasley. Defendant Zel Khan was a former CEO and Director of Petrolia, and Defendant Quinten Beasley was a former Senior Vice President and Director of Petrolia Canada.

Petrolia and Petrolia Canada demanded a jury trial and are seeking monetary relief of more than $1 million against the Defendants.

In April and May 2022, each of the Defendants filed an Original Answer, generally denying all of the allegations of Petrolia and Petrolia Canada.

Subsequently, in September 2022, Defendants filed an amended answer and counterclaims. Pursuant to the amended answer, Defendants generally denied the allegations of Petrolia and Petrolia Canada and are seeking indemnification under the Company’s governing documents and statutory provisions.

Beasley is seeking repayment of the outstanding balance of $5,000 plus accrued interest ($4,710) allegedly owed to him by the Company in connection with a promissory note entered into with the Company on July 14, 2016

In September 2022, Joel Oppenheim (“Oppenheim”) and Critical Update, Inc., owned by Beasley (“Critical Update” and collectively with Oppenheim, the “Intervenors”), filed a Petition in Intervention. Oppenheim alleges that he advanced at least $797,000 to the Company from 2015 to 2019 (including $416,900 alleged owed under a loan agreement) and that he also provided various certificates of deposit to the Company in the aggregate amount of $258,251. Oppenheim is seeking return of amounts advanced with interest, a declaratory judgment establishing the amount of Company stock and warrants owed to him, and attorney’s fees. Separately, Critical Update is seeking $120,000 CAD alleged owed to it in consideration for services rendered to Petrolia Canada, plus interest and attorney’s fees.

On October 11, 2022, Petrolia and Petrolia Canada filed a general denial of all the Defendants’ counterclaims.

Subsequently, on December 6, 2022, Oppenheim filed a motion for severance asking the court to sever his breach of loan agreement claim from the other claims in this lawsuit and adjudicate the claim as Cause No. 2022-15278-B. The same day, Oppenheim also filed a motion for partial summary judgment on his breach of loan agreement claim. On December 22, 2022, Oppenheim filed a separate lawsuit and application for temporary injunction (Cause No. 2022-83054) in the 157^th Judicial District Court, Harris County Texas against the Company and Petrolia Canada and their individual board members. That action is a shareholder derivative lawsuit filed against the Company alleging, among other things, breach of duty of loyalty and breach of duty of obedience, as well as seeking to compel a shareholder meeting and seeking expedited discovery. On December 30, 2022, Jovian Petroleum Corporation filed a petition in intervention to join this newly filed lawsuit.

In January 2023, Petrolia and Petrolia Canada filed a motion to strike the intervention of Oppenheim and on February 3, 2023, Oppenheim filed a response to that motion arguing that such intervention is proper. Such motions are still pending with the court.

On February 9, 2023, Edna Meyer-Nelson, Suzanne Klein, and Laura S. Ward (the “First Additional Intervenors”), each a shareholder of the Company, filed a separate Petition in Intervention to join in Oppenheim’s derivative suit against the Company.

On March 2, 2023, Dr. Marvin Chasen and Billie Mae Chasen (the “Second Additional Intervenors”, and together with the First Additional Intervenor), filed a separate Petition in Intervention to join in Oppenheim’s derivative suit against the Company.

The Additional Intervenors are seeking an order compelling an annual shareholder meeting of the Company; a temporary injunction requiring the Defendants to hold an annual and special meeting of the shareholders of the Company within 30 days to elect directors of the Company and conduct such other proper business as may come before it; a temporary injunction enjoining the Defendant Directors from voting their Series B Preferred Shares; an order combining the hearing on the temporary injunction with a trial on the merits; expedited discovery; and upon final trial, the Additional Intervenors are requesting: (i) rescission of the Series B Preferred Stock; (ii) forfeiture of all compensation paid to the Defendant Directors by the Company after the Series B Preferred Stock issuance; (iii) actual damages in an amount to be proven at trial; (iv) exemplary damages sufficient to deter the directors of other Texas corporations from disenfranchising a corporation’s shareholders, as alleged by the Additional Intervenors; (v) attorneys’ fees and expenses; and (vi) such other and further relief to which Additional Intervenors are entitled.

The outcome of the above litigation is currently unknown; however, the Company disputes the Defendants’ counterclaims and the allegations of the Intervenors and intends to defend the matter vigorously, while also continuing to seek all damages which it is due.

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.

Item 1A Risk Factors

There have been no material changes from the risk factors previously disclosed in Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2022, filed with the Commission on May 12, 2023 under the heading “Risk Factors”, except as set forth below and investors should review the risks provided in the Form 10-K and below, prior to making an investment in the Company. The business, financial condition and operating results of the Company can be affected by a number of factors, whether currently known or unknown, including but not limited to those described in the Form 10-K for the year ended December 31, 2022 under “Risk Factors” and below, any one or more of which could, directly or indirectly, cause the Company’s actual financial condition and operating results to vary materially from past, or from anticipated future, financial condition and operating results. Any of these factors, in whole or in part, could materially and adversely affect the Company’s business, financial condition, operating results and stock price.

Unanticipated problems at, or downtime affecting, our facilities and those operated by third parties on which we rely could have a material adverse effect on our results of operations.

The occurrence of significant unforeseen conditions or events in connection with the operation or maintenance of our facilities, such as the need to refurbish such facilities, complete capital projects at such facilities, shortages of workers or materials, adverse weather, including, but not limited to lightning strikes, floods, hurricanes, tornadoes and earthquakes, equipment failures, fires, explosions, oil or other leaks, damage to or destruction of property and equipment associated therewith, environmental releases and/or damage, government regulation changes affecting the use of such facilities, terrorist attacks, mechanical or physical failures of equipment, acts of God, or other conditions or events, could prevent us from operating our facilities, or prevent such third parties from operating their facilities, or could force us or such third parties to shut such facilities down for repairs, maintenance, refurbishment or upgrades for a significant period of time.

For example, on May 5, 2023, the Company was notified by BSR, the operator of our Utikuma asset that the Province of Alberta has declared a state of emergency due to wildfires in Alberta. We were informed that because of wildfires in the vicinity of our oilfield assets, the field was shut in and all personnel were evacuated, and that the highway to the Slave Lake area has been closed. Early assessments of the situation indicate that our Utikuma facilities may have incurred some damage.

Item 2 Unregistered Sales of Equity Securities and Use of Proceeds

There were no securities sold by the Company during and through the date of filing of this report.

Item 3 Defaults Upon Senior Securities

None.

Item 4 Mine Safety Disclosures

Not Applicable.

Item 5 Other Information

None.

Item 6 Exhibits

* Filed herewith.

** Furnished herewith.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.