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:
|
● |
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. |
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
March 31, 2023 | |
Level 1 | | |
Level 2 | | |
Level 3 | | |
Total | |
ARO liabilities | |
| — | | |
| — | | |
| 2,350,530 | | |
| 2,350,530 | |
| |
| | | |
| | | |
| | | |
| | |
December 31, 2022 | |
| | | |
| | | |
| | | |
| | |
ARO liabilities | |
| — | | |
| — | | |
| 2,301,335 | | |
| 2,301,335 | |
The
carrying value of cash, accounts receivable, other current assets, accounts payable, accounts payable – related parties, accrued
liabilities and accrued liabilities – related parties, as reflected in the consolidated balance sheets, approximate fair value,
due to the short-term maturity of these instruments. The carrying value of notes payable approximates their fair value due to immaterial
changes in market interest rates and the Company’s credit risk since issuance of the instruments or due to their short-term nature.
Derivative liabilities are remeasured at fair value every reporting period. Our derivative liabilities are considered level 3 financial
instruments.
Related
parties
The
Audit Committee approves all material related party transactions. The Audit Committee is provided with the details of each new, existing
or proposed related party transaction, including the terms of the transaction, the business purpose of the transaction, and the benefits
to the Company and the relevant related party. In determining whether to approve a related party transaction, the following factors are
considered: (1) if the terms are fair to the Company, (2) if there are business reasons to enter into the transaction, (3) if the transaction
would impair independence of an outside Director, or (4) if the transaction would present an improper conflict of interest for any Director
or executive officer. Any member of the Audit Committee who has an interest in the transaction will abstain from voting on the approval
of the related party transaction.
Business
combinations
In
January 2017, the FASB issued ASU 2017-01 Business Combinations (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
Cost | |
Canadian
properties | | |
United
States properties | | |
Total | |
As of December 31, 2021 | |
$ | 2,492,403 | | |
$ | 4,304,622 | | |
$ | 6,797,025 | |
Dispositions | |
| — | | |
| 375 | | |
| 375 | |
Foreign currency translation | |
| (159,363 | ) | |
| — | | |
| (159,363 | ) |
As of December 31, 2022 | |
$ | 2,333,040 | | |
$ | 4,304,997 | | |
$ | 6,638,037 | |
Foreign currency translations | |
| 1,896 | | |
| — | | |
| 1,896 | |
As of March 31, 2023 | |
$ | 2,334,936 | | |
$ | 4,304,997 | | |
$ | 6,639,933 | |
| |
| | | |
| | | |
| | |
Accumulated depletion | |
| | | |
| | | |
| | |
As of December 31, 2021 | |
$ | 387,409 | | |
$ | 61,551 | | |
$ | 448,960 | |
Depletion | |
| 237,067 | | |
| — | | |
| 237,067 | |
Foreign currency translation | |
| (34,273 | ) | |
| — | | |
| (34,273 | ) |
As of December 31, 2022 | |
$ | 590,203 | | |
$ | 61,551 | | |
$ | 651,754 | |
Depletion | |
| 44,806 | | |
| — | | |
| 44,806 | |
Foreign currency translation | |
| 450 | | |
| — | | |
| 450 | |
As of March 31, 2023 | |
$ | 635,459 | | |
$ | 61,551 | | |
$ | 697,010 | |
| |
| | | |
| | | |
| | |
Net book value as of December 31, 2022 | |
$ | 1,742,837 | | |
$ | 4,243,446 | | |
$ | 5,986,283 | |
Net book value as of March 31, 2023 | |
$ | 1,699,477 | | |
$ | 4,243,446 | | |
$ | 5,942,923 | |
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
| |
Balance
Sheet Classification | |
March
31, 2023 | | |
December
31, 2022 | |
| |
| |
| | |
| |
Right-of-use assets | |
Other long-term assets | |
| 21,706 | | |
| 23,086 | |
Current lease liabilities | |
Other current liabilities | |
| 5,656 | | |
| 5,482 | |
Non-current lease liabilities | |
Other long-term liabilities | |
| 16,325 | | |
| 17,714 | |
As
of March 31, 2023, the maturities of our lease liability are as follows:
SCHEDULE
OF MATURITIES LEASE LIABILITY
| |
| | |
2023 | |
$ | 3,808 | |
2024 | |
| 5,714 | |
2025 | |
| 6,472 | |
2026 | |
| 5,987 | |
Total | |
$ | 21,981 | |
Less imputed interest | |
| (275 | ) |
Present value of lease liabilities | |
$ | 21,706 | |
NOTE
8. NOTES PAYABLE
The
following table summarizes the Company’s notes payable:
SCHEDULE
OF NOTES PAYABLE
| |
Interest rate | | |
Date of maturity | |
March
31, 2023 | | |
December
31, 2022 | |
Credit note I(ii) | |
| 10 | % | |
January 1, 2020 | |
$ | 286,446 | | |
$ | 426,909 | |
Discount on credit note I | |
| | | |
| |
| (27,715 | ) | |
| (41,572 | ) |
Lee Lytton | |
| | | |
On Demand | |
| 3,500 | | |
| 3,500 | |
M. Hortwitz | |
| 10 | % | |
October 14, 2016 | |
| 10,000 | | |
| 10,000 | |
| |
| | | |
| |
$ | 272,231 | (i) | |
$ | 398,837 | |
|
(i) |
All
notes are current liabilities (due within one year or less from March 31, 2023). |
|
|
|
|
(ii) |
On
January 2, 2020, the Company entered into a loan agreement in the amount of $1,000,000
with a third party (including a $120,000
origination fee). The note bore interest at an interest rate of $10%
per annum and matured on June
30, 2020, and included (as discussed below) warrants to purchase 5,000,000
shares of common stock (the “Loan Warrants”), at an exercise price of $0.10
per share in Canadian dollars which expired on January
2, 2023. The fair value of issued warrants were recorded as a debt discount of $266,674
and monthly amortization of $11,111.
These funds were initially placed in escrow, then on May 29, 2020, they were used for the purchase of the Utikuma oil field.
Pursuant to a loan extension agreement, on October 30, 2020, the Company issued warrants to purchase 5,000,000
shares of common stock, at an exercise price of $0.05
per share which expired on January
6, 2023. The fair value of the issued warrants was recorded as a debt discount of $166,289
and monthly amortization of $4,614. Payments totaling $150,000 were made on this note during the first quarter of 2023, applied to accrued interest first
and then principal. |
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
| |
| | |
2023 | |
$ | 272,231 | |
Thereafter | |
| — | |
Total | |
$ | 272,231 | |
NOTE
9. RELATED PARTY NOTES PAYABLE
The
following table summarizes the Company’s related party notes payable:
SCHEDULE OF RELATED PARTY
NOTES PAYABLE
| |
Interest rate | | |
Date of maturity | |
March
31, 2023 | | |
December
31, 2022 | |
Quinten Beasley | |
| 10 | % | |
October 14, 2016 | |
| 5,000 | | |
| 5,000 | |
Blue Sky Resources (ii) | |
| 3.5 | % | |
December 31, 2021 | |
| 178,923 | | |
| 178,923 | |
Blue Sky Resources (iii) | |
| 10 | % | |
December 31, 2021 | |
| 150,000 | | |
| 150,000 | |
Blue Sky Resources (iv) | |
| 10 | % | |
December 31, 2022 | |
| 2,085,432 | | |
| 2,085,432 | |
Ivar Siem (v) | |
| 9 | % | |
December 31, 2021 | |
| 278,435 | | |
| 278,435 | |
Mark Allen (vi) | |
| 9 | % | |
September 2, 2021 | |
| 55,000 | | |
| 55,000 | |
Mark Allen (vii) | |
| 12 | % | |
June 30, 2020 | |
| 200,000 | | |
| 200,000 | |
Mark Allen (viii) | |
| 9 | % | |
June 30, 2021 | |
| 61,012 | | |
| 241,125 | |
Joel Oppenheim (ix) | |
| 10 | % | |
December 31, 2021 | |
| 266,900 | | |
| 266,900 | |
| |
| | | |
| |
$ | 3,280,702 | (i) | |
$ | 3,460,815 | |
|
(i) |
All
notes are current liabilities (due within one year or less from March 31, 2023.) |
|
|
|
|
(ii) |
On
February 9, 2018, the Company entered into a Revolving Line of Credit Agreement (“LOC”) for $200,000 (subsequently increased
to $500,000 on April 12, 2018) with Jovian Petroleum Corporation (“Jovian”). The CEO of Jovian is Quinten Beasley, our
former director (resigned October 31, 2018), and 25% of Jovian is owned by Zel C. Khan, our former CEO and director. The initial
agreement was for a period of 6 months, and it previously could be extended for up to 5 additional terms of 6 months each. All amounts advanced
pursuant to the LOC will bear interest from the date of advance until paid in full at 3.5% simple interest per annum. Interest will
be calculated on a basis of a 360-day year and charged for the actual number of days elapsed. This LOC was subsequently extended until December 31, 2021. On February 2, 2022, the LOC was assigned to Blue Sky Resources. |
|
|
|
|
(iii) |
On
February 3, 2022, Joel Oppenheim, a former Board member, assigned $150,000
of his note to Blue Sky Resources. |
|
|
|
|
(iv) |
On
December 1, 2021, the Company signed an amended loan agreement with a third party for $2,085,432, which combined prior credit notes
and accrued interest on those amounts. The loan bears interest at 10% per annum and had a maturity date of December 31, 2022. The
note was secured by a security interest against the 25% Working Interest in the Cona assets, a security guarantee of a working interest
in the Utikuma oil field and a working interest in the TLSAU field. The note was assigned to Blue Sky Resources on February 11, 2022,
and moved to Related Party Notes Payable. |
|
|
|
|
(v) |
On
August 15, 2019, the Company entered into a loan agreement in the amount of $75,000
with Ivar Siem, a member of the Board of Directors. The note bears interest at an interest rate of 12%
per annum with a four (4) month maturity. On December 4, 2019, the Company entered into a loan agreement in the amount of $100,000
with Ivar Siem. The note bears interest at an interest rate of 12%
per annum with a six (6) month maturity. At the maturity date, the noteholder has the right to collect the principal plus interest
or convert into 1,250,000
shares of common stock at $0.08
per share. In addition, if converted, the noteholder will also receive 5,000,000
warrants at an exercise price of $0.10
per share, vesting immediately with a 36-month expiration period. On February 28, 2020, the Company entered into a $50,000
loan agreement with Ivar Siem. The note does not bear any interest (0%
interest rate) and is due on demand. The note includes warrants to purchase 200,000
shares of common stock (the “Loan Warrants”), at an exercise price of $0.10
per share in Canadian dollars and expired on March
1, 2022. The warrants were issued on January 1, 2021. On January 1, 2021, the Company entered into an amended loan agreement
in the amount of $278,435,
which combined the three previous loans, along with accrued interest. The note bears an interest rate of 9%
per annum and matured on December
21, 2021. |
|
(vi) |
On
April 15, 2020, the Company entered into an agreement with Mark Allen, that included a funding clause where the Company borrowed
$55,000
from Mr. Allen, the Company’s Chief Executive Officer. The note bears interest at an interest rate of 9%
per annum and matured on September
2, 2021. |
|
|
|
|
(vii) |
During
2019, the Company entered into a loan agreement in the amount of $200,000 with Mark Allen. The note bears interest at an interest
rate of 12% per annum and matured on June 30, 2020. At the maturity date, the note holder has the right to collect the principal
plus interest or convert into 2,500,000 shares of common stock at $0.08 per share. In addition, upon conversion, the note holder
will also receive 10,000,000 warrants at an exercise price of $0.10 per share, vesting immediately with a 36-month expiration period.
|
|
|
|
|
(viii) |
On
January 3, 2020, the Company entered into a loan agreement in the amount of $100,000 with
Mark Allen. The note bears interest at an interest rate of 10%
per annum and matured on June
1, 2020, with warrants to purchase 400,000
shares of common stock (the “Loan Warrants”), at an exercise price of $0.10
per share in Canadian dollars and expire on January 3, 2023. The fair value of issued warrants were recorded as a debt discount of
$31,946
and monthly amortization of $1,775.
On February 14, 2020, the Company entered into a loan agreement in the amount of $125,000
with Mark Allen. The note bears interest at an interest rate of 10%
per annum and matures on June
1, 2020, with warrants to purchase 750,000
shares of common stock (the “Loan Warrants”), at an exercise price of $0.10
per share in Canadian dollars and expired on February
14, 2022. The fair value of issued warrants were recorded as a debt discount of $38,249
and monthly amortization of $1,903.
On January 1, 2021, the Company entered into an amended loan agreement in the amount of $245,938,
which combined the two previous loans, along with accrued interest. The note bears an interest rate of 9%
and matured on June
30, 2021. A payment of $196,344 was made on this note in the first quarter of 2023, applied to accrued interest first and then
principal. |
|
|
|
|
(ix) |
Various
shareholder advances were provided by Joel Oppenheim during 2018 and 2019. There were no formal documents drawn. Interest rates
were applied based on other similar loan agreements entered into by the Company during that period. On February 12, 2021, the Company
entered into an amended loan agreement in the amount of $416,900 that consolidated these amounts. The loan bears interest at 10%
per annum and matured on December 31, 2021. On August 31, 2021, this loan was in default due to missed interest payments,
and a default interest rate was applied to the principal balance. On February 3, 2022, $150,000 of this note was assigned to Blue
Sky Resources. |
The
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
| |
| | |
2023 | |
$ | 3,280,702 | |
Thereafter | |
| — | |
Total | |
$ | 3,280,702 | |
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
| |
March
31, 2023 | |
Inflation rate | |
| 1.92
- 2.15 | % |
Estimated asset life | |
| 12-21 years | |
The
following table shows the change in the Company’s ARO liability:
SCHEDULE
OF CHANGE IN ASSET RETIREMENT OBLIGATIONS
| |
Canadian
properties | | |
United
States properties | | |
Total | |
Asset retirement obligations, December 31, 2021 | |
$ | 1,186,297 | | |
$ | 1,070,730 | | |
$ | 2,257,027 | |
Accretion expense | |
| 145,191 | | |
| 28,412 | | |
| 173,603 | |
Disposition | |
| — | | |
| (47,624 | ) | |
| (47,624 | ) |
Foreign currency translation | |
| (81,671 | ) | |
| — | | |
| (81,671 | ) |
Asset retirement obligations, December 31, 2022 | |
$ | 1,249,816 | | |
$ | 1,051,518 | | |
$ | 2,301,335 | |
Accretion expense | |
| 37,550 | | |
| 10,655 | | |
| 48,205 | |
Foreign currency translation | |
| 991 | | |
| — | | |
| 991 | |
Asset retirement obligations, March 31, 2023 | |
$ | 1,288,357 | | |
$ | 1,062,173 | | |
$ | 2,350,530 | |
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
| |
Warrants | | |
Weighted Average Exercise Price | |
Outstanding at year ended December 31, 2021 | |
| 29,700,000 | | |
| 0.13 | |
Granted | |
| 1,000,000 | | |
| 0.10 | |
Expired | |
| (6,730,000 | ) | |
| 0.11 | |
Outstanding at year ended December 31, 2022 | |
| 23,970,000 | | |
| 0.13 | |
Granted | |
| 250,000 | | |
| 0.10 | |
Expired | |
| (6,000,000 | ) | |
| 0.12 | |
Outstanding at March 31, 2023 | |
| 18,220,000 | | |
$ | 0.14 | |
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
| |
March
31, 2023 | | |
December
31, 2022 | |
Warrants granted: | |
| | | |
| | |
Pursuant to financing arrangements | |
| 250,000 | | |
| 1,000,000 | |
Total | |
| 250,000 | | |
| 1,000,000 | |
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
| |
March
31, 2023 | | |
December
31, 2022 | |
Risk-free interest rate | |
| 3.81 | % | |
| 2.49% – 4.22 | % |
Expected life | |
| 3.0 years | | |
| 3.0 years | |
Expected dividend rate | |
| 0 | % | |
| 0 | % |
Expected volatility | |
| 253 | % | |
| 267% to 299 % | |
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
| |
Canada | | |
United States | | |
Total | |
Three months ended March 31, 2022 | |
| | | |
| | | |
| | |
Revenue | |
$ | 1,830,281 | | |
$ | 6,079 | | |
$ | 1,836,360 | |
Production costs | |
| (1,263,889 | ) | |
| (12,386 | ) | |
| (1,276,275 | ) |
Depreciation, depletion, amortization, and accretion | |
| (87,190 | ) | |
| (7,804 | ) | |
| (94,994 | ) |
Results of operations from producing activities | |
$ | 479,202 | | |
$ | (14,111 | ) | |
$ | (465,091 | ) |
| |
| | | |
| | | |
| | |
Total long-lived assets, March 31, 2022 | |
$ | 2,083,418 | | |
$ | 4,243,225 | | |
$ | 6,326,643 | |
| |
| | | |
| | | |
| | |
Three months ended March 31, 2023 | |
| | | |
| | | |
| | |
Revenue | |
$ | 1,376,317 | | |
$ | — | | |
$ | 1,376,317 | |
Production costs | |
| (1,651,335 | ) | |
| (8,145 | ) | |
| (1,659,480 | ) |
Depreciation, depletion, amortization, and accretion | |
| (82,356 | ) | |
| (10,655 | ) | |
| (93,011 | ) |
Results of operations from producing activities | |
$ | (357,374 | ) | |
$ | (18,800 | ) | |
$ | (376,174 | ) |
| |
| | | |
| | | |
| | |
Total long-lived assets, March 31, 2023 | |
$ | 1,699,477 | | |
$ | 4,243,446 | | |
$ | 5,942,923 | |
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.