UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

 Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

 

For the Fiscal Year Ended August 31, 2021

 

or

 

 Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

 

Commission File Number: 000-55991

 

PETROTEQ ENERGY INC.

(Exact name of registrant as specified in its charter)

 

Ontario   None
(State or other jurisdiction of
incorporation or organization)
  (I.R.S. Employer
Identification No.)
     

15315 W. Magnolia Blvd, Suite 120

Sherman Oaks, California

  91403
(Address of principal executive offices)   (Zip code)

 

(866) 571-9613

(Registrant’s telephone number, including area code)

 

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

 

Title of each class:   Trading Symbol(s):   Name of each exchange on which registered:
N/A   N/A   N/A

 

Securities registered pursuant to section 12(g) of the Act:

 

Common Shares, without par value
(Title of Class)

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes    No 

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes    No 

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant 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 a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. 

 

Large accelerated filer  Accelerated filer 
Non-accelerated filer  Smaller reporting company 
  Emerging growth company   

 

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 Act).  Yes    No 

 

The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold on the TSX Venture Exchange as of the last business day of the registrant’s most recently completed second fiscal quarter (CAD$0.07 converted to US$0.0552 on February 28, 2021) was approximately: $17,419,452.

 

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:

 

Number of shares of common stock outstanding as of December 14, 2021 was 646,053,821.

 

Documents incorporated by reference: None.

 

 

 

 

 

NOTE REGARDING FORWARD-LOOKING STATEMENTS

 

This Annual Report on Form 10-K contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). In particular, statements contained in this Annual Report on Form 10-K, including but not limited to, statements regarding the sufficiency of our cash, our ability to finance our operations and business initiatives and obtain funding for such activities; our future results of operations and financial position, business strategy and plan prospects are forward looking statements. These forward-looking statements relate to our future plans, objectives, expectations and intentions and may be identified by words such as “may,” “will,” “should,” “expects,” “plans,” “anticipates,” “intends,” “targets,” “projects,” “contemplates,” “believes,” “seeks,” “goals,” “estimates,” “predicts,” “potential” and “continue” or similar words. Readers are cautioned that these forward-looking statements are based on our current beliefs, expectations and assumptions and are subject to risks, uncertainties, and assumptions that are difficult to predict, including those identified below, under Part I, Item 1A. “Risk Factors” and elsewhere in this Annual Report on Form 10-K. Therefore, actual results may differ materially and adversely from those expressed, projected or implied in any forward-looking statements. We undertake no obligation to revise or update any forward-looking statements for any reason. 

 

NOTE REGARDING COMPANY REFERENCES

 

Throughout this Annual Report on Form 10-K, “Petroteq,” the “Company,” “we,” “us” and “our” refer to Petroteq Energy Inc.

 

 

 

 

PETROTEQ ENERGY INC.

 

FORM 10-K

 

TABLE OF CONTENTS

 

      Page
       
  PART I.   1
Item 1. Business   1
Item 1A. Risk Factors   21
Item 1B. Unresolved Staff Comments   38
Item 2. Properties   38
Item 3. Legal Proceedings   39
Item 4. Mine Safety Disclosures   39
  PART II.   41
Item 5. Market price of, and dividends of the Registrant’s Common Equity and Related Stockholder Matters   41
Item 6. Selected Financial Data   41
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations   42
Item 7A. Quantitative and Qualitative Disclosures About Market Risk   45
Item 8. Financial Statements and Supplementary Data   F-1
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure   46
Item 9A. Controls and Procedures   46
Item 9B. Other Information   46
  PART III.   47
Item 10. Directors, Executive Officers and Corporate Governance   47
Item 11. Executive Compensation   49
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters   53
Item 13. Certain Relationships and Related Transactions, and Director Independence   54
Item 14. Principal Accountant Fees and Services   56
  PART IV.    
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 10-K   57
Item 16. Form 10-K Summary   58
SIGNATURES   59

 

i

 

 

PART I

 

ITEM 1. BUSINESS.

 

BUSINESS OVERVIEW

 

We are a holding company organized under the laws of Ontario, Canada, that is engaged in various aspects of the oil and gas industry. Our primary focus is on the development and implementation of our proprietary oil sands mining and processing technology to recover oil from surface mined bitumen deposits. Our wholly-owned subsidiary, Petroteq Energy CA, Inc., a California corporation (“PCA”), conducts our oil sands extraction business through two wholly owned operating companies, Petroteq Oil Recovery, LLC, a Utah limited liability company (“POR”), and TMC Capital, LLC, a Utah limited liability company (“TMC Capital”). Another subsidiary, Petrobloq LLC, a California limited liability company (“Petrobloq”), also wholly owned by Petroteq, is currently dormant.

  

Oil Sands & Processing

 

Through PCA, our wholly-owned subsidiary, and PCA’s two subsidiaries POR and TMC Capital, we are in the business of exploring for, extracting and producing oil and hydrocarbon products from oil sands deposits and sediments located in the Asphalt Ridge Are of Uintah County, Utah, utilizing our proprietary extraction technology (the “Petroteq Clean Oil Recovery Technology” or “Extraction Technology”). Our primary oil sands extraction and processing operations are conducted at our Asphalt Ridge processing facility (herein the “Asphalt Ridge Plant” or “Plant”), which is owned by POR.

 

Petroteq owns the intellectual property rights to the Petroteq Clean Oil Recovery Technology which is used at our Asphalt Ridge Plant to extract and produce crude oil from oil sands utilizing a closed-loop solvent based extraction system.

 

The Asphalt Ridge Plant initially commenced operations as a pilot plant in 2015 at a site near Maeser, Utah, but was relocated in 2017 to a site near our Asphalt Ridge Mine #1 located on lands a Mining and Mineral Lease Agreement dated as of July 1, 2013, between Asphalt Ridge, Inc., as lessor, and TMC, as lessee, (the “TMC Mineral Lease”). The relocation of the Plant near our existing mine site was designed to improve logistical and processing efficiencies in the oil sands recovery process. The relocation of the Plant occurred during a temporary suspension of our mining and processing operations in 2016 that resulted from a sharp decline in world oil prices. We restarted operations at the end of May 2018 and completed expansion work on the Plant to increase production capacity to 400-500 barrels of oil per day during the last quarter of fiscal 2019 (the quarter ended August 31, 2019). During our testing of the Plant and its increased production capacity during the first quarter of fiscal 2020 (the quarter ending November 30, 2019), we determined that a number of equipment upgrades were required to support continuous operation of the Plant. As discussed below, these upgrades were completed in December 2020.

 

We had expected to generate revenue from the sale of hydrocarbon products from the Asphalt Ridge Plant commencing in the third quarter ending May 31, 2020. However, due to the COVID-19 pandemic and volatility in oil prices, we reduced operations to a single shift per day during the quarter ending February 29, 2020 and ultimately suspended operations at the Plant during the quarter ending May 31, 2020.

 

In July 2020, Greenfield Energy LLC (“Greenfield”), a joint venture company formed by TomCo Energy PLC, a UK energy company, and Valkor LLC (“Valkor”), a Texaco limited liability company, assumed the management and operation of the Asphalt Ridge Plant. Under a Technology License Agreement dated July 2, 2019, Petroteq granted to Valkor a non-exclusive license and right to use Petroteq’s Clean Oil Recovery Technology in operations conducted at the Plant. Since July 2020, Greenfield has implemented various upgrades to the Plant to improve operating capacity and reliability and began testing to assess the commerciality of the Plant and Petroteq’s proprietary technology. To improve operational capability during winter months, Greenfield also arranged for buildings to be erected over the nitrogen system and the vapor recovery system and for wind-walls were erected at the mixing tank area and decanter deck at the Plant.

 

1

 

 

Following the startup of the Plant in January 2021, we determined that certain additional equipment would be required to improve the process of extracting bitumen from oil sands ore and the removal of clay fines from produced oil. The additional equipment was required to transition the plant to commercialization and to demonstrate the commerciality of both the Plant and Petroteq’s Clean Oil Recovery Technology. The required equipment was installed and commissioned and the Plant was restarted in April 2021. 

 

The first full load of oil produced by the Plant was sold in June 2021 by Valkor. The production and sale of the first load of oil from the Plant following a series of upgrades was an important milestone as it demonstrated that heavy oil from Utah oil sands can be produced economically using Petroteq’s Clean Oil Recovery Technology without the use of water and without any requirement for a tailings pond. The buyer paid West Texas Intermediate Crude Oil (“WTI”) benchmark pricing of $70.91 per barrel for the 10.2° API heavy sweet crude oil produced by the Plant. The fact that we received WTI pricing for the oil produced by the Plant demonstrates that the heavy sweet (low sulfur) oil produced from Utah’s oil sands in the Asphalt Ridge area will likely command a premium price relative to other heavy oils.

 

The 2021 FEED Design Platform

 

In July 2021, Crosstrails Engineering LLC completed a Front End Engineering Design (the “2021 FEED”) for a 5,000 barrel per day (“BPD”) production train that could be constructed either at the site of the Asphalt Ridge Plant or as a separate oil sands processing facility at an undeveloped site. The 2021 FEED describes the design data, design requirements, detailed major equipment requirement, and general operating philosophies for the development of a 5,000 BPD production train, including a Class 3 (± 25%) cost estimate of approximately $110 million for construction of a new commercial plant as a separate facility. The cost estimates in the 2021 FEED suggest a capital cost of $22,000 per daily barrel of production. A new oil sands processing facility based on the 2021 FEED will consist of an initial 5,000 BPD production train but provides for a possible future expansion to 10,000 BPD through the addition of a second parallel 5,000 BPD train. The capital cost of $22,000 per daily barrel for an initial 5,000 BPD production train installed either as an adjunct to the existing Asphalt Ridge Plant or as a separate processing facility on an undeveloped site compares very favorably with the construction costs of plants and facilities that deploy more traditional methods of extracting bitumen and heavy oil from oil sands.

 

Preliminary estimates for the longest lead time for procuring equipment for a new 5,000 BPD production train under the 2021 FEED are approximately 48-54 weeks. The overall engineering, procurement and construction of a 5,000 BPD plant are estimated to require 54-62 weeks, barring any significant supply chain upsets or adverse weather conditions during construction and commissioning of the plant. Once constructed and operating, it is estimated that each production train will employ 40-50 persons between mining and plant operations.

 

Petroteq anticipates that the 2021 FEED may provide the basis for a standard design package for 5,000 BPD production trains constructed by Petroteq or by its technology licensees in Utah and in other parts of the United States and other countries having oil sands and other structures holding substantial bitumen and heavy oil resources. Any standard design package developed from the 2021 Feed may require a certain amount of customization for local site conditions and ore characteristics, but the differences are not expected to be significant.

 

Status of Mining & Processing Operations

 

After the April 2021 restart, the Asphalt Ridge Plant was operated intermittently until August 2021, when operations were suspended to allow the Company and its engineering firms to conduct a detailed inspection of the Plant for the purpose of determining whether the Plant’s equipment, and the configuration of its units, would permit the integration or auxiliary construction of a new 5,000 BPD production training based on the 2021 FEED. During this period, exploratory core sampling and testing was conducted of the oil sands resources at Asphalt Mine #1.

 

Based on the inspections of the Plant’s units and equipment and evaluations of core data taken from areas at and around Asphalt Ridge Mine #1, the Company preliminarily decided, subject to further study and evaluation, to (a) construct a separate 5,000 BPD oil sands processing plant, with the option of adding a second 5,000 BPD production train, on an undeveloped site in the Asphalt Ridge area (and not as an expansion to the existing Plant), (b) continue to operate the Asphalt Ridge Plant where economic conditions support commercial operations, and (c) to augment the supply of oil sands ore from Asphalt Mine #1 as feedstock for the Plant to higher quality oil sands ores and sediments mined or produced from other leases and properties in the Asphalt Ridge area.

 

2

 

 

In September 2021, we initiated discussions with Valkor for the purpose of developing a long term oil sands ore supply contract with Greenfield for the purchase of oil sands ores produced from mineral leases held or managed by Greenfield in the Asphalt Ridge Northwest area.

 

The Plant is currently in a winterized shut-down, although it may be restarted and operated upon short notice for demonstration purposes and for the purpose of testing and evaluating different oil sands ores and materials sources from different leases and properties in the Asphalt Ridge area. We currently anticipate that the Asphalt Ridge Plant will resume processing and production operations in February-March 2022. Upon resuming operations, the Plant will be operated primarily for the purpose of processing oil sands ores and bituminous sands sourced from both Asphalt Mine #1 and from Asphalt Ridge leases held or managed by Greenfield or Valkor, and potentially from other sources in the Asphalt Ridge area. The Plant will also be used for demonstration purposes for potential investors and prospective technology licensees and for the purpose of testing and evaluating oil sands and heavy oil source material produced from areas within the Uintah Basin in Utah and in other regions of the United States and other countries as such materials are made available to us.

 

Research and Development

 

The Asphalt Ridge Plant has proved that Petroteq’s Clean Oil Recovery Technology, including our redesigned extraction and production process, is capable of producing oil in marketable quantities and that a substantial portion of the “post processed” sand generated by our extraction and production operations may be sold for various uses. Petroteq continued to test ore from various oil sands deposits and resources in the Asphalt Ridge area of Utah, with varying degrees of oil quality and with oil saturations in the range of 5 to 10 percent by weight. Petroteq’s proprietary technology and extraction process has been successful in extracting oil from the different oil sands ores that we have tested, confirming that our oil extraction technology can accommodate a wide range of ore specifications.

 

During the fiscal year ending August 31, 2021, we engaged Kahuna Ventures LLC, an energy-focused project execution firm, to review the POSP operating data, process simulation data, and our 5,000 BPD FEED study. The technical evaluation conducted by Kahuna Ventures indicated extraction costs of approximately $13.50 per barrel of oil produced. With mining and ore transport costs adding another $8.50 per barrel, this suggests an estimated operating cost of approximately $22 per barrel of oil produced (prior to adjustment for corporate overhead, production related taxes and royalties). The estimated operating cost of $22 per produced barrel of oil does not take into account the reduction in net operating costs that may result from the sale of commercial marketable sand generated during our extraction and production operations, which we estimate could reduce our net operating costs, measured on a per barrel of oil produced basis, by as much as $10-15 per barrel.

 

Several barrels of produced oil from the Asphalt Ridge Plant have now been tested by Quadrise Fuels International plc in the United Kingdom for the purpose of assessing the suitability of the heavy sweet oil produced by the POSP for their MSAR® technology. MSAR® is a low viscosity oil-in-water emulsified synthetic heavy fuel oil (“HFO”). It is manufactured using Quadrise’s proprietary technology to mix heavy oils with small amounts of specialist chemicals and water to a bespoke formulation. According to Quadrise, the resulting emulsion contains approximately 30% water and less than 1% chemicals. The emulsion is a low viscosity liquid at room temperature, which makes it easier to handle and reduces the heating costs for storing, transportation and use in comparison to HFOs.

 

In September 2021, Quadrise reported that the testing program, which was completed at the Quadrise Research Facility ("QRF") in Essex, in the United Kingdom, confirmed the ability to produce commercial MSAR® and bioMSAR™ fuels from the sample of heavy sweet oil provided by Greenfield from the POSP and that a report of the testing results has been issued to the client.  Simulations of storage and handling of both MSAR® and bioMSAR™ produced were also completed during the program, which indicated that commercial production of MSAR® and bioMSAR™ fuels would be possible in Utah for potential power and marine end-user applications domestically and internationally. Quadrise further noted that this testing concluded the proof-of-concept work that was scheduled in Phase 1 of the Commercial Trial Agreement between Greenfield and Quadrise announced on August 18, 2020. Quadrise recently reported that Greenfield and Quadrise have entered into discussions regarding potential future trials and deployment of the technology to produce MSAR® and/or bioMSAR™ fuel at a commercial scale.

 

3

 

 

Petroteq continues to work with a local drilling fluids company to identify customers for the commercially marketable sand generated from the Asphalt Ridge Plant for use in oil and gas hydraulic fracturing or “fracking” operations. The fluids company has to date taken 340 tons of sand and it is expected that it will take the additional processed sand currently available, together with additional quantities of sand as and when they are produced at the Plant. The proceeds from the sale of sand are expected to be approximately $15-20 per ton ($10-15 per barrel).

 

As announced by Petroteq on November 17, 2020, Greenfield has executed a non-exclusive, multi-site license with Petroteq (the “Greenfield License”). The Greenfield License has been granted in consideration for $2,000,000 in funding that Greenfield has provided to date for upgrades to the Asphalt Ridge Plant. The Greenfield License will allow Greenfield to use Petroteq’s Clean Oil Recovery Technology in any future oil sands processing plants built by Greenfield in the United States. The Greenfield License provides that the ownership of any intellectual property developed as a result of upgrades to or operations conducted at the POSP, including associated trials and testing, will be owned by Petroteq. At the same time, any such intellectual property, including any oil sands technologies developed by Petroteq, will be included within the scope of the Greenfield License and may be used by Greenfield under the terms of the license.

 

For any future oil sands plants built by Greenfield utilizing the Greenfield License, Greenfield will pay Petroteq a 5% royalty of net revenues received from crude oil and other hydrocarbon products produced from oil sand resources.

 

In October 2021, Petroteq and Big Sky Resources LLC (“Big Sky”), a company based in Rye, New York, entered into a technology license agreement under which Petroteq granted to Big Sky a non-exclusive, non-transferable license and right to use Petroteq's proprietary ‎technology to design, construct, operate and finance oil sands extraction plants ‎at up to two locations in the continental United States. Under the agreement, ‎Big Sky has agreed to pay Petroteq a one-time, non-refundable license fee of ‎$2 million, which will become payable upon commencing construction of its first ‎plant. The agreement further provides that Big Sky will pay Petroteq a 5% royalty on the net revenue received by Big Sky from the ‎production, sale or other disposition of licensed product from the plants for as long as Petroteq continues to hold enforceable and protected intellectual ‎property rights in the licensed technology in the United States.‎

 

Pursuant to the licensing agreement, Big Sky is obligated to engage Valkor LLC (or an affiliate named by Valkor) as ‎the sole and exclusive provider of engineering, planning, and construction ‎services for all oil sands plants built by Big Sky or under its direction. Big Sky has indicated it will work closely with Valkor to identify ‎plant locations in the State of Utah. ‎

 

ASPHALT RIDGE PROCESSING PLANT 

 

In June 2011, Petroteq commenced the development of the Asphalt Ridge Plant at a site near Maeser, Utah and entered into construction and equipment fabrication contracts for the purpose of evaluating Petroteq’s Clean Oil Recovery Technology in extracting, processing and producing crude oil from oil sands mined from the TMC Mineral Lease and from other deposits located in the Asphalt Ridge area of Utah. By January 2014, our initial processing facility, designed as a pilot plant having processing capacity of 250 barrels per day, was fully permitted and construction was completed by October 1, 2014. Operations conducted at the pilot plant during 2015 allowed us to test and evaluate our proprietary technology at or near the Plant’s capacity. During 2015, the Plant produced approximately 10,000 (gross) barrels of oil from the local oil sands ores, including oil sands deposits located within our TMC Mineral Lease. From this production, 7,777.33 barrels of finished crude oil were sold to an oil and gas distributor for resale to its refinery customers, with the balance of the produced oil used internally to power generators for the Plant. The initial processing plant was flexible in that it had the ability to produce both high quality heavy crude oil as well as lighter oil if needed.

 

In 2015, with the sharp decline in world oil prices, we determined that the transportation costs incurred in hauling mined ore from our mine site to pilot processing facility, a distance of approximately 17 miles, were adversely affecting the economics of our processing operations. For that reason, we temporarily suspended operations in 2016, and, in 2017, the Plant was disassembled and moved from its original location to the site of our Temple Mountain mining site (referred to as Asphalt Ridge Mine #1) located within the TMC Mineral Lease. During the reassembly of the Plant, additional equipment was installed to increase the Plant’s capacity from 250 barrels per day to 400-500 barrels per day. In May 2018, mining operations at Asphalt Ridge Mine #1 recommenced, and the new upgraded Asphalt Ridge Plant commenced a test production phase of heavy crude oil from oil sands deposits at this site. Work to increase the Plant’s capacity to 400-500 barrels per day was completed during the last quarter of fiscal 2019 (the quarter ended August 31, 2019). Testing, which continued into the first quarter of fiscal 2020 (the quarter ended November 30, 2019), determined that a number of equipment upgrades were required to support continuous operation of the Plant.

 

4

 

 

Greenfield, a joint venture company established by TomCo and Valkor, assumed responsibility for the management and operations of our Asphalt Ridge Plant in July 2020. Greenfield has made certain upgrades to the Plant to improve its capacity and reliability. During the ensuing year, we anticipate that the Plant will be operated for the purpose of (a) extracting, processing and producing crude oil and other hydrocarbon products from oil sands ores supplied by our Asphalt Mine #1, from Greenfield and potentially from other sources and properties located in the Asphalt Ridge area, (b) evaluating and testing oil sands from varying sources that are impregnated with oils having different qualities and characteristics, and (c) demonstrating the capabilities of Petroteq’s Clean Oil Recovery Technology to potential investors and prospective licensees. Recent budgets for the Plant prepared by Valkor estimate that, during the ensuing year, the Plant will require approximately $3.8 million in capital expenditures and operating expenses and should be able to generate revenue in the range of $4 million.

 

RESOURCES AND MINING OPERATIONS

 

Through its acquisition of TMC Capital in June 2015, Petroteq indirectly acquired certain mineral rights under the TMC Mineral Lease, which encompassed approximately 1,229.82 acres of land in the Temple Mountain area of Asphalt Ridge in Uintah County, Utah. In June 2018, Petroteq, acting through POSR, acquired the record lease title and all of the operating rights to produce oil from oil sands resources under two mineral leases entitled “Utah State Mineral Lease for Bituminous-Asphaltic Sands”, each dated June 1, 2018, between the State of Utah’s School and Institutional Trust Land Administration (“SITLA”), as lessor, and POSR, as lessee, covering lands consisting of approximately 1,351.91 acres that largely adjoin the lands covered by the TMC Mineral Lease (“the Temple Mountain SITLA Leases”). In March 2019, a third SITLA Lease was acquired by Petroteq that added 39.97 acres to the mix in the Temple Mountain area of Asphalt Ridge.

 

In April 2019 and in July 2019, in two separate transactions, TMC Capital acquired an initial 50% and then the remaining 50% of the oil sands operating rights under five (5) federal (U.S.) oil and gas leases administered by the (U.S.) Department of Interior’s Bureau of Land Management (“BLM”), covering lands located in eastern and south-eastern Utah (“BLM Leases”). The BLM Leases have been included in applications, filed decades ago with the BLM under the (U.S.) Combined Hydrocarbon Lease Act of 1981, for conversion to new “Combined Hydrocarbon Leases” that will eventually allow the development of oil sands resources in the federal lands included within the BLM Leases and in surrounding areas,

 

As described in more detail below, the TMC Mineral Lease in its original form was terminated effective August 10, 2020, and a new Short-Term Mining Lease, dated the same date, was entered into between Asphalt Ridge, Inc., as lessor, and Valkor, as lessee. Valkor and TMC Capital thereafter entered into a Short-Term Mining and Mineral Sublease dated August 20, 2020 (the “TMC Mineral Sublease”) in which all of Valkor’s rights and interests under the Short-Term Mining Lease were subleased to TMC Capital. As of August 31, 2021, Petroteq (through its subsidiaries) held mineral leases (or the operating rights under leases) covering approximately 7,631.91 net acres within the State of Utah, consisting of approximately 320 acres held under the TMC Mineral Sublease, 1,351.91 acres held under the Temple Mountain SITLA Leases, and 5,960 acres under the BLM Leases.

 

Between March 14, 2019 and May 31, 2020, we made cash deposits of $1,907,000, included in prepaid expenses and other current assets on the consolidated balance sheets for the acquisition of 100% of the operating rights under U.S. federal oil and gas leases, administered by the BLM in Garfield and Wayne Counties, covering approximately 8,480 gross acres in P.R. Springs and the Tar Sands Triangle within the State of Utah. The total consideration of $3,000,000 has been partially settled by the $1,907,000 cash deposit, with the balance of $1,093,000 still outstanding. 

 

5

 

 

In a letter agreement dated April 17, 2020 between the transferor of the oil and gas leases and TMC Capital, as transferee, the parties, due to uncertainty as to whether all of the 10 leases for which the Company had initially paid deposits would be considered active by BLM and included in new Combined Hydrocarbon Leases (CHLs) under the Combined Hydrocarbon Act of 1981 - agreed to adjust the purchase price as follows: (a) should all 10 of the leases be available and included in CHL’s, the Company will pay the additional $1,093,000 for the rights under the leases; (b) if only a portion of the leases ranging from 4 to 9 of the leases are available and included in CHL’s, the final purchase price of the leases will be between $1.5 million and $2.5 million; and (c) notwithstanding the above, if after a period of 7 years from April 17, 2020, at least six of the leases are not determined to be active and are not included in CHLs the Company shall be entitled to demand a refund of $1.2 million or instruct the Seller to acquire other leases in the same area for up to $1.2 million.

 

The following table sets forth the gross/net developed and undeveloped acreage held under the TMC Mineral Sub-Lease.

  

TMC Mineral Lease

Developed/Undeveloped Acreage (Gross/Net)

Total Acreage
Gross Acres 1,229.82 acres
Net Acres 1,229.82 acres
Developed Acreage
Asphalt Ridge Mine #1/Permit Boundaries
Gross Acres 174.00 acres
Net Acres 174.00 acres
Undeveloped Acreage
Acreage Outside Asphalt Ridge  Mine #1/Permit Boundaries
Gross Acres 1,055.82 acres
Net Acres 1,055.82 acres

 

The TMC Mineral Sublease covers lands situated in or near Utah’s Asphalt Ridge, an area located along the northern edge of the Uintah Basin and containing oil sands deposits located at or near the surface. Most of the oil-impregnated reservoirs or deposits in the Asphalt Ridge area are found in the Rimrock Sandstone (Mesaverde Group Formations) and in the (Tertiary) Duchense River Formation. Substantial bitumen deposits in the Rimrock and Duchense River Formations extend from the northwest in a southeasterly direction through the lands included in the TMC Mineral Sublease, including the lands included in T5S-R22E (Section 31) where our Asphalt Ridge Mine #1 is located. Bitumen and heavy oil saturated pay thicknesses in lands covered by the TMC Mineral Sublease generally range from 50-200 feet or more, with oil content or saturation averaging approximately 6% by weight.

 

As announced by Petroteq on October 29, 2020, a recent survey of Petroteq's lease properties has identified three key areas where the oil sands ore appears to have higher oil saturations than what was previously mined. Samples were taken from each location and lab assays of the samples showed that the ore was a higher quality to that mined previously. These areas are currently anticipated to be the focus of Petroteq's mining efforts during the initial operation of the Asphalt Ridge Plant following its restart. In addition, six corehole locations were staked and, subject to rig availability, will be drilled during January. This work is expected to allow Petroteq's mining consultant to develop a detailed mining plan which would direct future mining operations for extended plant operation. No additional exploratory work has been performed in the preceding three years.

 

The following tables set forth the gross/net undeveloped acreage held under the SITLA Leases and BLM Leases, respectively.

 

SITLA Leases
Developed/Undeveloped Acreage (Gross/Net)
 
SITLA Lease #53806
Gross Acres 833.03 acres
Net Acres 833.03 acres
   
SITLA Lease #53807
Gross Acres 478.91 acres
Net Acres 478.91 acres
   
                                                                             SITLA Lease #53918  
       Gross Acres 39.97 acres
       Net Acres 39.97 acres
All Acreage is Currently Undeveloped

 

6

 

  

BLM Leases

Developed/Undeveloped Acreage (Gross/Net)

 
BLM Lease #U-38071
Gross Acres 1,920.00 acres
Net Acres 1,920.00 acres
   
BLM Lease #U-08291G
Gross Acres  160.00 acres
Net Acres  160.00 acres
   
BLM Lease #U-17781
Gross Acres  1,880.00 acres

 

Net Acres  1,880.00 acres
   
BLM Lease #U-17979
Gross Acres  720.00 acres
Net Acres  720.00 acres
 
BLM Lease #U-20860
Gross Acres  1,280.00 acres
Net Acres  1,280.00 acres
   
All Acreage is Currently Undeveloped

 

The BLM Leases include lands located either in the P.R. Springs or Tar Sands Triangle Areas of Utah, geographic areas that have been designated STSAs by the (U.S.) Department of Interior.

 

TMC Mineral Sublease

 

The TMC Mineral Lease originally issued to TMC Capital in July 2013 has been terminated and replaced with (a) a new Short-Term Mining Lease dated as of August 10, 2020 between Asphalt Ridge, Inc., as lessor, and Valkor, as lessee, and (b) a TMC Mineral Sublease in which all of the rights and interests of Valkor under the Short-Term Mining Lease were subleased to TMC Capital. Under the TMC Mineral Lease, TMC Capital was granted the exclusive right to explore for, mine and produce oil and other minerals associated with oil sands, subject to certain depth limits. The lands covered by and included within the TMC Mineral Sublease include both our Asphalt Mine #1 and the Asphalt Ridge Plant owned by POSR

 

Previously, TMC Capital was the direct lessee under the TMC Mineral Lease, which was amended on October 1, 2015, March 1, 2016, February 1, 2018, and most recently on November 21, 2018. The primary term of the TMC Mineral Lease originally commenced July 1, 2013 and continued for approximately seven years until August 20, 2020,

 

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The TMC Mineral Sublease has a term that is co-extensive with the term of the Short-Term Mining Lease between Asphalt Ridge, Inc. and Valkor, and originally included an expiration date of June 30, 2021. On July 1, 2021 Asphalt Ridge, Inc. and Valkor amended the Short-Term Mining Lease to extend the term of the lease until December 31, 2021, which in turn extended the term of the TMC Mineral Sublease to December 31, 2021 as well. We anticipate that additional extensions will be agreed upon by December 31, 2021 that will extend the term of the Short Term Mining Lease and the TMC Mineral Sublease as may be required to continue operations under the lease and at the Asphalt Ridge Plant during the ensuing year.

 

Upon entering into the TMC Mineral Sublease, TMC Capital paid Valkor an initial rental fee in the amount of $25,000 and is required to pay Valkor a monthly rental fee of $15,000 during the term of the TMC Mineral Sublease. TMC Capital is also obligated to pay production royalties consisting of (a) eight percent (8%) of the gross revenue received from the sale or disposition of bitumen or from oil and other minerals derived from processing bitumen extracted from oil sands deposits within the lands covered by the Sublease.

 

During the year ending August 31, 2020, we received (gross) proceeds of $290,809 from the sale of upgraded or finished oil produced at the Asphalt Ridge Plant from oil sands mined under the TMC Mineral Lease. During our fiscal years ending August 31, 2019 we had sales of $59,335 and for the years ended August 31, 2018 and 2017 and 2016, we had no sales of produced oil since, during this period, we temporarily suspended our mining and processing operations during the relocation, reassembly and expansion of the Plant to a new site located within the TMC Mineral Lease.

 

During the last five (5) months of 2015, we produced approximately 10,000 barrels of oil, with 2,222 barrels consumed as fuel in plant operations and 7,777.33 barrels sold and delivered to an independent purchaser at the Plant. Our use of produced oil as a fuel source for plant generators in 2015 is no longer necessary since the Plant’s power supply is now provided by a local power company. 

 

The costs associated with extraction and processing operations at the Asphalt Ridge Plant that are used in determining our “Average Production Costs” include the costs of oil sands ore, natural gas liquids, aromatic solvent, operator labor, electricity, propane, nitrogen, water, diesel fuel and rental equipment. The primary costs are the costs of mining oil sands ore, natural gas liquids, aromatic solvents, and labor costs. Other than the aromatic solvents, the condensate used as both a solvent and a feedstock in the processing operations at Plant is produced by processing natural gas liquids through a distillation column, with aromatic solvents then added to the distillate. In addition:

 

  Our fixed costs generally remain constant without regard to the API gravity of our upgraded crude oil;

 

  Our oil sands ore costs, which include our mining costs, the cost of transporting mined ore to our processing facility, and pre-processing costs (crushing etc.) incurred in preparing mined ore for processing, do not vary with the API gravity of the oil produced at our facility, but will decrease over time (subject to economies of scale) as our mining operations expand and oil production increases; and

 

  Solvent and condensate costs are based on the market prices that exist for each category of product, which are usually determined by a monthly average of prevailing prices in effect during the month of delivery. Solvent and condensate costs typically increase as the target API gravity for our finished crude oil increases.

 

During the period of August 2018 through December 2018, our “Average Production Costs” at the Asphalt Ridge Plant decreased to $27 per barrel of oil produced at the facility. During this period, our fixed costs did not differ materially from our August 2015 to December 2015 fixed costs. We do anticipate that any increase in production or throughput capacity at the Plant will result in any reduction of the fixed costs per barrel at the facility.

 

With respect to variable costs at the Asphalt Ridge Plant, our oil sands ore cost during the 2018 period increased to an average of $6.65 per barrel, due primarily to the quantity and quality of ore processed, but with cost-savings resulting from the relocation of the Plant to the site of our Asphalt Ridge Mine #1 located within the TMC Mineral Lease. In addition, during the 2018 period, our average cost of aromatic solvent decreased to $0.47 per gallon and the average cost of condensate was substantially lower at $2.75 per barrel, due primarily to our production of heavier oil with an API gravity of between 15 and 25 degrees.

 

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The API gravity for the raw heavy oil or bitumen extracted from oil sands ores initially processed at the Asphalt Ridge Plant has averaged approximately 10 degrees. Through the application of our Crude Oil Recovery Technology at the Plant, we are able to produce a crude oil having a range of API gravity of between 10 degrees and 12 degrees. Through our solvent formulation and the select distillation capabilities, we are able to craft final crude oil products that can meet the specifications of a range of customers.

 

Generally, we have been able to sell the finished oil produced at our Asphalt Ridge Plant at a price representing a discount off an average of published prices for West Texas Intermediate (WTI) crude oil for a specified period.  WTI crude oil is commonly used as a benchmark in pricing oil under oil sales/purchase contracts, particularly in the United States. The discount off the WTI benchmark price is based on a number of factors, including differences that may exist between the specifications of our crude oil and those of WTI crude oil together with the cost of transporting our crude oil to delivery points. Since WTI crude oil generally has an API gravity of between 37-42 degrees, a heavier oil having a lower API gravity in the range of the oil produced at our processing facility will be valued and sold at a price reflecting a discount off the WTI benchmark price. More recently, however, we have been able to sell finished oil produced at the Plant at a price that is closer to or at the WTI benchmark price, suggesting that we are increasingly able to market our produced oils at a premium due to refiner demands for domestic heavy sweet crude oil.

 

Acquisition of the Asphalt Ridge NW Leases

 

Recently, TMC Capital and POSR, Petroteq’s operating subsidiaries, and Valkor entered into an “Agreement Governing Reciprocal Assignment of Mineral Leases” dated October 15, 2021 (the “Exchange Agreement”), under which (a) TMC Capital/POSR agreed to assign to Valkor all of their respective rights and interests in the TMC Mineral Lease, the Short-Term Mining Lease, and the Temple Mountain SITLA Leases, and (b) Valkor agreed to assign to TMC Capital all of its rights and interests in the following Utah state mineral leases located in the Asphalt Ridge Northwest area of Uintah County, Utah (the “Asphalt Ridge NW Leases”):

 

(a) Utah State Mineral Lease for Bituminous-Asphaltic Sands dated as of September 1, 2018 (Mineral Lease No. 53831), executed between the State of Utah, acting by and through the School and Institutional Trust Lands Administration (“SITLA”), as lessor, and Indago Oil and Gas, Inc., as lessee, covering approximately 640 acres;

 

(b) Utah State Mineral Lease for Bituminous-Asphaltic Sands dated as of September 1, 2018 (Mineral Lease No. 53832), executed between the State of Utah, acting by and through SITLA, as lessor, and Indago Oil and Gas, Inc., as lessee, covering approximately 898.22 acres; and

 

(c) Utah State Mineral Lease for Bituminous-Asphaltic Sands dated as of June 1, 2018 (Mineral Lease No. 53805), executed between the State of Utah, acting by and through SITLA, as lessor, and Indago Oil and Gas, Inc., as lessee, covering approximately 1,920 acres.

 

The Asphalt Ridge NW Leases cover or encompass approximately 3,458.22 acres, lands that are located in an area referred to as “Asphalt Ridge Northwest” and in close proximity to mineral leases held by Greenfield. Valkor acquired the Asphalt Ridge NW Leases under an Assignment of Oil and Gas Leases dated June 29, 2021 executed between Indago Oil and Gas Inc., as assignor, and Valkor Energy Holdings, LLC, as assignee, which was approved by SITLA on or about September 10, 2021.

 

Under the terms of the Exchange Agreement, Valkor has executed an assignment to TMC Capital of the record lease title and all of the operating rights (working interests) under the Asphalt Ridge NW Leases, and TMC Capital has in turn executed assignments transferring to Valkor all of TMC’s rights and interests in the Asphalt Ridge and SITLA Leases located in the Temple Mountain area. However, the reciprocal assignment of the SITLA Leases under the Exchange Agreement, including the assignment of the Asphalt Ridge NW Leases to TMC Capital, will not constitute final and completed transactions until the assignments have been reviewed and approved by SITLA.

 

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Following the execution of the Exchange Agreement in October 2021, TMC Capital and Valkor also entered into the following agreements:

 

(1) Under an Agreement Governing Assignment of Participation Rights in Mineral Leases, Valkor granted to TMC Capital the right to participate at up to a 50% interest in any future exploration or production operations conducted by Valkor under the Short-Term Mining Lease.

 

(2) Under an Agreement Governing Assignment of Operating Rights (SITLA Leases), TMC Capital assigned to Valkor all of the operating rights under the Asphalt Ridge NW Leases at depths of 500 feet or more below the surface, with TMC Capital reserving the right to participate at up to a 50% working interest in any exploratory or production operation conducted by Valkor at the deeper intervals. The assignment of the deeper operating rights to Valkor, subject to TMC Capital’s participation rights, is also subject to approval by SITLA.

 

The Exchange Agreement and the reciprocal assignment of mineral leases between and among TMC, POSR and Valkor will not affect the ownership of the Asphalt Ridge Plant, which will continue to be owned by Petroteq through POSR.

 

The recent transactions under the Exchange Agreement, including Valkor’s assignment of lease record title and operating rights to TMC Capital in the Asphalt Ridge NW Leases, will expand Petroteq’s oil sands resources in Utah and provide Petroteq with the following additional advantages and benefits:

 

Based on data obtained to date, we estimate that the oil content or saturation rate for the oil sands deposits existing within the lands covered by the Asphalt Ridge NW Leases at approximately 12% by weight. In contract, the oil saturation rate in the oil sands resources under the TMC Mineral Lease and the Short-Term Mining Lease in the Temple Mountain area of Asphalt Ridge has an average oil content or saturation rate of approximately 6% by weight. The difference in oil content or saturation in the oil sands deposits contained within the Asphalt Ridge NW Leases is substantial and should significantly improve the economics of our mining and processing operations as we go forward;

 

The Asphalt Ridge NW Leases contain an oil sands deposit that is contiguous within a single contained area, which will allow for greater efficiencies in our mining and transport operations. In contrast, the oil deposits contained within the original TMC Mineral Lease are contained in separate blocks running along a trend of approximately eight miles and the Temple Mountain SITLA Leases are completely undeveloped with limited exploration;

 

The Asphalt Ridge NW Leases contain substantial oil sands resources in outcroppings located near the surface (with less overburden), creating new and better surface mining prospects for Petroteq and its operating subsidiaries.

 

Asphalt Ridge NW (SITLA) Leases

 

The Asphalt Ridge NW Leases acquired by TMC Capital under the Exchange Agreement are Utah state bituminous mineral leases having a primary term of ten (10) years and an extended term thereafter for as long as (a) oil and hydrocarbon products extracted from oil sands are produced in paying quantities, or (b) the mineral lessee is otherwise engaged in diligent operations, exploration or development activity and certain other conditions are satisfied. Generally, the term of the Asphalt Ridge NW Leases may not be extended beyond the twentieth year of their effective dates except by production in paying quantities. An annual minimum royalty or rental of $10 an acre must be paid during the first ten years of the leases; from and after the 11th year of the leases, the annual minimum royalty may be adjusted by the lessor based on certain “readjustment” provisions in the leases.

 

During the development of the Exchange Agreement that resulted in Valkor’s transfer of the Asphalt Ridge NW Leases to TMC Capital, Petroteq obtained a preliminary resource evaluation report from an independent engineering firm estimating approximately 85-90 million barrels of oil in place within the oil sands deposits located within the leases.

 

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The BLM Leases

 

In April 2019, TMC acquired an undivided 50% of the operating rights under the BLM Leases, consisting of the right to explore for and produce oil from oil sands formations and deposits from the surface down to a subsurface depth of 1,000 feet. The operating rights assigned and transferred to TMC under certain of the BLM Leases also grant to TMC the right, subject to similar depth limitation, to explore for and produce oil and gas from conventional sources. Each of the BLM Leases includes lands that are located within a “Special Tar Sands Area” or “STSA”, a geographic area that has been designated by the (U.S.) Department of Interior as containing substantial deposits of oil sands.

 

The BLM Leases were originally issued by BLM under the Mineral Leasing Act of 1920 (the “MLA”). However, because the definition of “oil” in the MLA prior to 1981 did not include oil produced from oil sands, the BLM Leases (and all other federal onshore mineral leases issued prior to 1981) did not authorize the development and recovery of oil from oil sands, tar sands and bitumen-impregnated rocks and sediments. The Combined Hydrocarbon Leasing Act of 1981 (“CHL Act”) expanded the definition of “oil” to include oil produced from oil sands and bitumen deposits and authorized the issuance of new “combined hydrocarbon leases” or “CHLs” that permit exploration and production of oil and gas from both conventional sources and from oil sands deposits.

 

For federal onshore mineral leases that were in effect on November 16, 1981 (the CHL Act’s enactment date) and included lands located within an STSA, the CHL Act granted to lessees the right to convert such leases to new CHLs. Upon issuance by BLM, each CHL will constitute a new lease that will remain in effect for a primary term of ten (10) years and thereafter for as long as oil or gas is produced in paying quantities.

 

Each of the BLM Leases has been included in an application to BLM requesting their conversion to new CHLs. During the pendency of such applications, the term (and any operations) of the BLM Leases are in “suspension status” under BLM regulations until the new CHLs are issued.

 

SUMMARY OF PRODUCTION ROYALTIES

 

Technology Transfer Agreement

 

Pursuant to the terms of a technology transfer agreement dated November 7, 2011 that we entered into with Vladimir Podlipsky, the developer of Petroteq’s Clean Oil Recovery Technology, we are obligated to pay Mr. Podlipsky a royalty on production from each processing plant that we own or operate that uses the technology, starting with the construction and operation of a second plant. The royalty, if and at such time as it becomes payable, will consist of 2% of gross sales if the price of heavy oil is below $60 per barrel; 3% of gross sales if the price of heavy oil is between $60 and $69.99 per barrel; 3.5% of gross sales if the price of heavy oil is between $70 and $79.99; and 4% of gross sales if the price of heavy oil is greater than $80 per barrel.

 

TMC Mineral Lease

 

Under the TMC Mineral Lease, TMC Capital held 100% of the working interests (subject to a 1.6 % overriding royalty previously granted to Temple Mountain Energy, Inc.), with production royalties under a sliding scale starting at 8% of the gross proceeds derived from the sale or disposition of oil (including bitumen) and other hydrocarbon products produced from oil deposits within the lease.

 

In addition, TMC was required to make certain advance royalty payments to the lessor. During the period from July 1, 2018 to June 30, 2020, the minimum payments were $100,000 per quarter. The minimum payments were to increase to $150,000 per quarter beginning July 1, 2020. The TMC Mineral Lease was terminated in August 2020 and replaced with the Short-Term Mining Lease issued to Valkor and the TMC Mineral Sublease between Valkor and TMC Capital.

 

Production royalties payable under the TMC Mineral Sublease are 8% of the gross sales revenue, subject to certain adjustments.

 

Asphalt Ridge NW (SITLA) Leases

 

Under the terms of the Asphalt Ridge NW Leases, TMC Capital will be required to pay: (i) an annual rent equal to the greater of $1 an acre or a fixed sum of $500 (without regard to acreage); and (ii) a production royalty of 8% of the market price received for oil and hydrocarbon products produced from the leases at the point of first sale, less reasonable actual costs of transportation to the point of first sale. After the tenth year of the leases, SITLA (the lessor) may increase the royalty rate by as much as one percent (1%) per year up to a maximum of 12.5%, subject to a proviso that production royalties under the leases shall never be less than $3.00/bbl during the term of the leases.

 

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BLM Leases

 

Under the BLM Leases, production royalties are governed by BLM regulations and are payable to the U.S. Department of Interior at the rate of 12.5% of the amount or value of the production removed and sold. The interests acquired by TMC under the BLM Leases are also subject to a 6.25% overriding royalty reserved by predecessors-in-title.

 

PERMITS AND TAXES

 

On September 15, 2008, a large mining permit was granted to TME Asphalt Ridge, LLC by the State of Utah Division of Oil, Gas, and Mining (“UDOGM”) for the mining and development of the Asphalt Ridge Mine #1, an open pit mine located on lands included within the TMC Mineral Lease.

 

On or about July 9, 2015, UDOGM approved an application filed by TMC Capital to transfer the “Notice of Intention to Commence Large Mining Operations” for the Asphalt Ridge Mine #1 (Permit # M/047/0089) from TME Asphalt Ridge LLC to TMC Capital. On October 27, 2017, UDOGM granted final approval to TMC Capital’s “Amended Notice of Intention to Commence Large Mining Operations” and issued final Permit # M/047/0089 authorizing TMC Capital to conduct operations at Asphalt Ridge Mine #1.

 

Mining operations, including the initial development of the mine at the property and removal of a portion of the overburden soil layer, have already been performed. In addition to the mining permits, all environmental, construction, utility and other local permits necessary for the construction of the Asphalt Ridge Plant and processing oil sands ores and sediments have been granted to Petroteq’s operating subsidiaries.

 

Specifically, a Groundwater Discharge Permit was issued by the Utah Department of Environmental Quality (Division of Water Quality, Water Quality Board) (“UDEQ”), on July 26, 2016 (expiration on July 27, 2021), covering disposal of tailings from ore sands produced from the land area encompassed by the Asphalt Ridge Mine #1. This permit, required by Utah law even though our processing facility does not use a water-based process, authorizes a return of residual sand tailings to the mine for backfill and capping. A Small Source Registration air permit was issued by UDEQ by a letter dated November 2, 2018. The letter confirms that the Asphalt Ridge Plant is exempt from any requirement of additional air quality permits since the facility produces less emissions than the level that would require a special air permit. A Conditional Use Permit (“CUP”) was issued by the Uintah County (Utah) Commission to us on January 29, 2018, for the operation of the Plant. The CUP is a right/interest in land under Utah law and will continue in effect in perpetuity.

 

The oil and gas properties (including plants, equipment etc.) included in our private mineral leases are subject to the State of Utah’s property (ad valorem) tax. The actual tax rate is established by each county in the State (and therefore may vary) and is generally assessed against the “fair market value” of the property. Under Utah Code § 59-2-1103, the oil and gas properties included in the SITLA Leases are exempt from the State’s property (ad valorem) tax (although this exemption does not apply to improvements on state lands).

 

Under Utah Code § 59-5-120, beginning January 1, 2006 and ending June 30, 2026, no severance (production) tax will be imposed on oil and gas produced from oil sands (tar sands). Accordingly, severance tax will not be owed to the State of Utah on the production of oil and hydrocarbon substances from the TMC Mineral Sublease or our SITLA Leases until after June 30, 2026.

 

PETROTEQ’S PROPRIETARY EXTRACTION TECHNOLOGY

 

Petroteq intends to continue to develop its business and operations by (a) producing and marketing crude oil and hydrocarbon products (and sand byproduct) from oil sands resources under its mineral leases, or that may be acquired from third parties, through the use of Petroteq’s Clean Oil Recovery Technology, and (b) marketing its proprietary technology through licenses and other co-venture arrangements with third parties. The centerpiece of our proprietary technology consists of a patented closed loop, continuous flow, scalable and environmentally safe extraction technology and involves a process that can extract crude oil (primarily bitumen and heavy oil) and other hydrocarbon products from a wide range of oil sands deposits and other hydrocarbon sediment types. Petroteq’s oil extraction process takes place in a completely closed loop system that continuously recirculates and recycles the solvent after it has separated the bitumen and heavy oils from the oil sands. The closed loop system is capable of recovering up to 99% of all hydrocarbons from the oil sands. The only two end products that are produced through our proprietary extraction are high quality heavy oil and clean sand, making this technology environmentally benign.

 

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Petroteq’s Clean Oil Recovery Technology, which has been modified since 2015, utilizes no water in the process, is anticipated to produce minimal greenhouse gases, and is expected to extract up to 99% of all hydrocarbon content and recycle up to 95% of the solvents. The proprietary solvent composition used in the process is expected to dissolve up to 99% of heavy bitumen/asphalt and other lighter hydrocarbons from the oil sands and prevent their precipitation during the extraction process. Solvents used in this composition form an azeotropic mixture which has a low boiling point of 50 – 65 °C (degrees Celsius) and it is expected to allow recycling of over 95% of the solvent.

  

In the oil extraction and upgrade process utilized at the Asphalt Ridge Plant, the bitumen crude oil that is extracted from mined oil sands has an average API gravity of 9-12 degrees.

 

No diluents or blending agents are used to reduce the viscosity of the heavy oil extracted from bitumen saturated ores. Instead, varying amounts of solvent are introduced into an extraction tank containing raw oil sands ore that has been crushed prior to being added to the extraction tank. The solvent is designed to release the crude oil from bitumen-saturated ore during the initial extraction process.

 

The crude oil containing solvent is then introduced or subjected to a simple flash distillation process where virtually all of the solvent is recovered and recycled for future use.

 

Our oil extraction process, developed and used in the Asphalt Ridge Plant during its pilot phase, has a Feed/Bottoms heat exchanger, a Solvent Vaporizer (heat exchanger), a Solvent Scrubber (vessel), air-cooled condensers, an air-cooled product cooler, a Bitumen Product Pump, and an oil heater plus a propane tank as the energy source. The bitumen/solvent slurry is routed via a pump to the Feed/Bottoms Exchanger where it is pre-heated both to cool the exiting product as well as to integrate the heat available from the flash distillation process. This pre-heated slurry is then heated in the Solvent Vaporizer to approximately 405°F to vaporize essentially all of the solvent from the bitumen product. This two-phase stream is then flashed across a control valve and routed to the Solvent Scrubber where the gaseous solvent stream exits the vessel and is routed to air-cooled condensers where it will be liquified and returned to the storage vessel to be re-used. The resultant hot bitumen is pumped through the Feed/Bottoms exchanger via the Bitumen Product Pump and cooled prior to entering an air-cooled exchanger where it is cooled to 180°F, the temperature at which the product is stored. If it is desired that solvent be left in the bitumen for transportation purposes, the temperature of that back end flash distillation process can be controlled.

 

Petroteq has received patents in the United States, Canada and Russia that protect the claims and processes embodied in its Clean Oil Recovery Technology. See “Intellectual Property” below.

 

INTELLECTUAL PROPERTY

 

On March 27, 2013, Petroteq entered into an intellectual property license agreement in a private arm’s length transaction with TS Energy Ltd, a Canadian company, which has agreed to act as the sole and exclusive licensee of our Clean Oil Recovery Technology within Canada and the Republic of Trinidad and Tobago.

 

On July 2, 2019, Petroteq entered into an intellectual property license agreement with Valkor LLC, a company based in Katy, Texas, for the non-exclusive, non-transferable use of Petroteq’s Clean Oil Recovery Technology on a worldwide basis (subject to any exclusive license agreements in effect) in the engineering, construction and operation of oil sands plants. The agreement requires Valkor to invest (or secure investment of) a minimum of $20 million towards the construction of an oil sands plant by December 2020, and to have in production a minimum of 1,000 barrels per day. The agreement also requires Valkor to pay a one-time non-refundable license fee of $2 million per oil sands plant commissioned, with 50% payable upon start of construction and the remainder payable upon first production. The agreement further provides that Valkor will pay a five percent (5%) royalty based on annual gross sales for so long as the licensed technology is covered by a valid claim in the country in which it is used.

 

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We rely upon patents to protect our intellectual property. We have obtained patents in the United States, Canada and Russia that protect our Clean Oil Recovery Technology. The following sets forth details of our issued patents.

 

DOCKET   TITLE   COUNTRY  

DATE FILED

SERIAL NO.

 

DATE ISSUED

PATENT NO./STATUS

1492.2   Oil From Oil Sands
Extraction Process
  USA   09/26/12
13/627,518
-----------------------
10/07/11
61/545,034
  02/06/18
9,884,997
Expires: 10/07/31

 

Summary: A system for extracting bitumen from oil sands includes an extractor tank which incorporates a plurality of jet injectors. Operationally, the jet injectors provide jet streams of an extractant in the extractor tank that creates a fluidized bed of the extractant. A reaction between crushed oil sands and the fluidized bed then separates bitumen from the oil sands.

 

Corresponding Foreign Patent Properties

 

DOCKET   TITLE   COUNTRY  

DATE FILED

SERIAL NO.

 

DATE ISSUED

PATENT NO./STATUS

11492.2a   Oil Extraction Process   Canada   09/30/11 2,754,355   Received Notice of Allowance; patent payment submitted to Commission of Patents
                 
11492.2d   Oil From Oil Sands Extraction Process   Russia   04/28/14 2014117162   12/20/15 2571827 Expires: 09/27/2032

 

THE OIL SANDS MARKET

  

As an unconventional hydrocarbon resource, oil sands hold hundreds of billions of barrels of oil on a worldwide basis. Although Canada is the only country that is currently extracting large quantities of oil from its oil sands deposits, the United States also has large oil sands resources that can be developed. In a 2007 Report entitled “A Technical, Economic, and Legal Assessment of North American Oil Shale, Oil Sands, and Heavy Oil Resources In Response to Energy Policy Act of 2005 Section 369(p)” (September 2007), prepared by the Utah Heavy Oil Program, Institute For Clean and Secure Energy and The University of Utah for the U.S. Department of Energy (the “2007 Report”), the authors reported the following estimates, which estimates were based upon source material published in 1979, 1987 and 1993:

 

  The United States has an estimated 76 billion barrels of oil-in-place (“OIP”) (OIP are not estimates of reserves or recoverable resources) from bitumen and heavy oil contained in oil sands resources;

  

  In the United States, Utah is known to have the largest oil sands deposits, with total resource estimates ranging from 23 to 32 billion barrels of OIP from bitumen and heavy oil contained in oil sands formations and deposits; and

 

  Within the state of Utah, the region that has experienced the most oil sands development, both in terms of existing oil production and supporting infrastructure, is the Asphalt Ridge area located on the northern edge of the Uintah Basin in eastern Utah. In the 2007 Report, it is estimated that about one (1) billion barrels of OIP exist in the form of bitumen and heavy oil contained in oil sands formations and deposits in the Asphalt Ridge area.

 

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From our own investigation of the oil sands deposits in the Asphalt Ridge area of Utah, we believe that a substantial part of the oil sands deposits in this area are accessible through outcroppings or in shallow depths with limited or no overburden. In our view, the location and accessibility of oil sands deposits in Asphalt Ridge create an opportunity for commercial development, supported by positive economics, using surface mining techniques and our extraction technology.

 

The worldwide growing demand for heavy crude oil and the recent decline in heavy crude oil production in countries such as Venezuela makes the high quality, low Sulphur, heavy oil found in oil sands deposits in the United States a valuable resource that has been underdeveloped to date. The development of “tight shale” oil plays in the United States has produced significant quantities of light, sweet crude oil reserves, but heavy oil development in the United States has lagged. To date, oil sands development has been limited by the absence of a viable technology that can extract heavy oil and bitumen from the oil sands deposits in an economical and environmentally responsible manner. To that end, Petroteq has developed and patented an extraction technology that aims to develop oil sands reserves in an economical and environmentally responsible manner. Petroteq is currently expanding its commercial oil sands extraction operations in the Asphalt Ridge area, utilizing a process that is economical, environmentally benign and produces high quality heavy oil.

  

We have tested our Clean Oil Recovery Technology from oil sands sourced from both the Asphalt Ridge area of Utah and from different parts of the world that have different hydrocarbon chemical compositions. To date, we have conducted tests with oil sands from Russia, China, Indonesia and the Middle East. Our tests with Russian oil sands, which were the only tests of our Extraction Technology with oil sands from different parts of the world that were conducted by third parties, were conducted in Ufa, Bashkorkostan (Russia) by a third party (KVADRA) retained by us to perform the tests using a multi-ton pilot plant, used the local oil sands ore with oil saturation in a range of 7-10%, and resulted in industrial quantities of heavy oil. From the tests conducted in Ufa, an average of 70 metric tons of raw oil sands material were processed per day resulting in 5,475 kg of heavy asphaltenic oil per day. Other tests, consisting of oil sands samples from China, Indonesia and Jordan, were conducted internally at Petroteq’s laboratory in San Diego using lab bench testing with our own solvent blend that produced approximately one to two pound quantities. By introducing the solvent mixture to crushed and treated ore containing bitumen oil, the oil was separated by recycling the solvent with a laboratory-scale rotor vacuum evaporator. Sand tailings were separated by centrifuge and dried under the vacuum.

 

Through our testing of oil sands sourced from different countries, we found that the efficiency and consistency of Petroteq’s extraction technology are not affected by differences in the chemical composition of the oil/bitumen in the oil sands. Despite relatively significant differences in oil/bitumen chemistry, both the efficiency and consistency of our extraction technology remained intact, resulting in an oil recovery efficiency that in each test exceeded 99%. We believe that this testing demonstrates that the Extraction Process is universal in its application and does not depend on the material source or the hydrocarbon content or fingerprint.

 

REGULATION

 

Exploration and production operations are subject to various types of regulation at the federal, state and local levels. This regulation includes requiring permits to drill wells, maintaining bonding requirements to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties on which wells are drilled, and the plugging and abandoning of wells. Full mining permits have been granted to POR from the State of Utah Division of Oil, Gas, and Mining for the mining and development of the Asphalt Ridge Mine #1 located in the Asphalt Ridge area of Utah. In addition to the mining permits, all environmental, construction, utility and other local permits necessary for the construction of the plant and the processing of the oil sands have been granted to POR. Our operations are also subject to various conservation laws and regulations.

 

Typically, oil enhancements such as hydraulic fracturing operations are overseen by state regulators as part of their oil and gas regulatory programs; however, the (U.S.) Environmental Protection Agency (“EPA”) has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the Safe Drinking Water Act and has released draft permitting guidance for hydraulic fracturing activities that use diesel in fracturing fluids in those states where EPA is the permitting authority. As a result, we may be subject to additional permitting requirements for our operations. These permitting requirements and restrictions could result in delays in operations at well sites as well as increased costs to make wells productive. In addition, legislation introduced in Congress provides for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and requires the public disclosure of certain information regarding the chemical makeup of hydraulic fracturing fluids. Moreover, on November 23, 2011, the EPA announced that it was granting in part a petition to initiate a rulemaking under the Toxic Substances Control Act, relating to chemical substances and mixtures used in oil and gas exploration and production. Further, on May 4, 2012, the BLM issued a proposed rule to regulate hydraulic fracturing on public and Indian land.

 

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On August 16, 2012, the EPA published final rules that establish new air emission control requirements for natural gas and NGL production, processing and transportation activities, including New Source Performance Standards to address emissions of sulphur dioxide and volatile organic compounds, and National Emission Standards for Hazardous Air Pollutants (NESHAP) to address hazardous air pollutants frequently associated with gas production and processing activities. Among other things, these final rules require the reduction of volatile organic compound emissions from natural gas wells through the use of reduced emission completions or “green completions” on all hydraulically fractured wells constructed or refractured after January 1, 2015. In addition, gas wells are required to use completion combustion device equipment (e.g., flaring) by October 15, 2012 if emissions cannot be directed to a gathering line. Further, the final rules under NESHAP include maximum achievable control technology (MACT) standards for “small” glycol dehydrators that are located at major sources of hazardous air pollutants and modifications to the leak detection standards for valves. Compliance with these requirements, especially the imposition of these green completion requirements, may require modifications to certain of our operations, including the installation of new equipment to control emissions at the well site that could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

 

In addition to these federal legislative and regulatory proposals, some states such as Pennsylvania, West Virginia, Texas, Kansas, Louisiana and Montana, and certain local governments have adopted, and others are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances, including requirements regarding chemical disclosure, casing and cementing of wells, withdrawal of water for use in high-volume hydraulic fracturing of horizontal wells, baseline testing of nearby water wells, and restrictions on the type of additives that may be used in hydraulic fracturing operations. For example, the Railroad Commission of Texas adopted rules in December 2011 requiring disclosure of certain information regarding the components used in the hydraulic fracturing process. In addition, Pennsylvania’s Act 13 of 2012 became law on February 14, 2012 and amended the state’s Oil and Gas Act to impose an impact fee for drilling, increase setbacks from certain water sources, require water management plans, increase civil penalties, strengthen the Pennsylvania Department of Environmental Protection’s (PaDEP) authority over the issuance of drilling permits, and require the disclosure of chemical information regarding the components in hydraulic fracturing fluids.

 

We believe that the technologies we use are cleaner and environmentally friendlier than the known fracking or tar sand technologies. Regulatory and social resistance sometimes prohibits fracking recovery methods in some states.

  

OSHA and Other Laws and Regulations.

 

We are subject to the requirements of the federal Occupational Safety and Health Act (OSHA), and comparable state laws. The OSHA hazard communication standard, the EPA community right-to-know regulations under the Title III of CERCLA and similar state laws require that we organize and/or disclose information about hazardous materials used or produced in our operations. Also, pursuant to OSHA, the Occupational Safety and Health Administration has established a variety of standards related to workplace exposure to hazardous substances and employee health and safety.

 

Oil Pollution Act.

 

The Federal Oil Pollution Act of 1990 (“OPA”) and resulting regulations impose a variety of obligations on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills in waters of the United States. The term “waters of the United States” has been broadly defined to include inland water bodies, including wetlands and intermittent streams. The OPA assigns joint and several strict liability to each responsible party for oil removal costs and a variety of public and private damages. We believe that we are in compliance with the OPA and the federal regulations promulgated thereunder in the conduct of our operations.

 

Clean Water Act.

 

The Federal Water Pollution Control Act (Clean Water Act) and resulting regulations, which are primarily implemented through a system of permits, also govern the discharge of certain contaminants into waters of the United States. Sanctions for failure to comply strictly with the Clean Water Act are generally resolved by payment of fines and correction of any identified deficiencies. However, regulatory agencies could require us to cease construction or operation of certain facilities or to cease hauling wastewaters to facilities owned by others that are the source of water discharges. We believe that we substantially comply with the Clean Water Act and related federal and state regulations.

 

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COMPETITION

 

Competition in the oil industry is intense. We compete with other companies seeking to acquire sub economic oil fields, many with substantial financial and other resources. We will also compete with technologies such as gas injection, polymer flooding, microbial injection and thermal methods. As a new technology, we also compete with many of the other technologies that have been proven to be economically successful in enhancing oil production in the United States. As a result of this competition, we may be unable to attract the necessary funding or qualified personnel. If we are unable to successfully compete for funding or for qualified personnel, our activities may be slowed, suspended or terminated, any of which would have a material adverse effect on our ability to continue operations. However due to the innovative nature of our technology and the ecological benefit it provides, while remaining economically efficient, we believe that competition will not be a significant impediment to our operations or expansion.

 

IMPLICATIONS OF BEING AN EMERGING GROWTH COMPANY

 

We are an “emerging growth company,” as defined in the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”), and therefore we intend to take advantage of certain exemptions from various public company reporting requirements, including not being required to have our internal controls over financial reporting audited by our independent registered public accounting firm pursuant to Section 404 of the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”) even if we cease to be a smaller reporting company with annual revenues of less than $100 million, reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements and exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and any golden parachute payments. We may take advantage of these exemptions until we are no longer an “emerging growth company.” In addition, the JOBS Act provides that an “emerging growth company” can delay adopting new or revised accounting standards until such time as those standards apply to private companies. We have elected to use the extended transition period for complying with new or revised accounting standards under the JOBS Act. This election allows us to delay the adoption of new or revised accounting standards that have different effective dates for public and private companies until those standards apply to private companies. As a result of this election, our financial statements may not be comparable to companies that comply with public company effective dates.

 

We will remain an “emerging growth company” until the earlier of (1) the last day of the fiscal year: (a) following the fifth anniversary of the date of the first sale of our common shares pursuant to an effective registration statement filed under the Securities Act; (b) in which we have total annual gross revenue of at least $1.07 billion; or (c) in which we are deemed to be a large accelerated filer, which generally means the market value of our common shares that is held by non-affiliates exceeded $700.0 million as of the last business day of our most recently completed second fiscal quarter, and (2) the date on which we have issued more than $1.0 billion in non-convertible debt during the prior three-year period. References herein to “emerging growth company” have the meaning associated with that term in the JOBS Act.

 

ENFORCEABILITY OF CIVIL LIABILITIES

 

We are a company incorporated in Ontario, Canada. Certain of our directors and officers named in this registration statement reside outside the U.S. In addition, some of our assets and the assets of our directors and officers are located outside of the United States. As a result, it may be difficult for investors who reside in the United States to effect service of process upon these persons in the United States. You may also have difficulty enforcing, both in and outside the United States, judgments you may obtain in U.S. courts against us or these persons in any action, including actions based upon the civil liability provisions of U.S. federal or state securities laws.

 

Furthermore, there is substantial doubt whether an action could be brought in Canada in the first instance predicated solely upon U.S. federal securities laws. Canadian courts may refuse to hear a claim based on an alleged violation of U.S. securities laws against us or these persons on the grounds that Canada is not the most appropriate forum in which to bring such a claim. Even if a Canadian court agrees to hear a claim, it may determine that Canadian law and not U.S. law is applicable to the claim. If U.S. law is found to be applicable, the content of applicable U.S. law must be proved as a fact, which can be a time-consuming and costly process. Certain matters of procedure will also be governed by Canadian law.

 

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History and Development of the Company

 

We were incorporated as “AXEA Capital Corp.” on January 4, 2008 pursuant to the Business Corporations Act (British Columbia). On October 15, 2012, MCW Energy Group Limited (“MCW NB”), a corporation incorporated in the Province of New Brunswick, completed a reverse acquisition of AXEA Capital Corp. (the “RTO”) and as a result MCW NB became a wholly owned subsidiary of AXEA Capital Corp. which also changed its name from “AXEA Capital Corp.” to “MCW Enterprises Ltd.” Pursuant to articles of continuance filed on December 7, 2012, MCW NB changed its jurisdiction of governance by continuing from the Province of New Brunswick into the Province of Ontario. Pursuant to articles of continuance filed on December 12, 2012, MCW Enterprises Ltd. changed its jurisdiction of governance by continuing from the Province of British Columbia into the Province of Ontario and changed its name to MCW Enterprises Continuance Ltd. Pursuant to a certificate of amalgamation dated December 12, 2012, MCW Enterprises Continuance Ltd. and MCW NB amalgamated in the Province of Ontario and continued under the name “MCW Energy Group Limited”.

 

We are governed by the Business Corporations Act (Ontario) and our registered office is located at Suite 6000, 1 First Canadian Place, PO Box 367, 100 King Street West, Toronto, Ontario M5X 1E2, Canada. Our executive office is located at 15315 W. Magnolia Blvd., Suite 120, Sherman Oaks, California 91403. Our telephone number is (866) 571-9613.

 

Our common shares are listed on the TSX Venture Exchange (the “TSXV”) under the trading symbol “PQE” but currently suspended from trading, the Frankfurt Exchange under the trading symbol PQCF.F and on the OTC Pink under the trading symbol “PQEFF”.

 

Pursuant to articles of amendment filed on May 5, 2017, we changed our name from “MCW Energy Group Limited” to “Petroteq Energy Inc.” and we changed our TSXV trading symbol from MCW to PQE. On June 2, 2017, our OTCQX trading symbol was changed from MCW to PQEFF. Since March 15, 2018, our stock has traded on the OTC Pink market when it no longer traded on the OTCQX International Market.

 

On May 5, 2017, we effected a share consolidation (reverse stock split) on a 1-for-30 basis. Unless otherwise included, all shares amounts and per share amounts in this registration statement have been prepared on a pro forma basis to reflect the 1-for-30 reverse stock split of our outstanding common shares. On November 23, 2018, our shareholders approved a resolution authorizing our Board of Directors to consolidate our shares on a basis of up to ten for one. No consolidation has been effected to date.

 

We determined that the Company ceased to qualify as a foreign private issuer (as defined in Rule 405 under the Securities Act of 1933, as amended, and Rule 3b-4 under the Securities Exchange Act of 1934, as amended) as of February 28, 2019 (being the last business day of the second fiscal quarter of the fiscal year ended August 31, 2019), and therefore ceased to be eligible to rely on the rules and forms available to foreign private issuers on August 31, 2019.

 

Additional information related to our company may be found on our website at www.petroteq.energy. Information contained in our website does not form part of the registration statement and is intended for informational purposes only.

 

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RECENT DEVELOPMENTS

 

Suspension of trading on the TSX Venture Exchange (“TSXV”)

 

The Company is under a cease trade order invoked by the TSXV on August 6, 2021.

 

The Company filed the 2021 Q3 Filings on SEDAR and with the United States Securities and Exchange Commission (the “SEC”) on August 19, 2021. In addition, on August 19, 2021, the Company’s amended financial statements and management’s discussion and analysis ‎for the eight quarters from May 31, 2019 to February 28, 2021 were filed on SEDAR and with the SEC, as contained in the Company’s amended annual reports on Form 10-K/A for the financial years ended August 31, 2019 and August 31, 2020, and in the Company’s amended quarterly reports on Form 10-Q/A for the periods ended May 31, 2019, November 30, 2019, February 29, 2020, May 31, 2020, November 30, 2020 and February 28, 2021. The Company’s amended financial statements and management discussion and analysis for the period ended February 28, 2019 were filed on SEDAR on August 23, 2021, and with the SEC on August 25, 2021, as exhibits to the Company’s current report on Form 8-K.

 

As a result of the issuance of the TSXV Cease Trade Order (“CTO”) on August 6, 2021, the Exchange suspended trading of the Company’s Common Shares. As part of the Exchange’s review of the Company’s reinstatement application, the Exchange reviewed the Company’s financial statements for the three and nine months ended May 31, 2021 and raised concerns over unapproved filings. As a result of an internal investigation the Company identified several transactions (“Transactions”) reported in SEDAR (“Canada”) and EDGAR (“United States”) that had not been submitted for approval by the Toronto Stock Exchange.

 

Based on the Company’s initial review of the Transactions, it is estimated that a total of 54,370,814 Common Shares were issued as a result of the Transactions.‎ While some of the issued Common Shares, namely, 4,336,972, are estimated to have been issued at prices above what the Exchange ‎would have otherwise approved, 50,033,842 are estimated to have been issued at share prices below what the Exchange ‎generally approves for convertible securities.‎ While the Company is now making the necessary submissions to the Exchange for the Transactions, they may not all be accepted for approval by the Exchange and as a condition to reinstatement of trading on the Exchange the Company may need to take remedial action to ensure that Transactions are in compliance with the Exchange.

 

The net proceeds of the Transactions that resulted in new funds to the Company were used for expansion of the Company’s oil sands processing plant in Utah and for working capital.‎

 

The Company continues to work with the Exchange on a reinstatement of trading and will update the market as developments warrant. However, the Exchange has indicated that these matters and their review of the Transactions may take some time to resolve and that a reinstatement to trading is not expected in the near term.

 

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Unsolicited takeover bid by Viston United Swiss AG

 

On October 27, 2021, 2869889 Ontario Inc., an indirect, wholly-owned subsidiary of Viston United Swiss AG commenced a conditional, unsolicited takeover bid (the “Offer”) to acquire all of the issued and outstanding Common Shares of the Company. Viston filed a Tender Offer Statement with the SEC relating to the Offer on Schedule TO under section 14(d)(1) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), on October 25, 2021, and an amendment to the Tender Offer Statement on October 27, 2021. As set forth in the Solicitation/Recommendation Statement on Schedule 14D-9 under section 14(d)(4) of the Exchange Act filed with the SEC on November 9, 2021, shareholders were advised that the Board of Directors was not yet in a position to make a recommendation to shareholders to accept or reject the Offer, and that the Company has retained Haywood Securities Inc. as financial advisor to the Company and the Board of Directors.

 

Exchange of mineral leases

 

Under the terms of an agreement dated October 15, 2021 between Petroteq Oil Recovery, LLC and TMC Capital, LLC, two of the Company’s U.S. subsidiaries, and Valkor Energy, LLC (the “Exchange Agreement”), Petroteq Oil and TMC Capital agreed to assign to Valkor all of their respective rights and interests in the TMC Mineral Lease located near Temple Mountain in the Asphalt Ridge area of Uintah County, Utah, including interests under a sublease to a Short-Term Mining Lease obtained by Valkor in August 2020, and in three Utah state oil sands leases that are contiguous to or in close proximity to the lands encompassed by the TMC Mineral Lease.

 

In a separate agreement, Valkor granted to provide TMC Capital the right to participate, at up to a 50% working interest, in any future operations conducted by Valkor under the TMC Mineral Lease or the Short-Term Mining Lease held by Valkor covering acreage formerly included in the TMC Mineral Lease, or on any of the lands covered by either of the leases.

 

To complete the exchange under the Exchange Agreement, Valkor agreed to assign to TMC Capital all of its rights and interests in three Utah state oil sands leases located in Uintah County, Utah, in an area referred to as Asphalt Ridge Northwest (the “Asphalt Ridge NW Leases”), including the “record lease title” and all of the operating rights (i.e. working interests) under the leases.

 

In a separate agreement, TMC Capital agreed to assign to Valkor the operating rights under the three Asphalt Ridge NW Leases at subsurface depths below 500 feet, with TMC Capital retaining a right to participate, at up to a 50% working interest, in any operation conducted by Valkor at the deeper intervals.  Under this agreement, each party will have the right to participate, at up to a 50% joint ownership basis, in any new oil sands processing plant constructed on lands covered by the Asphalt Ridge NW Leases.

 

As of October 28, 2021, each of the agreements and assignments required to consummate the reciprocal assignment of leases between the Company’s subsidiaries and Valkor has been executed and all of the transactions have been tentatively completed, subject to the approvals that must be obtained from the State of Utah’s School and Institutional Trust Lands Administration (SITLA). 

  

The exchange of mineral properties between the Company’s subsidiaries and Valkor - resulting in the Company’s acquisition of record title and all interests under the Asphalt Ridge NW Leases - creates substantial benefits and opportunities for the Company, including:

 

  (a) The Asphalt Ridge NW leases contain an oil sands deposit that is contiguous within a single contained area. This will allow for greater efficiencies in mining and in ore transport operations. By contrast, the original TMC Mineral Lease in the Temple Mountain area of Asphalt Ridge encompasses three separate deposits running along a trend over about 8 miles, a structural outlay requiring substantial development and transport costs.
     
  (b) Based on historical well data from deposits adjacent to and surrounding the Asphalt Ridge NW Leases, the oil content or saturation in the deposit of oil sands within the Asphalt Ridge NW Leases is expected to average in the range of 12% by weight. In contrast, the oil sands ores mined or produced from lands within the TMC Mineral Lease in the Temple Mountain area have an average oil content or saturation in the range of 6% by weight. The higher oil content in the oil sands deposit located within the Asphalt NW Leases should provide for better yields per ton of bulk oil sand processed and improved project economics for a 5,000 barrel per day commercial plant that is being considered by the Company in this area.
     
  (c) Because a substantial part of the oil sands deposit within the Asphalt Ridge NW Leases is close to the surface and extends into various outcroppings, extraction and production may be conducted by surface mining where  less overburden will need to be removed before initiating mining operations.

  

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ITEM 1A. RISK FACTORS.

 

The following risks relate specifically to our business and should be considered carefully. Our business, financial condition and results of operations could be harmed by any of the following risks. As a result, the trading price of our common shares could decline and the holders could lose part or all of their investment.

 

We face business disruption and related risks resulting from the recent outbreak of the novel coronavirus 2019 (“COVID-19”), which could have a material adverse effect on our business and results of operations.

 

In an effort to contain and mitigate the spread of COVID-19, many countries, including the United States and Canada, have imposed restrictions on travel, and there have been business closures and a substantial reduction in economic activity in countries that have had significant outbreaks of COVID-19. The pandemic has had a material adverse effect on our operations.

 

Significant uncertainty remains as to the potential impact of the COVID-19 pandemic on our operations, and on the global economy as a whole. Government-imposed restrictions on travel and other “social-distancing” measures such restrictions on assembly of groups of persons, have the potential to disrupt supply chains for parts and sales channels for our products, and may result in labor shortages.

 

It is currently not possible to predict how long the pandemic will last or the time that it will take for economic activity to return to prior levels. We will continue to monitor the COVID-19 situation closely, and intend to follow health and safety guidelines as they evolve.

 

We expect the ultimate significance of the impact of these disruptions, including the extent of their adverse impact on our financial and operational results, will be dictated by the length of time that such disruptions continue, which will, in turn, depend on the currently unknowable duration of the COVID-19 pandemic and the impact of governmental regulations that might be imposed in response. Our business could also be impacted should the disruptions from COVID-19 lead to changes in commercial behavior. The COVID-19 impact on the capital markets could impact our cost of borrowing. There are certain limitations on our ability to mitigate the adverse financial impact of these items, including the fixed costs of our operations. COVID-19 also makes it more challenging for management to estimate future performance of our businesses, particularly over the near to medium term.

 

We have a limited operating history, and may not be successful in developing profitable business operations.

 

Our oil extraction segment has a limited operating history. We have generated limited revenue from our oil sands mining and processing activities, and do not anticipate generating any significant revenue from these activities until our Asphalt Ridge processing facility is fully operational. Even once we are fully operational, our business operations must be considered in light of the risks, expenses and difficulties frequently encountered in establishing a business in the oil extraction business. 

 

We have an insufficient history at this time on which to base an assumption that our oil sands mining and processing operations will prove to be successful in the long-term.  Our future operating results will depend on many factors, including:

 

  our ability to raise adequate working capital;

 

  the success of our development and exploration;

 

  the demand for oil;

 

  the level of our competition;

 

  our ability to attract and maintain key management and employees; and

 

  our ability to efficiently explore, develop, produce or acquire sufficient quantities of marketable gas or oil in a highly competitive and speculative environment while maintaining quality and controlling costs.

 

To achieve profitable operations in the future, we must, alone or with others, successfully manage the factors stated above, as well as continue to develop ways to enhance or increase the efficiency of our mining and processing operations that are being conducted in the Asphalt Ridge area in eastern Utah.  Despite our best efforts, we may not be successful in our exploration or development efforts or obtain the regulatory approvals required to conduct our operations.  

 

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We have suffered operating losses since inception and we may not be able to achieve profitability.

 

At August 31, 2021, August 31, 2020 and August 31, 2019, we had an accumulated deficit of $(100,138,592), $(90,664,349), and $(78,285,282), respectively and we expect to continue to incur increasing expenses in the foreseeable future as we develop our oil extraction business. We incurred a net loss of $(9,474,243) and ($12,379,067) for the years ended August 31, 2021 and August 31, 2020, respectively.  As a result, we are sustaining substantial operating and net losses, and it is possible that we will never be able to develop or sustain the revenue levels necessary to attain profitability.

 

Our ability to be profitable will depend in part upon our ability to manage our operating costs and to generate revenue from our extraction operations. Operating costs could be impacted by inflationary pressures on labor, volatile pricing for natural gas used as an energy source in transportation of fuel and in oil sands processes, and planned and unplanned maintenance.

 

We have concluded that certain of our previously issued financial statements should not be relied upon and have restated certain of our previously issued financial statements which was time-consuming and expensive and could expose us to additional risks that could have a negative effect on our Company.

 

We had concluded that certain of our previously issued financial statements should not be relied upon. We have restated our previously issued audited consolidated financial statements and related note disclosures as of and for the year ended August 31, 2020 and 2019. We do not intend to restate our unaudited condensed consolidated financial statements and related note disclosures as of and for the three and six months ended February 28, 2019 and 2018 which were included in our initial registration statement on Form 10 originally filed with the SEC on May 22, 2019, and amended by Amendment No. 1 thereto filed with the SEC on June 24, 2019 and by Amendment No. 2 thereto filed with the SEC on July 5, 2019, and such unaudited condensed consolidated financial statements and related note disclosures should not be relied on. The restatement process was time consuming and expensive and, along with the failure to file our quarterly report on Form 10-Q for the period ended May 31, 2021 with the SEC in a timely manner, could expose us to additional risks that could have a negative effect on our Company. In particular, we incurred substantial unanticipated expenses and costs, including audit, legal and other professional fees, in connection with the restatement of our previously issued financial statements. Our management’s attention was also diverted from some aspects of the operation of our business in connection with the restatement.

 

The restatement of our financial statements may in the future lead to, among other things, future stockholder litigation, loss of investor confidence, negative impacts on our stock price and certain other risks.

 

There can be no assurance that litigation against the Company and/or its management or Board of Directors might not be threatened or brought in connection with matters related to our restatements. As a result of the circumstances giving rise to the restatements, we have become subject to certain additional risks and uncertainties, including unanticipated costs for accounting and legal fees in connection with or related to the restatements, potential stockholder litigation, government investigations, and potential claims by Redline Capital Management S.A. as described under Part I, Item 3. - Legal Proceedings. Any such proceeding could result in substantial defense costs regardless of the outcome of the litigation or investigation. If we do not prevail in any such litigation, we could be required to pay substantial damages or settlement costs. In addition, the restatements and related matters could impair our reputation and could cause our counterparties to lose confidence in us. Each of these occurrences could have an adverse effect on our business, results of operations, financial condition and stock price.

 

We expect that our revenues will be limited until our Asphalt Ridge processing facility has become fully operational and we are at full production.

 

The losses from continuing operations over the past four fiscal years have been largely due to the relocation, reassembly and expansion or our processing facility, and we have faced additional challenges with the onset of the COVID-19 pandemic. As described elsewhere in this Annual Report, the relocation of our Asphalt Ridge processing facility from its original site near Maeser, Utah, to its present site on the TMC Mineral Lease in 2017 occurred during a temporary suspension of our oil sands mining and processing operations that we had initiated in 2016 in the face of a sharp decline in world oil prices, and our resulting inability to operate profitably at low volumes of output. We restarted operations at the end of May 2018, and completed expansion work on the processing facility to increase production during the last quarter of fiscal 2019. We had expected to generate revenue from the sale of hydrocarbon products commencing in the third quarter ended May 31, 2020. However, due to the COVID-19 pandemic, we had suspended production of hydrocarbon products. Even once we resume production, we anticipate that our revenue will be limited until we are at full production. We expect that we will require additional capital to continue our operations and planned growth.

 

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The failure to comply with the terms of our secured notes could result in a default under the terms of the note and, if uncured, it could potentially result in action against the pledged assets.

 

As of August 31, 2021, we had issued and outstanding convertible notes in the principal amount of $10,126,246 to certain private investors which mature between September 1, 2021 and July 21, 2025 and are secured by a pledge of all of our assets.  If we fail to comply with the terms of the notes, the note holder could declare a default under the notes and if the default were to remain uncured, as secured creditors they would have the right to proceed against the collateral secured by the loans. Any action by secured creditors to proceed against our assets would likely have a serious disruptive effect on our operations.

 

We have limited capital and will need to raise additional capital in the future.

 

We do not currently have sufficient capital to fund both our continuing operations and our planned growth. We will require additional capital to meet the terms of the TMC Mineral Lease and to continue to grow our business via acquisitions and to further expand our exploration and development programs. We may be unable to obtain additional capital when required. Future acquisitions and future exploration, development, processing and marketing activities, as well as our administrative requirements (such as salaries, insurance expenses and general overhead expenses, as well as legal compliance costs and accounting expenses) will require a substantial amount of additional capital and cash flows.

 

We may pursue sources of additional capital through various financing transactions or arrangements, including joint venturing of projects, debt financing, equity financing or other means. We may not be successful in identifying suitable financing transactions in the time period required or at all, and we may not obtain the capital we require by other means. If we do not succeed in raising additional capital, our resources may not be sufficient to fund our planned operations and may force us to curtail operations or cancel planned projects.

 

Our ability to obtain financing, if and when necessary, may be impaired by such factors as the capital markets (both generally and in the oil and gas industry in particular), our limited operating history, the location of our oil and gas properties and prices of oil and gas on the commodities markets (which will impact the amount of asset-based financing available to us, if any) and the departure of key employees.  Further, if oil or gas prices on the commodities markets decline, our future revenues, if any, will likely decrease and such decreased revenues may increase our requirements for capital.  If the amount of capital we are able to raise from financing activities, together with our revenues from operations, is not sufficient to satisfy our capital needs (even to the extent that we reduce our operations), we may be required to cease our operations, divest our assets at unattractive prices or obtain financing on unattractive terms.

  

Any additional capital raised through the sale of equity may dilute the ownership percentage of our shareholders.  Raising any such capital could also result in a decrease in the fair market value of our equity securities because our assets would be owned by a larger pool of outstanding equity.  The terms of securities we issue in future capital transactions may be more favorable to our new investors, and may include preferences, superior voting rights and the issuance of other derivative securities, and issuances of incentive awards under equity employee incentive plans, which may have a further dilutive effect.

 

Any additional debt financing may include conditions that would restrict our freedom to operate our business, such as conditions that:

 

  increase our vulnerability to general adverse economic and industry conditions;

 

  require us to dedicate a portion of our cash flow from operations to payments on our debt, thereby reducing the availability of our cash flow to fund capital expenditures, working capital, growth and other general corporate purposes; and

 

  limit our flexibility in planning for, or reacting to, changes in our business and our industry.

 

The incurrence of additional indebtedness could require acceptance of covenants that, if violated, could further restrict our operations or lead to acceleration of the indebtedness that would necessitate winding up or liquidation of our company. In addition to the foregoing, our ability to obtain additional debt financing may be limited and there can be no assurance that we will be able to obtain any additional financing on terms that are acceptable, or at all.

 

We may incur substantial costs in pursuing future capital financing, including investment banking fees, legal fees, accounting fees, securities law compliance fees, printing and distribution expenses and other costs.  We may also be required to recognize non-cash expenses in connection with certain securities we may issue, which may adversely impact our financial condition.

 

23

 

 

There is substantial doubt about our ability to continue as a going concern.

 

At August 31, 2021, we had not yet achieved profitable operations, had accumulated losses of $(100,138,592) since our inception and a working capital deficit of $(6,264,427) and expect to incur further losses in the development of our business, all of which casts substantial doubt about our ability to continue as a going concern. We have incurred net losses for the past five years. As at August 31, 2020 and August 31, 2019, we had an accumulated deficit of $(90,664,349) and $(78,285,282), respectively and a working capital deficit of $(12,955,134) and $(9,268,763), respectively. The opinion of our independent registered accounting firm on our audited financial statements for the years ended August 31, 2021 and 2020 draws attention to our notes to the financial statements, which describes certain material uncertainties regarding our ability to continue as a going concern. Our ability to continue as a going concern is dependent upon our ability to generate future profitable operations and/or to obtain the necessary financing to meet our obligations and repay our liabilities arising from normal business operations when they come due. Management’s plan to address our ability to continue as a going concern includes (1) obtaining debt or equity funding from private placement or institutional sources, (2) obtaining loans from financial institutions, where possible, or (3) participating in joint venture transactions with third parties. Although management believes that it will be able to obtain the necessary funding to allow us to remain a going concern through the methods discussed above, there can be no assurances that such methods will prove successful. The accompanying financial statements do not include any adjustments that might result from the outcome of this uncertainty.

 

Strategic relationships upon which we may rely are subject to change, which may diminish our ability to conduct our operations.

 

Our ability to successfully acquire oil and gas interests, to establish reserves, and to identify and enter into commercial arrangements with customers will depend on developing and maintaining close working relationships with industry participants and our ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment. These realities are subject to change and our inability to maintain close working relationships with industry participants or continue to acquire suitable property may impair our ability to execute our business plan.

 

To continue to develop our business, we will endeavor to use the business relationships of our management to enter into strategic relationships, which may take the form of joint ventures with other private parties and contractual arrangements with other oil and gas companies, including those that supply equipment and other resources that we will use in our business. We may not be able to establish these strategic relationships or, if established, we may not be able to maintain them.  In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to in order to fulfill our obligations to these partners or maintain our relationships.  If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations.

  

We may not be able to successfully manage our growth, which could lead to our inability to implement our business plan.

 

Our growth is expected to place a significant strain on our managerial, operational and financial resources, especially considering that we currently only have a small number of executive officers, employees and advisors. Further, as we enter into additional contracts, we will be required to manage multiple relationships with various consultants, businesses and other third parties. In addition, once we commence operations at our oil extraction facility, our strain on management will further increase. These requirements will be exacerbated in the event of our further growth or in the event that the number of our drilling and/or extraction operations increases. There can be no assurance that our systems, procedures and/or controls will be adequate to support our operations or that our management will be able to achieve the rapid execution necessary to successfully implement our business plan. If we are unable to manage our growth effectively, our business results of operations and financial condition will be adversely affected, which could lead to us being forced to abandon or curtail our business plan and operations.

 

24

 

 

Our operations are dependent upon us maintaining access to mineral leases.

 

TMC, one of our wholly owned operating subsidiaries, holds certain mining and mineral production rights under the TMC Mineral Lease, covering lands consisting of approximately 1,229.82 acres located in the Asphalt Ridge area in Uintah County, Utah. The Company has entered into an agreement with Valkor Energy to exchange our TMC Mineral Leases for certain STLA leases situated nearby, subject to the approval of SITLA.

 

Any relocation or construction of a new processing facility from the TMC Mineral Lease, or the acquisition of other mineral leases for our operations, would require extensive plant relocation and construction work and new regulatory permits to allow our processing facilities at a new lease or mine site to becoming operational. There can be no assurance that we could economically relocate our processing facility to other leases or that we would be able to obtain new or substitute mineral leases, if necessary, upon or under acceptable terms, or that any new or substitute leases would permit us to relocate our processing facility to a site within such leases.

 

The loss of key personnel would directly affect our efficiency and profitability.

 

Our future success is dependent, in a large part, on retaining the services of our current management team. Our executive officers possess a unique and comprehensive knowledge of our industry, our technology and related matters that are vital to our success within the industry.  The knowledge, leadership and technical expertise of these individuals would be difficult to replace. The loss of one or more of our officers could have a material adverse effect on our operating and financial performance, including our ability to develop and execute our long term business strategy. We do not maintain key-man life insurance with respect to any employees. We do not have employment agreements with any of our executive officers other than our Chief Executive Officer. There can be no assurance that any of our officers will continue to be employed by us.

 

In the future, we may incur significant increased costs as a result of operating as a U.S reporting company, and our management may be required to devote substantial time to new compliance initiatives.

 

In the future, we may incur significant legal, accounting and other expenses as a result of operating as a public company. The Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”), as well as new rules subsequently implemented by the U.S. Securities and Exchange Commission (the “SEC”), have imposed various requirements on public companies, including requiring changes in corporate governance practices. Our management and other personnel will need to devote a substantial amount of time to these new compliance initiatives. Moreover, these rules and regulations will increase our legal and financial compliance costs and will make some activities more time-consuming and costly. For example, we expect these new rules and regulations to make it more difficult and more expensive for us to obtain director and officer liability insurance, and we may be required to incur substantial costs to maintain the same or similar coverage.

 

We have identified weaknesses in our internal controls, and we cannot provide assurances that these weaknesses will be effectively remediated or that additional material weaknesses will not occur in the future.

 

As a public company, we are subject to the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) and the Sarbanes-Oxley Act. We expect that the requirements of these rules and regulations will continue to increase our legal, accounting and financial compliance costs, make some activities more difficult, time consuming and costly, and place significant strain on our personnel, systems and resources.

 

We are required requires, among other things, to maintain effective disclosure controls and procedures, and internal control over financial reporting.

 

We do not yet have effective disclosure controls and procedures, or internal controls over all aspects of our financial reporting. We are continuing to develop and refine our disclosure controls and other procedures that are designed to ensure that information required to be disclosed by us in the reports that we will file with the SEC is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms. Our management is responsible for establishing and maintaining adequate internal control over our financial reporting, as defined in Rule 13a-15(f) under the Exchange Act. We will be required to expend time and resources to further improve our internal controls over financial reporting, including by expanding our staff. However, we cannot assure you that our internal control over financial reporting, as modified, will enable us to identify or avoid material weaknesses in the future.

 

25

 

 

We have identified material weaknesses in our internal control over financial reporting. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of our financial statements will not be prevented or detected on a timely basis. The material weaknesses identified to date include insufficient number of staff to maintain optimal segregation of duties and levels of oversight. As such, our internal controls over financial reporting were not designed or operating effectively.

 

We will be required to expend time and resources to further improve our internal controls over financial reporting, including by expanding our staff. However, we cannot assure you that our internal control over financial reporting, as modified, will enable us to identify or avoid material weaknesses in the future.

  

We have not yet retained sufficient staff or engaged sufficient outside consultants with appropriate experience in GAAP presentation, especially of complex instruments, to devise and implement effective disclosure controls and procedures, or internal controls. We will be required to expend time and resources hiring and engaging additional staff and outside consultants with the appropriate experience to remedy these weaknesses. We cannot assure you that management will be successful in locating and retaining appropriate candidates; that newly engaged staff or outside consultants will be successful in remedying material weaknesses thus far identified or identifying material weaknesses in the future; or that appropriate candidates will be located and retained prior to these deficiencies resulting in material and adverse effects on our business.

 

Our current controls and any new controls that we develop may become inadequate because of changes in conditions in our business, including increased complexity resulting from our international expansion. Further, weaknesses in our disclosure controls or our internal control over financial reporting may be discovered in the future. Any failure to develop or maintain effective controls, or any difficulties encountered in their implementation or improvement, could harm our operating results or cause us to fail to meet our reporting obligations and may result in a restatement of our financial statements for prior periods. Any failure to implement and maintain effective internal control over financial reporting could also adversely affect the results of management reports and independent registered public accounting firm audits of our internal control over financial reporting that we will eventually be required to include in our periodic reports that will be filed with the SEC. Ineffective disclosure controls and procedures, and internal control over financial reporting could also cause investors to lose confidence in our reported financial and other information, which would likely have a negative effect on the market price of our common stock.

 

Any failure to maintain effective disclosure controls and internal control over financial reporting could have a material and adverse effect on our business and operating results, and cause a decline in the market price of our common stock.

 

Our operations are currently geographically concentrated and therefore subject to regional economic, regulatory and capacity risks.

 

All of our production is anticipated to be derived from our properties in the Asphalt Ridge area. As a result of this geographic concentration, we may be disproportionately exposed to the effect of regional supply and demand factors, delays or interruptions of production from ore sands in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, weather events or interruption of the processing or transportation of crude oil or natural gas. Additionally, we may be exposed to additional risks, such as changes in laws and regulations that could cause us to permanently cease mining operations at Asphalt Ridge.

 

In addition, the Exchange Act requires, among other things, that we maintain effective internal controls for financial reporting and disclosure controls and procedures. Further, we are required to perform system and process evaluation and testing on the effectiveness of our internal controls over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act. Our testing may reveal deficiencies in our internal controls over financial reporting that are deemed to be material weaknesses. Our compliance with Section 404 will require that we incur substantial accounting expense and expend significant management efforts. We currently do not have an internal audit group, and we will need to hire additional accounting and financial staff with appropriate public company experience and technical accounting knowledge. Moreover, if we are not able to comply with the requirements of Section 404 in a timely manner, or if we or our independent registered public accounting firm identifies deficiencies in our internal controls over financial reporting that are deemed to be material weaknesses, the market price of our stock could decline, and we could be subject to sanctions or investigations by the SEC or other regulatory authorities, which would require additional financial and management resources.

 

26

 

 

Licenses and permits are required for our company to operate in some jurisdictions, and the loss of or failure to renew any or all of these licenses and permits or failure to comply with applicable laws and regulations could prevent us from either completing current projects or obtaining future projects, and thus, materially adversely affect our business.

 

Our operations will require licenses, permits and in some cases renewals of licenses and permits from various governmental authorities.  Our ability to obtain, sustain or renew such licenses and permits on acceptable terms is subject to change in regulations and policies and to the discretion of the applicable governments, among other factors.  Our inability to obtain, or our loss of or denial of extension of, any of these licenses or permits could hamper our ability to produce revenues from our operations.

  

We may be required to make significant capital expenditures to comply with laws and the applicable regulations and standards of governmental authorities and organizations.

 

We are subject to various national, state, and local laws and regulations in the various countries in which we operate, including those relating to the renewable energy industry in general, and may be required to make significant capital expenditures to comply with laws and the applicable regulations and standards of governmental authorities and organizations. Moreover, the cost of compliance could be higher than anticipated. On the effective date hereof, our operations will become subject to compliance with the U.S. Foreign Corrupt Practices Act in addition to certain international conventions and the laws, regulations and standards of other foreign countries in which we operate. 

 

In addition, many aspects of our operations are subject to laws and regulations that relate, directly or indirectly, to the renewable energy industry. Existing and proposed new governmental conventions, laws, regulations and standards, including those related to climate and emissions of “greenhouse gases,” may in the future add significantly to our operating costs or limit our activities or the activities and levels of capital spending by our customers. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and even criminal penalties, the imposition of remedial obligations, and the issuance of injunctions that may limit or prohibit our operations. The application of these requirements, the modification of existing laws or regulations or the adoption of new laws or regulations which impose substantial new regulatory requirements on our oil extraction operations could also harm our business, results of operations, financial condition and prospects. 

 

We could be subject to litigation that could have an adverse effect on our business and operating results.

 

We are, from time to time, involved in litigation. The numerous operating hazards inherent in our business increase our exposure to litigation, which may involve, among other things, contract disputes, personal injury, environmental, employment, warranty and product liability claims, tax and securities litigation, patent infringement and other intellectual property claims and litigation that arises in the ordinary course of business. Our management cannot predict with certainty the outcome or effect of any claim or other litigation matter. Litigation may have an adverse effect on us because of potential negative outcomes such as monetary damages or restrictions on future operations, the costs associated with defending the lawsuits, the diversion of management’s resources and other factors.

 

Global political, economic and market conditions could negatively impact our business.

 

Our company’s operations are affected by global political, economic and market conditions. The recent economic downturn has generally reduced the availability of liquidity and credit to fund business operations worldwide and has adversely affected our customers, suppliers and lenders. Our limited capital resources have negatively impacted our activity levels and, in turn, our financial condition and results of operations. A sustained or deeper recession in regions in which we operate could limit overall demand for our renewable energy solutions and could further constrain our ability to generate revenues and margins in those markets and to grow overall.

 

War, terrorism, geopolitical uncertainties, public health issues, and other business interruptions have caused and could cause damage or disruption to international commerce and the global economy, and thus could have a material adverse effect on us, our suppliers, logistics providers and customers. Our business operations are subject to interruption by, among others, natural disasters (including, without limitation, earthquakes), fire, power shortages, nuclear power plant accidents, terrorist attacks and other hostile acts, labor disputes, public health issues, and other events beyond our control. Such events could decrease demand for our services and products, make it difficult or impossible for us to make and deliver crude oil and hydrocarbon products to our buyers and customers, or to receive necessary supplies from our suppliers, and create delays and inefficiencies in our supply chain. Should major public health issues, including pandemics, arise, we could be adversely affected by more stringent employee travel restrictions, additional limitations in freight services, governmental actions limiting the movement of products between regions, delays in production ramps of new products, and disruptions in the operations of our customers and suppliers. The majority of our business operations, our corporate headquarters, and other critical business operations, including suppliers and customers, are in locations that could be affected by natural disasters. In the event of a natural disaster, we could incur significant losses, require substantial recovery time and experience significant expenditures in order to resume operations.

 

27

 

 

We do not carry business interruption insurance, and any unexpected business interruptions could adversely affect our business.

 

Our operations are vulnerable to interruption by earthquake, fire, power failure and power shortages, hardware and software failure, floods, computer viruses, and other events beyond our control.  In addition, we do not carry business interruption insurance to compensate us for losses that may occur as a result of these kinds of events, and any such losses or damages incurred by us could disrupt our projects and our other operations without reimbursement. Because of our limited financial resources, such an event could threaten our viability to continue as a going concern and lead to dramatic losses in the value of our common shares.

  

Certain Factors Related to Oil Sands Exploration

 

The Nature of Oil Sands Exploration and Development involves many risks.

 

Oil sands exploration and development are very competitive and involve many risks that even a combination of experience, knowledge and careful evaluation may not be able to overcome. As with any exploration property, there can be no assurance that commercial deposits of bitumen will be produced from oil sands exploration licenses and our permit lands in Utah.

 

The Extraction Technology has never been implemented on a large commercial basis as an oil and gas recovery technology before and our assumptions and expectations may not be accurate causing actual results of the implementation of the Extraction Technology to be significantly different form our current expectations. As a result, our operations may not generate any significant revenues from the development of the bitumen resources. In addition, there is no assurance that reserve engineers or lenders will determine that the production resulting from the application of the Extraction Technology can be used to establish reserves.

 

Furthermore, the marketability of any resource will be affected by numerous factors beyond our control. These factors include, but are not limited to, market fluctuations of prices, proximity and capacity of pipelines and processing equipment, equipment and labor availability and government regulations (including, without limitation, regulations relating to prices, taxes, royalties, land tenure, allowable production, importing and exporting of oil and gas, land use and environmental protection). The extent of these factors cannot be accurately predicted, but the combination of these factors may result in us not receiving an adequate return on invested capital.

 

Supply risk is a function of the unavailability of oil sands ores containing heavy oil and bitumen, whether from our mineral leases or from third parties; poor ore grade quality or density, and solvents and condensates that we acquire from third parties. Unplanned mine equipment and extraction plant maintenance, storage costs and in situ reservoir and equipment performance could also impact our production targets. Our oil extraction activities will be dependent upon having an available supply of mined oil sands ores and sandstones containing heavy oil and bitumen.

 

The viability of our business plan, business operations, and future operating results and financial condition are and will be exposed to fluctuating prices for oil, gas, oil products and chemicals.

 

Prices of oil, gas, oil products and chemicals are affected by supply and demand, which can fluctuate significantly. Factors that influence supply and demand include operational issues, natural disasters, weather, political instability or conflicts, economic conditions and actions by major oil-exporting countries. Price fluctuations can have a material effect on our ability to raise capital and fund our exploration activities, our potential future earnings, and our financial condition. For example, in a low oil and gas price environment oil sands exploration and development may not be economically or financially viable or profitable. Prolonged periods of low oil and gas prices, or rising costs, could result in our mining and processing projects being delayed or cancelled, as well as the impairment of certain assets.

 

28

 

 

Environmental and regulatory compliance may impose substantial costs on us.

 

Our operations are or will be subject to stringent federal, state and local laws and regulations relating to improving or maintaining environmental quality. Environmental laws often require parties to pay for remedial action or to pay damages regardless of fault. Environmental laws also often impose liability with respect to divested or terminated operations, even if the operations were terminated or divested many years ago.

 

Our mining, production and processing activities are or will be subject to extensive laws and regulations governing prospecting, development, production, exports, taxes, labor standards, occupational health, waste disposal, land use, protection and remediation of the environment, protection of endangered and protected species, operational safety, toxic substances and other matters. Generally, oil and gas exploration and production, including our oil sands mining and processing operations, are subject to risks and liabilities associated with pollution of the environment and disposal of waste products. Compliance with these laws and regulations will impose substantial costs on us and will subject us to significant potential liabilities. In addition, should there be changes to existing laws or regulations, our competitive position within the oil sands industry may be adversely affected, as many industry players have greater resources than we do. 

 

We are required to obtain various regulatory permits and approvals in order to explore and develop our properties. There is no assurance that regulatory approvals for exploration and development of our properties will be obtained at all or with terms and conditions acceptable to us.

 

We may be exposed to third party liability and environmental liability in the operation of our business.

 

Our operations could result in liability for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damage. We could be liable for environmental damages caused by previous owners. As a result, substantial liabilities to third parties or governmental entities may be incurred, and the payment of such liabilities could have a material adverse effect on our financial condition and results of operations. The release of harmful substances in the environment or other environmental damages caused by our activities could result in us losing our operating and environmental permits or inhibit us from obtaining new permits or renewing existing permits. We currently have a limited amount of insurance and, at such time as we commence additional operations, we expect to be able to obtain and maintain additional insurance coverage for our operations, including limited coverage for sudden environmental damages, but we do not believe that insurance coverage for environmental damage that occurs over time is available at a reasonable cost. Moreover, we do not believe that insurance coverage for the full potential liability that could be caused by environmental damage is available at a reasonable cost. Accordingly, we may be subject to liability or may lose substantial portions of our properties in the event of certain environmental damage. We could incur substantial costs to comply with environmental laws and regulations which could affect our ability to operate as planned.

 

American climate change legislation could negatively affect markets for crude and synthetic crude oil

 

Environmental legislation regulating carbon fuel standards in the United States (or elsewhere) could adversely affect companies that produce, refine, transport, process and sell crude oil and refined products, including our oil sands mining and processing operations, and could result in increased costs and/or reduced revenue. For example, both the state of California and the U.S. Government have passed legislation which, in some circumstances, considers the lifecycle greenhouse gas emissions of purchased fuel and which may negatively affect our business or require the purchase of emissions credits, which may not be economically feasible.

 

Because of the speculative nature of oil exploration, there is risk that we will not find commercially exploitable oil and gas and that our business will fail.

 

The search for commercial quantities of oil and gas as a business is extremely risky. We cannot provide investors with any assurance that any properties in which we obtain a mineral interest will contain commercially exploitable quantities of oil and gas or heavy oil and bitumen contained in oil sands.  The exploration expenditures to be made by us may not result in the discovery of commercial quantities of oil and/or gas.  Problems such as unusual or unexpected formations or pressures, premature declines of reservoirs, invasion of water into producing formations and other conditions involved in oil and gas exploration often result in unsuccessful exploration efforts. If we are unable to find commercially exploitable quantities of oil and gas (in particular oil sands containing economically recoverable heavy oil and bitumen), and/or we are unable to commercially extract such quantities, we may be forced to abandon or curtail our business plan and, as a result, any investment in us may become worthless.

 

29

 

 

The price of oil and gas has historically been volatile.  If it were to decrease substantially, our projections, budgets and revenues would be adversely affected, potentially forcing us to make changes in our operations.

 

Our future financial condition, results of operations and the carrying value of any oil and gas interests we acquire will depend primarily upon the prices paid for oil and gas production. Oil and gas prices historically have been volatile and likely will continue to be volatile in the future, especially given current world geopolitical conditions. Our cash flows from operations are highly dependent on the prices that we receive for oil and gas. This price volatility also affects the amount of our cash flows available for capital expenditures and our ability to borrow money or raise additional capital. The prices for oil and gas are subject to a variety of additional factors that are beyond our control. These factors include:

 

the level of consumer demand for oil and gas;

 

the domestic and foreign supply of oil and gas;

 

the ability of the members of the Organization of Petroleum Exporting Countries (“OPEC”) to agree to and maintain oil price and production controls;

  

the price of oil, both in international and U.S. markets;

 

domestic governmental regulations and taxes;

 

the price and availability of solvent materials and feedstocks;

 

weather conditions;

 

market uncertainty due to political conditions in oil and gas producing regions, including the Middle East; and

 

worldwide economic conditions.

 

These factors as well as the volatility of the energy markets generally make it extremely difficult to predict future oil and gas price movements with any certainty. Declines in oil and gas prices affect our revenues and accordingly, such declines could have a material adverse effect on our financial condition, results of operations, our future oil and gas reserves and the carrying values of our oil and gas properties. If the oil and gas industry experiences significant price declines, we may be unable to make planned expenditures, among other things. If this were to happen, we may be forced to abandon or curtail our business operations, which would cause the value of an investment in us to decline in value or become worthless.

  

Because of the inherent dangers involved in oil and gas operations, there is a risk that we may incur liability or damages as we conduct our business operations, which could force us to expend a substantial amount of money in connection with litigation and/or a settlement.

 

The oil and gas business involves a variety of operating hazards and risks such as well blowouts, pipe failures, casing collapse, explosions, uncontrollable flows of oil, gas or well fluids, fires, spills, pollution, releases of toxic gas and other environmental hazards and risks. These hazards and risks could result in substantial losses to us from, among other things, injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, cleanup responsibilities, regulatory investigation and penalties and suspension of operations. In addition, we may be liable for environmental damages caused by previous owners of property purchased and leased by us. As a result, substantial liabilities to third parties or governmental entities may be incurred, the payment of which could reduce or eliminate the funds available for exploration, development or acquisitions or result in the loss of our properties and/or force us to expend substantial monies in connection with litigation or settlements. There can be no assurance that any insurance we may have in place will be adequate to cover any losses or liabilities. The occurrence of a significant event not fully insured or indemnified against could materially and adversely affect our financial condition and operations. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial condition and results of operations, which could lead to any investment in us becoming worthless.

 

30

 

 

The market for oil and gas is intensely competitive, and competitive pressures could force us to abandon or curtail our business plan.

 

The market for oil, gas and hydrocarbon products is highly competitive, and we only expect competition to intensify in the future. Numerous well-established companies are focusing significant resources on exploration and production and are currently competing with us for oil and gas opportunities, including opportunities involving the production of crude oil, synthetic crude oil and other products from oil sands.  Other oil and gas companies may seek to acquire oil and gas leases and properties that we have targeted.  Additionally, other companies engaged in our line of business may compete with us from time to time in obtaining capital from investors.  Competitors include larger companies which, in particular, may have access to greater resources, may be more successful in the recruitment and retention of qualified employees and may conduct their own refining and petroleum marketing operations, which may give them a competitive advantage.  Actual or potential competitors may be strengthened through the acquisition of additional assets and interests.  Additionally, there are numerous companies focusing their resources on creating fuels and/or materials which serve the same purpose as oil and gas but are manufactured from renewable resources. As a result, there can be no assurance that we will be able to compete successfully or that competitive pressures will not adversely affect our business, results of operations and financial condition. If we are not able to successfully compete in the marketplace, we could be forced to curtail or even abandon our current business plan, which could cause any investment in us to become worthless.

 

Our estimates of the volume of recoverable resources could have flaws, or such resources could turn out not to be commercially extractable. Further, we may not be able to establish any reserves. As a result, our future revenues and projections could be incorrect.

 

Estimates of recoverable resources and of future net revenues prepared by different petroleum engineers may vary substantially depending, in part, on the assumptions made and may be subject to adjustment either up or down in the future. To date we have not established any reserves. Our actual amounts of production, revenue, taxes, development expenditures, operating expenses, and future quantities of recoverable oil and gas reserves may vary substantially from the estimates. There are numerous uncertainties inherent in estimating quantities of bitumen resources and recoverable reserves, including many factors beyond our control and no assurance can be given that the recovery of bitumen will be realized. In general, estimates of resources and reserves are based upon a number of factors and assumptions made as of the date on which the resources and reserve estimates were determined, such as geological and engineering estimates which have inherent uncertainties, the assumed effects of regulation by governmental agencies and estimates of future commodity prices and operating costs, all of which may vary considerably from estimated results. Oil and gas reserve estimates are necessarily inexact and involve matters of subjective engineering judgment. In addition, any estimates of our future net revenues and the present value thereof are based on assumptions derived in part from historical price and cost information, which may not reflect current and future values, and/or other assumptions made by us that only represent our best estimates. For these reasons, estimates of reserves and resources, the classification of such resources and reserves based on risk of recovery, prepared by different engineers or by the same engineers at different times, may vary substantially. Investors are cautioned not to assume that all or any part of a resource is economically or legally extractable. Additionally, if declines in and instability of oil and gas prices occur, then write downs in the capitalized costs associated with any oil and gas assets we obtain may be required. Because of the nature of the estimates of our recoverable resources and future reserves and estimates in general, we can provide no assurance that our estimated bitumen resources or future reserves will be present and/or commercially extractable. If our recoverable bitumen resource estimates are incorrect, the value of our common shares could decrease and we may be forced to write down the capitalized costs of our oil and gas properties.

 

Decommissioning costs are unknown and may be substantial.  Unplanned costs could divert resources from other projects.

 

In the future, we may become responsible for costs associated with abandoning and reclaiming wells, facilities and pipelines which we use for processing of oil and gas reserves.  Abandonment and reclamation of these facilities and the costs associated therewith is often referred to as “decommissioning.”  We accrue a liability for decommissioning costs associated with our extraction plant and wells but have not established any cash reserve account for these potential costs in respect of any of our properties.  If decommissioning is required before economic depletion of our properties or if our estimates of the costs of decommissioning exceed the value of the reserves remaining at any particular time to cover such decommissioning costs, we may have to draw on funds from other sources to satisfy such costs.  The use of other funds to satisfy such decommissioning costs could impair our ability to focus capital investment in other areas of our business.

  

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We may have difficulty marketing or distributing the oil we produce, which could harm our financial condition. 

 

In order to sell the finished crude oil that we are able to produce, if any, we must be able to make economically viable arrangements for the storage, transportation and distribution of our oil to the market.  We will rely on local infrastructure and the availability of transportation for storage and shipment of our products, but infrastructure development and storage and transportation facilities may be insufficient for our needs at commercially acceptable terms in the localities in which we operate.  This situation could be particularly problematic to the extent that our operations are conducted in remote areas that are difficult to access, such as areas that are distant from shipping and/or pipeline facilities.  These factors may affect our and potential partners’ ability to explore and develop properties and to store and transport oil and gas production, increasing our expenses.

 

Furthermore, weather conditions or natural disasters, actions by companies doing business in one or more of the areas in which we will operate, or labor disputes may impair the distribution of oil and/or gas and in turn diminish our financial condition or ability to maintain our operations.

 

Challenges to our properties may impact our financial condition.

 

Title to oil and gas interests is often not capable of conclusive determination without incurring substantial expense.  While we intend to make appropriate inquiries into the title of properties and other development rights we acquire, title defects may exist.  In addition, we may be unable to obtain adequate insurance for title defects, on a commercially reasonable basis or at all.  If title defects do exist, it is possible that we may lose all or a portion of our right, title and interests in and to the properties to which the title defects relate. If our property rights are reduced, our ability to conduct our exploration, development and processing activities may be impaired.  To mitigate title problems, common industry practice is to obtain a title opinion from a qualified oil and gas attorney prior to the excavation activities undertaken or the drilling operations of a well.

 

We rely on technology to conduct our business, and our technology could become ineffective or obsolete.

 

We rely on technology, including geographic and seismic analysis techniques and economic models, to develop our reserve estimates and to guide our exploration, development and processing activities.  We and our operator partners will be required to continually enhance and update our technology to maintain its efficacy and to avoid obsolescence.  Our oil extraction business is dependent upon the Extraction Technology that we have developed but which has not yet been used on a large commercial scale. As such, the project carries with it a greater degree of technological risk than other projects that employ commercially proven technologies and the Extraction Technology may not perform as anticipated. If major process design changes are required, the costs of doing so may be substantial and may be higher than the costs that we anticipate for technology maintenance and development.  If we are unable to maintain the efficacy of our technology, our ability to manage our business and to compete may be impaired.  Further, even if we are able to maintain technical effectiveness, our technology may not be the most efficient means of reaching our objectives, in which case we may incur higher operating costs than we would were our technology more efficient.

  

Our failure to protect our proprietary information and any successful intellectual property challenges or infringement proceedings against us could materially and adversely affect our competitive position.

 

We rely on a variety of intellectual property rights that we use in our services and products. We rely upon intellectual property rights and other contractual or proprietary rights, including copyright, trademark, trade secrets, confidentiality provisions, contractual provisions, licenses and patents. We may not be able to successfully preserve these intellectual property rights in the future, and these rights could be invalidated, circumvented, or challenged. In addition, the laws of some foreign countries in which our services and products may be sold do not protect intellectual property rights to the same extent as the laws of the United States. Our failure to protect our proprietary information and any successful intellectual property challenges or infringement proceedings against us could materially and adversely affect our competitive position. Without patent and other similar protection, other companies could use substantially identical technology to offer products for sale without incurring the sizable development costs we have incurred. Even if we spend the necessary time and money, a patent may not be issued or it may insufficiently protect the technology it was intended to protect. If our pending patent applications are not approved for any reason, the degree of future protection for our proprietary technology will remain uncertain. If we have to engage in litigation to protect our patents and other intellectual property rights, the litigation could be time consuming and expensive, regardless of whether we are successful. Despite our efforts, our intellectual property rights, particularly existing or future patents, may be invalidated, circumvented, challenged, infringed or required to be licensed to others. We cannot be assured that any steps we may take to protect our intellectual property rights and other rights to such proprietary technologies that are central to our operations will prevent misappropriation or infringement of the right to use or license others to use the Extraction Technology and accordingly may conduct an oil sands extraction operation similar to ours.

 

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Certain Factors Related to Our Common Shares

 

There presently  is a limited market for our common shares, and the price of our common shares may continue to be volatile.

 

Our common shares are currently quoted on the TSXV, the Frankfurt Exchange and the OTC Pink Sheets markets. Our common shares are currently subject to a cease trade order on the TSXV, as mentioned above.  Our common shares, however, are very thinly traded, and we have a very limited trading history.  There could continue to be volatility in the volume and market price of our common shares moving forward.  This volatility may be caused by a variety of factors, including the lack of readily available quotations, the absence of consistent administrative supervision of “bid” and “ask” quotations and generally lower trading volume. In addition, factors such as quarterly variations in our operating results, changes in financial estimates by securities analysts or our failure to meet our or their projected financial and operating results, litigation involving us, factors relating to the oil and gas industry, actions by governmental agencies, national economic and stock market considerations as well as other events and circumstances beyond our control could have a significant impact on the future market price of our common shares and the relative volatility of such market price.

 

Offers or availability for sale of a substantial number of shares of our common shares may cause the price of our common shares to decline.

 

Our shareholders could sell substantial amounts of common shares in the public market, including shares sold upon the filing of a registration statement that registers such shares and/or upon the expiration of any statutory holding period under Rule 144 of the Securities Act of 1933 (the “Securities Act”), if available, or upon trading limitation periods.  Such volume could create a circumstance commonly referred to as an “overhang” and in anticipation of which the market price of our common shares could fall. The existence of an overhang, whether or not sales have occurred or are occurring, also could make it more difficult for us to secure additional financing through the sale of equity or equity-related securities in the future at a time and price that we deem reasonable or appropriate.

 

We do not anticipate paying any cash dividends.

 

We do not anticipate paying cash dividends on our common shares for the foreseeable future.  The payment of dividends, if any, would be contingent upon our revenues and earnings, if any, capital requirements, and general financial condition.  The payment of any dividends will be within the discretion of our Board of Directors.  We presently intend to retain all earnings, if any, to implement our business strategy; accordingly, we do not anticipate the declaration of any dividends in the foreseeable future.

 

The market price and trading volume of our common shares may continue to be volatile and may be affected by variability in our performance from period to period and economic conditions beyond management’s control.

 

The market price of our common shares may continue to be highly volatile and could be subject to wide fluctuations. This means that our shareholders could experience a decrease in the value of their common shares regardless of our operating performance or prospects. The market prices of securities of companies operating in the oil and gas sector have often experienced fluctuations that have been unrelated or disproportionate to the operating results of these companies. In addition, the trading volume of our common shares may fluctuate and cause significant price variations to occur. If the market price of our common shares declines significantly, our shareholders may be unable to resell our common shares at or above their purchase price, if at all. There can be no assurance that the market price of our common shares will not fluctuate or significantly decline in the future.

  

Some specific factors that could negatively affect the price of our common shares or result in fluctuations in their price and trading volume include:

 

actual or expected fluctuations in our operating results;

 

actual or expected changes in our growth rates or our competitors’ growth rates;

 

our inability to raise additional capital, limiting our ability to continue as a going concern;

 

changes in market prices for our product or for our raw materials;

 

changes in market valuations of similar companies;

 

changes in key personnel for us or our competitors;

 

speculation in the press or investment community;

 

changes or proposed changes in laws and regulations affecting the renewable energy industry as a whole;

 

conditions in the renewable energy industry generally; and

 

conditions in the financial markets in general or changes in general economic conditions.

  

In the past, following periods of volatility in the market price of the securities of other companies, shareholders have often instituted securities class action litigation against such companies. If we were involved in a class action suit, it could divert the attention of senior management and, if adversely determined, could have a material adverse effect on our results of operations and financial condition.

 

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We may be classified as a foreign investment company for U.S. federal income tax purposes, which could subject U.S. investors in our common shares to significant adverse U.S. income tax consequences.

 

Depending upon the value of our common shares and the nature of our assets and income over time, we could be classified as a “passive foreign investment company”, or “PFIC”, for U.S. federal income tax purposes. Based upon our current income and assets and projections as to the value of our common shares, we do not presently expect to be a PFIC for the current taxable year or the foreseeable future. While we do not expect to become a PFIC, if among other matters, our market capitalization is less than anticipated or subsequently declines, we may be a PFIC for the current or future taxable years. The determination of whether we are or will be a PFIC will also depend, in part, on the composition of our income and assets, which will be affected by how, and how quickly, we use our liquid assets. Because PFIC status is a factual determination made annually after the close of each taxable year, including ascertaining the fair market value of our assets on a quarterly basis and the character of each item of income we earn, we can provide no assurance that we will not be a PFIC for the current taxable year or any future taxable year.

 

If we were to be classified as a PFIC in any taxable year, a U.S. holder would be subject to special rules generally intended to reduce or eliminate any benefits from the deferral of U.S. federal income tax that a U.S. holder could derive from investing in a non-U.S. corporation that does not distribute all of its earnings on a current basis. Further, if we are classified as a PFIC for any year during which a U.S. holder holds our common shares, we generally will continue to be treated as a PFIC for all succeeding years during which such U.S. holder holds our common shares.

 

We are exposed to credit risk through our cash and cash equivalents held at financial institutions.

 

Credit risk is the risk of unexpected loss if a customer or third party to a financial instrument fails to meet contractual obligations. We are exposed to credit risk through our cash and cash equivalents held at financial institutions. We have cash balances at four financial institutions. We have not experienced any loss on these accounts, although balances in the accounts may exceed the insurable limits.

 

Some of our officers and directors have conflicts of interest and cannot devote a substantial amount of time to our company.

 

Certain of our current directors and officers are, and may continue to be, involved in other industries through their direct and indirect participation in corporations, partnerships or joint ventures which may be potential competitors of ours. Several of our officers work for us on a part time basis. These officers have discretion as to what time they devote to our activities, which may result in lack of availability when needed due to responsibilities at other jobs. In addition, situations may arise in connection with potential acquisitions or opportunities where the other interests of these directors and officers may conflict with our interests. Directors and officers with conflicts of interest will be subject to and follow the procedures set out in applicable corporate and securities legislation, regulation, rules and policies. Certain of our directors and officers will only devote a portion of their time to our business and affairs and some of them are or will be engaged in other projects or businesses.

 

Our ability to issue an unlimited number of common shares and preferred shares may have anti-takeover effects that could discourage, delay or prevent a change of control and may result in dilution to our investors.

 

Our charter documents currently authorize the issuance of an unlimited number of common shares without nominal or par value and an unlimited number of preferred shares without nominal or par value in one or more series without the requirement that we obtain any shareholder approval. The Board could authorize the issuance of additional preferred shares that would grant holders rights to our assets upon liquidation, special voting rights, redemption rights. That could impair the rights of holders of common shares and discourage a takeover attempt. In addition, in an effort to discourage a takeover attempt, our Board could issue an unlimited number of additional common shares. There are currently no preferred shares outstanding. If we issue any additional shares or enter into private placements to raise financing through the sale of equity securities, investors’ interests in our company will be diluted and investors may suffer substantial dilution in their net book value per share depending on market conditions and the price at which such securities are sold. If we issue any such additional shares, such issuances also will cause a reduction in the proportionate ownership and voting power of all other shareholders.

  

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Issuances of common shares upon exercise or conversion of convertible securities, including pursuant to our equity incentive plans and outstanding share purchase warrants and convertible notes could result in additional dilution of the percentage ownership of our stockholders and could cause our stock price to fall.

 

As of December 14, 2021, we have share purchase warrants to purchase 73,148,824 common shares outstanding at exercise prices ranging from $0.055 to $0.23 and options to purchase 7,250,000 common shares with a weighted average exercise price of CDN $0.79 and notes convertible into 118,391,331 common shares based on conversion prices ranging from $0.042 to $0.12 per share. The issuance of the common shares underlying the share purchase warrants, options and convertible notes will have a dilutive effect on the percentage ownership held by holders of our common shares.

 

The risks associated with penny stock classification could affect the marketability of our common shares and shareholders could find it difficult to sell their shares.

 

Our common shares are currently subject to “penny stock” rules as promulgated under the Securities and Exchange Act of 1934, as amended. The SEC adopted rules that regulate broker-dealer practices in connection with transactions in penny stocks. Transaction costs associated with purchases and sales of penny stocks are likely to be higher than those for other securities. Penny stocks generally are equity securities with a price of less than $5.00 (other than securities listed on certain national securities exchanges, provided that current price and volume information with respect to transactions in such securities is provided by the exchange).

 

The penny stock rules require a broker-dealer, prior to a transaction in a penny stock not otherwise exempt from the rules, to deliver a standardized risk disclosure document that provides information about penny stocks and the nature and level of risks in the penny stock market. The broker-dealer also must provide the customer with current bid and offer quotations for the penny stock, the compensation of the broker-dealer and its salesperson in the transaction, and monthly account statements showing the market value of each penny stock held in the customer’s account. The bid and offer quotations, and the broker-dealer and salesperson compensation information, must be given to the customer orally or in writing prior to effecting the transaction and must be given to the customer in writing before or with the customer’s confirmation.

 

In addition, the penny stock rules require that prior to a transaction in a penny stock not otherwise exempt from such rules, the broker- dealer must make a special written determination that the penny stock is a suitable investment for the purchaser and receive the purchaser’s written agreement to the transaction. These disclosure requirements may have the effect of reducing the level of trading activity in the secondary market for our common shares in the United States and shareholders may find it more difficult to sell their shares.

  

The rights of our shareholders may differ from the rights typically offered to shareholders of a U.S. corporation.

 

We are incorporated under the Business Corporations Act (Ontario). The rights of holders of our common shares are governed by the laws of the Province of Ontario, including the Business Corporations Act (Ontario), by the applicable laws of Canada, and by our Articles, as amended (the “Articles”), and our bylaws (the “bylaws”). These rights differ in certain respects from the rights of shareholders in typical U.S. corporations. The principal differences include without limitation the following:

 

Under the Business Corporations Act (Ontario), we have a lien on any common share registered in the name of a shareholder or the shareholder’s legal representative for any debt owed by the shareholder to us. Under U.S. state law, corporations generally are not entitled to any such statutory liens in respect of debts owed by shareholders. Our bylaws also provide that at least 25% of our Board of Directors must be resident Canadians.

 

With regard to certain matters, we must obtain approval of our shareholders by way of at least 66 2/3% of the votes cast at a meeting of shareholders duly called for such purpose being cast in favor of the proposed matter. Such matters include without limitation: (a) the sale, lease or exchange of all or substantially all of our assets out of the ordinary course of our business; and (b) any amendments to our Articles including, but not limited to, amendments affecting our capital structure such as the creation of new classes of shares, changing any rights, privileges, restrictions or conditions in respect of our shares, or changing the number of issued or authorized shares, as well as amendments changing the minimum or maximum number of directors set forth in the Articles. Under many U.S. state laws, the sale, lease, exchange or other disposition of all or substantially all of the assets of a corporation generally requires approval by a majority of the outstanding shares, although in some cases approval by a higher percentage of the outstanding shares may be required. In addition, under U.S. state law the vote of a majority of the shares is generally sufficient to amend a company’s certificate of incorporation, including amendments affecting capital structure or the number of directors.

 

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Pursuant to our bylaws, two persons holding 5% of the shares entitled to vote at the meeting present in person or represented by proxy and each entitled to vote thereat shall constitute a quorum for the transaction of business at any meeting of shareholders. Under U.S. state law, a quorum generally requires the presence in person or by proxy of a specified percentage of the shares entitled to vote at a meeting, and such percentage is generally not less than one-third of the number of shares entitled to vote.

 

Under rules of the Ontario Securities Commission, a meeting of shareholders must be called for consideration and approval of certain transactions between a corporation and any “related party” (as defined in such rules). A “related party” is defined to include, among other parties, directors and senior officers of a corporation, holders of more than 10% of the voting securities of a corporation, persons owning a block of securities that is otherwise sufficient to affect materially the control of the corporation, and other persons that manage or direct, to a substantial degree, the affairs or operations of the corporation. At such shareholders’ meeting, votes cast by any related party who holds common shares and has an interest in the transaction may not be counted for the purposes of determining whether the minimum number of required votes have been cast in favor of the transaction. Under U.S. state law, a transaction between a corporation and one or more of its officers or directors can generally be approved either by the shareholders or by a majority of the directors who do not have an interest in the transaction.

 

Neither Canadian law nor our Articles or bylaws limit the right of a non-resident to hold or vote our common shares, other than as provided in the Investment Canada Act (the “Investment Act”), as amended by the World Trade Organization Agreement Implementation Act (the “WTOA Act”). The Investment Act generally prohibits implementation of a direct reviewable investment in a Canadian business, as defined in the Investment Act, by an individual, government or agency thereof, corporation, partnership, trust or joint venture that is not a “Canadian,” as defined in the Investment Act (a “non-Canadian”), unless, after review, the Minister responsible for the Investment Act is satisfied that the investment is likely to be of net benefit to Canada. An investment in our common shares by a non-Canadian (other than a “WTO Investor,” as defined below) would be reviewable under the Investment Act if it were an investment to directly acquire control of our company, and the value of our assets were CDN$5.0 million or more (provided that immediately prior to the implementation of the investment in our company, it was not controlled by WTO Investors). An investment in our common shares by a WTO Investor (or by a non- Canadian other than a WTO Investor if, immediately prior to the implementation of the investment our company was controlled by WTO Investors) would be reviewable under the Investment Act if it were an investment to directly acquire control and the value of our assets or our enterprise value was equal to or exceeded certain threshold amounts determined on an annual basis.

 

The threshold for a pre-closing net benefit review depends on whether the purchaser is: (a) controlled by a person or entity from a member of the WTO; (b) a state-owned enterprise (SOE); or (c) from a country considered a “Trade Agreement Investor” under the Investment Act. A different threshold also applies if the Canadian business carries on a cultural business.

 

The 2021 threshold for WTO investors that are state-owned enterprises (“SOEs”), as defined in the Investment Act, will be CDN$415 million based on the book value of the Canadian business’ assets.

 

The 2021 thresholds for review for direct acquisitions of control of a publicly-traded Canadian entity by private sector investor WTO investors (CDN$1.043 billion) and private sector trade agreement investors (CDN$1.565 billion) are both based on the “enterprise value” of the Canadian business being acquired, where the enterprise value is the target’s market capitalization, plus total liabilities (less operating liabilities), minus cash and cash equivalents.

 

A non-Canadian, whether a WTO Investor or otherwise, would be deemed to acquire control of our company for purposes of the Investment Act if he or she acquired a majority of our common shares. The acquisition of less than a majority, but at least one-third of the shares, would be presumed to be an acquisition of control of our company, unless it could be established that we are not controlled in fact by the acquirer through the ownership of the shares. In general, an individual is a WTO Investor if he or she is a “national” of a country (other than Canada) that is a member of the WTO (“WTO Member”) or has a right of permanent residence in a WTO Member. A corporation or other entity will be a “WTO Investor” if it is a “WTO Investor-controlled entity,” pursuant to detailed rules set out in the Investment Act. The U.S. is a WTO Member. Certain transactions involving our common shares would be exempt from the Investment Act, including (i) an acquisition of our common shares if the acquisition were made in connection with the person’s business as a trader or dealer in securities; (ii) an acquisition of control of our company in connection with the realization of a security interest granted for a loan or other financial assistance and not for any purpose related to the provisions of the Investment Act; and (iii) an acquisition of control of our company by reason of an amalgamation, merger, consolidation or corporate reorganization, following which the ultimate direct or indirect control of our company, through the ownership of voting interests, remains unchanged. Under U.S. law, except in limited circumstances, restrictions generally are not imposed on the ability of non- residents to hold a controlling interest in a U.S. corporation.

 

The Canadian government may review and prohibit any level of investment by a non-Canadian in a Canadian business if it determines that the investment may be “injurious to national security”.

 

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We are required to comply with the Exchange Act’s domestic reporting regime and cause us to incur significant legal, accounting and other expenses.

 

We are required to comply with all of the periodic disclosure and current reporting requirements of the Exchange Act applicable to U.S. domestic issuers, which are more detailed and extensive than the requirements for foreign private issuers. We may also be required to make changes in our corporate governance practices in accordance with various SEC rules. As a result, we expect that compliance would increase our legal and financial compliance costs and is likely to make some activities highly time consuming and costly. We also expect that as we are now required to comply with the securities rules and regulations applicable to U.S. domestic issuers, it would make it more difficult and expensive for us to obtain director and officer liability insurance, and we may be required to accept reduced coverage or incur substantially higher costs to obtain coverage. These rules and regulations could also make it more difficult for us to attract and retain qualified members of our Board of Directors.

 

We are an emerging growth  company within the meaning of the Securities Act and intend to take advantage of certain reduced reporting requirements.

 

We are an “emerging growth company,” as defined in section 2(a)(19) of the Securities Act. For as long as we continue to be an emerging growth company, we may take advantage of exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies, including not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act even if we cease to be a smaller reporting company with annual revenues of less than $100 million, exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and shareholder approval of any golden parachute payments not previously approved. As an emerging growth company, we are required to report only two years of financial results and selected financial data compared to three and five years, respectively, for comparable data reported by other public companies. We may take advantage of these exemptions until we are no longer an emerging growth company. We will remain an emerging growth company until the earlier of (1) the last day of the fiscal year: (a) following the fifth anniversary of the date of the first sale of our common shares pursuant to an effective registration statement filed under the Securities Act; (b) in which we have total annual gross revenue of at least $1.07 billion; or (c) in which we are deemed to be a large accelerated filer, which generally means the market value of our common shares that is held by non-affiliates exceeded $700.0 million as of the last business day of our most recently completed second fiscal quarter, and (2) the date on which we have issued more than $1.0 billion in non-convertible debt during the prior three-year period. We cannot predict if investors will find our common shares less attractive because we may rely on these exemptions. If some investors find our common shares less attractive as a result, there may be a less active trading market for our common shares and the price of our common shares may be more volatile in the event that we decide to make an offering of our common shares following this direct listing.

 

Claims of U.S. civil liabilities may not be enforceable against us.

 

We are incorporated under Canadian law. Certain members of our Board of Directors and senior management are non- residents of the United States, and many of our assets and the assets of such persons are located outside the United States. As a result, it may not be possible to serve process on such persons or us in the United States or to enforce judgments obtained in U.S. courts against them or us based on civil liability provisions of the securities laws of the United States. As a result, it may not be possible for investors to effect service of process within the United States upon such persons or to enforce judgments obtained in U.S. courts against them or us, including judgments predicated upon the civil liability provisions of the U.S. federal securities laws.

 

The United States and Canada do not currently have a treaty providing for recognition and enforcement of judgments (other than arbitration awards) in civil and commercial matters. Consequently, a final judgment for payment given by a court in the United States, whether or not predicated solely upon U.S. securities laws, would not automatically be recognized or enforceable in Canada. In addition, uncertainty exists as to whether Canadian courts would entertain original actions brought in the United States against us or our directors or senior management predicated upon the securities laws of the United States or any state in the United States. Any final and conclusive monetary judgment for a definite sum obtained against us in U.S. courts would be treated by the courts of Canada as a cause of action in itself and sued upon as a debt at common law so that no retrial of the issues would be necessary, provided that certain requirements are met. Whether these requirements are met in respect of a judgment based upon the civil liability provisions of the U.S. securities laws, including whether the award of monetary damages under such laws would constitute a penalty, is an issue for the court making such decision. If a Canadian court gives judgment for the sum payable under a U.S. judgment, the Canadian judgment will be enforceable by methods generally available for this purpose. These methods generally permit the Canadian court discretion to prescribe the manner of enforcement.

 

As a result, U.S. investors may not be able to enforce against us or our senior management, Board of Directors or certain experts named herein who are residents of Canada or countries other than the United States any judgments obtained in U.S. courts in civil and commercial matters, including judgments under the U.S. federal securities laws.

 

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Our ability to use our net operating losses and certain other tax attributes may be limited.

  

As of August 31, 2020, we had accumulated net operating losses (NOLs), of approximately CDN $31.0 million. Varying jurisdictional tax codes have restrictions on the use of NOLs, if a corporation undergoes an “ownership change,” the corporation’s ability to use its pre-change NOLs, R&D credits and other pre-change tax attributes to offset its post-change income may be limited. An ownership change is generally defined as a greater than 50% change in equity ownership. Based upon an analysis of our equity ownership, we do not believe that we have experienced such ownership changes and therefore our annual utilization of our NOLs is not limited. However, should we experience additional ownership changes, our NOL carry forwards may be limited.

 

We may be subject to liability for failure to comply with the requirements of Regulation 14A under the Securities Exchange Act of 1934.

 

Through inadvertence, we did not comply with the requirements of Regulation 14A under the Exchange Act in connection with the annual and special meeting of our shareholders held on December 13, 2019 (the Meeting”). In particular: (a) the proxy statement prepared by our management complied with applicable Canadian proxy rules but failed to meet the form and disclosure requirements for proxy statements prescribed by Schedule 14A under the Exchange Act; (b) since item 4 of the agenda for the Meeting (approval of our Company’s advance notice by-law) and agenda item 5 (approval of a proposed consolidation (reverse split) of our outstanding common shares) are not among the routine matters excepted from Exchange Act Rule 14a-6, we were required but failed to file a preliminary copy of the proxy statement with the United States Securities and Exchange Commission at least 10 calendar days prior to the date on which the definitive proxy statement was sent to our Company’s shareholders, and thereby failed to give Staff at the SEC an opportunity to review and comment on the proxy statement; and (c) we proceeded under the Canadian “notice-and-access” rules for electronic posting of proxy materials rather than in compliance with Rule 14a-16 under the Exchange Act. In addition, we failed to timely comply with its obligation to file a current report on Form 8-K reporting on the results of the Meeting no later than December 19, 2019 (being the fourth business day following the date of the Meeting).

 

As a result of our failure to comply with Regulation 14A, the SEC may bring an enforcement action or commence litigation against us. If any claims or actions were to be brought against us relating to our lack of compliance with Regulation 14A, we could be subject to penalties, required to pay fines, make damages payments or settlement payments. In addition, any claims or actions could force us to expend significant financial resources to defend ourselves, could divert the attention of our management from our core business and could harm our reputation. However, we believe that the potential for any claims or actions is not probable.

 

Item 1B. Unresolved Staff Comments

 

Not applicable. 

 

ITEM 2. Properties

 

Our registered office address in Canada is Suite 6000, 1 First Canadian Place, 100 King Street West, Toronto, Ontario M5X 1E2, Canada. Our principal executive offices are located at 15315 W. Magnolia Blvd, #120, Sherman Oaks, California 91403. The monthly base rent is $5,089 for the approximately 2,196 square foot premises and the lease term is five years.

 

As of August 31, 2021, TMC Capital and POSR held the exclusive right to mine, extract and produce oil and associated hydrocarbons and minerals from oil sands containing heavy oil and bitumen under mineral leases covering approximately 1,671,91 acres near Temple Mountain in the Asphalt Ridge area in Uintah County, Utah, including approximately 320 acres held under the TMC Mineral Sublease and an additional 1,351.91 acres held under three Temple Mountain SITLA Leases. In 2019, TMC Capital acquired the operating rights under five BLM Leases covering lands consisting of approximately 5,960 acres situated in Uintah, Wayne and Garfield Counties, Utah. We have recently completed the construction and initial expansion of our Asphalt Ridge Plant, which currently covers an area of approximately 20,000 square feet and is located on three acres of land within the lands included within the TMC Mineral Sublease in Uintah County, Utah.

 

More recently, TMC Capital, POSR and Valkor entered into a reciprocal assignment exchange agreement dated October 15, 2021, under which (1) TMC and POSR assigned to Valkor all of their rights and interests in the TMC Mineral Lease (and the Short-Term Mining Lease held by Valkor) and in the Temple Mountain SITLA Lease, and (2) Valkor assigned to TMC Capital all of its rights and interests (including the record lease title and operating rights) in the Asphalt Ridge NW Leases consisting of three Utah state mineral leases located in the Asphalt Ridge Northwest area of Uintah County, Utah. Under this agreement, once the exchange of SITLA Leases is approved by SITLA, Petroteq (acting through TMC Capital) will hold three new SITLA Leases encompassing approximately 3,458.22 acres in an area called “Asphalt Ridge Northwest”.

 

In addition, under other agreements entered into between or among TMC Capital, POSR and Valkor in October 2021, (a) Valkor granted to TMC Capital the right to participate, up to a 50% working interest, in all exploratory, mining and production operations conducted by Valkor under its Short-Term Mining Lease encompassing the acreage that is subject to the TMC Mineral Sublease, and (b) TMC Capital granted to Valkor the operating rights in at or below 500 feet below the surface under the Asphalt Ridge NW Leases, with TMC Capital reserving the right to participate, at up to a 50% working interest, in all exploratory and production operations conducted by Valkor in deeper (below 500 feet subsurface or more) oil sands deposits and reservoirs.

 

With the recent reciprocal exchange of mineral leases by TMC Capital, POSR and Valkor, Petroteq (through POSR) will continue to own the Asphalt Ridge Plant in the Temple Mountain area of Asphalt Ridge. In addition, it is anticipated that Petroteq (acting through TMC Capital) and Valkor will, during the ensuing year, will determine whether a new 5,000 BPD oil sands processing plant utilizing Petroteq’s Clean Oil Recovery Technology should be constructed and operated on lands covered by the Asphalt Ridge NW Leases.

 

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Item 3. Legal Proceedings.

 

Legal Matters

 

On December 27, 2018, the Company executed and delivered: (i) a Settlement Agreement (the “Settlement Agreement”) with Redline Capital Management S.A. (“Redline”) and Momentum Asset Partners II, LLC; (ii) a secured promissory note payable to Redline in the principal amount of $6,000,000 (the “Note”) with a maturity date of 27 December 2020, bearing interest at 10% per annum; and (iii) a Security Agreement (together with the Settlement Agreement and the Note, the “Redline Agreements”) among the Company, Redline, and TMC, an indirect wholly-owned subsidiary of the Company.

 

After undertaking an in-depth analysis of the Redline Agreements in the context of the underlying transactions and events, special legal counsel to the Company has opined that the Redline Agreements are likely void and unenforceable.

 

The Company’s special legal counsel regards the possibility of Redline’s success in pursuing any claims against the Company or TMC under the Redline Agreements as less than reasonably possible and therefore no provision has been raised against these claims.

 

The Company is currently evaluating the options and remedies that are available to it to ensure that the Redline Agreements are declared as void or are rescinded and extinguished.

 

From time to time, we are the subject of litigation arising out of our normal course of operations. While we assess the merits of each lawsuit and defends itself accordingly, we may be required to incur significant expenses or devote significant resources to defend ourselves against such litigation. Accruals are made in instances where it is probable that liabilities may be incurred and where such liabilities can be reasonably estimated. Except as disclosed in this paragraph, there are no governmental, legal or arbitration proceedings (including any such proceedings which are pending or threatened of which we are aware), which may have, or have had during the 12 months prior to the date of this registration statement, a significant effect on our and/or our financial position or profitability. Although it is possible that liabilities may be incurred in instances for which no accruals have been made, management has no reason to believe that the ultimate outcome of these matters would have a significant impact on our consolidated financial position.

 

Item 4. Mine Safety Disclosures

 

We will commence open cast mining at our TMC sites once our plant is fully operational. In terms of the additional disclosure required, we provide the following information.

 

1.TMC Mining Operations:

 

TMC Capital’s mining operations are conducted primarily at Asphalt Ridge Mine #1, which is located on lands covered by the TMC Mineral Sublease in the Temple Mountain area of Utah’s Asphalt Ridge, an area located along the northern edge of the Uintah Basin and containing oil sands deposits located at or near the surface, particularly the acreage located in T5S-R22E (Section 31) where Asphalt Ridge Mine #1 is located.

 

(i)The total number of violations of mandatory health or safety standards that could significantly and substantially contribute to the cause and effect of a mine safety or health hazard under section 104 of the Federal Mine Safety and Health Act of 1977 (30 U.S.C. 814) for which the operator received a citation from the Mine Safety and Health Administration.

 

None.

 

(ii)The total number of orders issued under section 104(b) of such Act (30 U.S.C. 814(b)).

 

None.

 

(iii)The total number of citations and orders for unwarrantable failure of the mine operator to comply with mandatory health or safety standards under section 104(d) of such Act (30 U.S.C. 814(d)).4.

 

None.

 

(iv)The total number of flagrant violations under section 110(b)(2) of such Act (30 U.S.C. 820(b)(2)).

 

None.

 

39

 

 

(v)The total number of imminent danger orders issued under section 107(a) of such Act (30 U.S.C. 817(a)).

 

None.

 

(vi)The total dollar value of proposed assessments from the Mine Safety and Health Administration under such Act (30 U.S.C. 801 et seq.).

 

None.

 

(vii) The total number of mining-related fatalities.

 

None.

 

(viii) Written notifications received of:

 

a)A pattern of violations of mandatory health or safety standards that are of such nature as could have significantly and substantially contributed to the cause and effect of coal or other mine health or safety hazards under section 104(e) of such Act (30 U.S.C. 814(e)); or

 

None

 

b)The potential to have such a pattern.

 

None, that we are aware of.

 

c)Any pending legal action before the Federal Mine Safety and Health Review Commission involving such mine.

 

None

 

40

 

 

PART II.

 

Item 5. Market Price Of, And Dividends On The Registrant’s Common Equity And Related Stockholder Matters.

 

Our common shares are listed on the TSX Venture Exchange (the “TSXV”) under the symbol “PQE.V”.

 

At December 10, 2021, there were approximately 261 holders of record of our common shares.

 

Since inception, no dividends have been paid on the common shares. We intend to retain any earnings for use in its business activities, so it is not expected that any dividends on the common shares will be declared and paid in the foreseeable future.

 

As at August 31, 2021, there were 564,159,881 common shares issued and outstanding, which are listed for trading on the TSXV, share purchase warrants to purchase 73,148,824 common shares were outstanding and share purchase options to purchase 7,250,000 common shares were outstanding under the 2019 Option Plan (or its predecessors plans). See Item 6.B “Compensation – Stock Plan” for additional information regarding the 2019 Option Plan (or its predecessors plans).

 

Transfer Agent and Registrar

 

The transfer agent and registrar for our common stock is Computershare Trust Company of Canada.

 

Equity Compensation Plan Information

 

See Item 11—Executive Compensation for equity compensation plan information.

 

Recent Sales of Unregistered Securities

 

Sales of unregistered securities have been disclosed previously in the Company’s Current Reports on Form 8-K, as filed with the SEC.

 

Issuer Purchases of Equity Securities

 

There were no issuer purchases of equity securities during the fiscal year ended August 31, 2021.

 

Performance Graph and Purchases of Equity Securities

 

The Company is a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and is not required to provide the information required under this item.

 

Item 6. Selected Financial Data

 

The Company is a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and is not required to provide the information required under this item.

 

41

 

 

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

Results of Operations for the years ended August 31, 2021 and August 31, 2020

 

Net Revenue, Cost of Sales and Gross Loss

 

The Company entered into a Management and Operations Services Agreement with Valkor LLC on November 20, 2020, effective May 1, 2020. Valkor is an energy services company with expertise in oil and gas processing providing engineering, design optimization and construction as well as other services. Valkor has effected several process improvements to the Asphalt Ridge Plant and has optimized workflows. The Plant suspended operations in August 2021 but we anticipate a re-start of operations in February-March 2022.

 

During the current period, the Company entered into a Technology License Agreement with Valkor whereby Valkor paid $2,000,000 for a non-exclusive license to the Petroteq Oil Sands Recovery Technology. Since the Company has no obligation to deliver any technology or know-how on an ongoing basis to Valkor, therefore the revenue is recognizable immediately.

 

There has been no sale of hydrocarbon products during the year ended August 31, 2021 and minimal sales of $290,809 for the year ended August 31, 2020. Revenue represents the sale of hydrocarbon products for use as asphalt and to refineries that require or accept the commercial quality of our hydrocarbon products.

 

The cost of sales during the years ended August 31, 2021 and 2020 consists of: a) advance royalty payments which could be applied against production royalties for two years after the year in which the payment was made, the remaining balance of the advanced royalties were expensed during the prior year due to the termination of the TMC Mineral Lease; and b) certain production related expenses consisting of labor and maintenance expenditure.

 

Expenses

 

Expenses was $9,382,891 and $9,968,209 were incurred during the years ended August 31, 2021 and 2020, respectively, a decrease of $585,318 or 5.9%. The decrease in operating expenses is primarily due to:

 

Depletion, depreciation and amortization

 

Depletion, depreciation and amortization was $45,810 and $103,888 for the years ended August 31, 2021 and 2020, respectively, a decrease of $58,078 or 55.9%. The Company has ceased depletion, depreciation and amortization on production related assets and reserves until such time as the plant recommences operations, which is expected to occur as soon as the plant becomes operational under the Valkor Management and operations Services Agreement. The decrease in depreciation expense is primarily related to the depreciation of office leasehold improvements during the prior fiscal year.

 

Selling, general and administrative expenses

 

Selling, general and administrative expenses of $4,218,624 and $6,183,745 for the years ended August 31, 2021 and 2020, respectively, a decrease of $1,965,121 or 31.8%. Included in selling, general and administrative expenses are the following major expenses:

 

  a. Investor relations and public relations fees were $45,000 and $(92,179) for the years ended August 31, 2021 and 2020, an increase of $137,179 or 148.8%. The increase is primarily related to unfulfilled commitments by our investor relations and public relations vendors, resulting in the reversal of accrued expenses in the prior period and management concentrating its efforts and resources on developing a commercial strategy and plant analysis to determine the most appropriate course of action. 
     
  b. Professional fees were $1,596,754 and $2,614,540 for the years ended August 31, 2021 and 2020, respectively, a decrease of $1,017,786 or 38.9%. The decrease is primarily due to lower consulting expenses incurred on strategy and marketing efforts as we focused all of our attention on a commercial strategy and plant analysis to determine the most appropriate course of action. 

 

42

 

 

  c. Salaries and wages were $350,478 and $1,043,647 for the years ended August 31, 2021 and 2020, respectively, a decrease of $693,169 or 66.4%. The decrease is due to outsourcing of the operating site to a third party during the prior year.
     
  d. Share based compensation was $603,244 and $887,818 for the years ended August 31, 2021 and 2020, respectively, a decrease of $284,574 or 32.1%. The decrease is related to the prior year resignation of certain officers and directors and the expiration of option awards granted to them, resulting in the cessation of amortization related to those option awards and the full amortization of the remaining options outstanding which are now fully vested.
     
  e. Travel and promotional expenses were $700,724 and $713,662 for the years ended August 31, 2021 and 2020, respectively, a decrease of $12,938 or 1.8%. The decrease is insignificant and the expense includes some promotional expenditure incurred in the fourth quarter of the current year as management considers its strategy to commercialize the operation and its strategy to achieve this.
     
  f. Other expenses were $922,424 and $1,016,257 for the years ended August 31, 2021and 2020, respectively, a decrease of $93,833 or 9.2%. The decrease is due to a reduction in general corporate overhead.

 

Financing costs

 

Financing costs were $4,727,580 and $2,671,611 for the years ended August 31, 2021 and 2020, respectively, an increase of $2,055,969 or 77.0%. Finance costs consists of; (i)interest expense on borrowings of $1,820,459 and $1,256,985 for the years ended August 31, 2021 and 2020, respectively, an increase of $563,474, primarily attributable to penalty interest incurred on the Bay Private equity debt which was assigned to Bellridge during the current year of which a portion was converted to equity; and (ii) amortization of debt discount of $2,907,121 and $1,414,626 for the years ended August 31,2021 and 2020, respectively, an increase of $1,492,495 or 105.5%. primarily due to new debt issued during the current fiscal period with beneficial conversion features and warrants attached thereto, resulting in a substantial debt discount being recorded and amortized over the debt term.

 

Impairment of investments

 

Impairment of investments was $0 and $75,000 for the years ended August 31, 2021 and 2020, respectively. In the prior period the remaining commitment to fund our dormant Bitcoin operation was provided for upon settlement of our obligation.

 

Other expense (income), net

 

Other expenses (income), net were $1,563,902 and $746,564 for the years ended August 31, 2021 and 2020, respectively, an increase of $817,338 and represents the following:

 

  a. Loss (gain) on settlement of liabilities was $48,283 and $(524,971) for the years ended August 31, 2021 and 2020, respectively, an increase of $1,290,592. In the current fiscal year we settled debt We settled debt of $3,570,688 by the issuance of shares during the current fiscal year, realizing a small loss on settlement of $48,2383 in the prior year we settled debt of $2,533,655 by the issuance of shares, realizing a gain on settlement due to the difference between the agree per share settlement price and the market price of the shares on the date of settlement. In the prior year we incurred a loss on settlement due to the difference between the agree per share settlement price and the market price of the shares on the date of settlement.
     
  b. Loss on conversion of convertible debt was $1,033,921 and $744,918 for the years ended August 31, 2021 and 2020, respectively. During the current year and prior year several convertible notes with variable conversion rates were converted to equity at a discount to current market prices, resulting in a loss on conversion.

 

43

 

 

  c. Loss (gain ) on debt extinguishment was $416,480 and $(54,378) for the years ended August 31, 2021 and 2020, respectively. During the current year, we renegotiated the terms of several convertible notes, thereby realizing a loss on extinguishment of these notes of $416,480. In the prior year the gain was related to the amendment of terms related to certain of our debt obligations to remedy potential note defaults.
     
  d. Penalty on convertible notes was $202,908 and $610,312 for the years ended August 31, 2021 and 2020, respectively. During the current year three notes were renegotiated resulting in a penalty increase in the principal balance of the note outstanding in the aggregate sum of $202,908.  During the prior year a convertible note with an aggregate principal amount outstanding of $2,900,000 enforced a default penalty, resulting in an increase in the face value of the note by $610,312 as of the date of the default, this note was subsequently assigned to a third party and amended to rectify the maturity date default.
     
  e. Forgiveness of federal relief loans was $133,890 and $0 for the years ended August 31, 2021 and 2020, respectively. The company applied for forgiveness of three Payroll Protection Program (“PPP”) loan during the current year of which one was approved prior to year end and a second approved subsequent to year end.
     
  a. Interest income on funds advanced to third parties was $3,800 and $29,317 for the years ended August 31, 2021 and 2020, respectively, a decrease of $25,517. The decrease is primarily due to the lower balances due to the Company from third parties during the current year.

 

Derivate liability movements

 

Derivative liability movements was $(1,173,025) and $187,401 for the years ended August 31, 2021 and 2020, respectively. During the current year, several variable conversion price convertible notes were converted into equity or repaid, thereby reducing the number of convertible notes subject to derivative liabilities. The New convertible notes that the Company has entered into are predominantly at fixed conversion prices.

 

Net loss before income taxes

 

Net loss before income tax was $9,474,243 and $12,379,067 for the years ended August 31, 2021 and 2020, respectively, a decrease of $2,904,824 or 23.5%, primarily due to the revenue received from licensing fees, the reduction in selling, general and administrative expenses, the positive movement in derivative liabilities, offset by the increase in financing costs and other expense. As discussed above.

 

Net loss and comprehensive loss

 

Net loss and comprehensive loss was $9,474,243 and $12,379,067 for the years ended August 31, 2021 and 2020, respectively, a decrease of $2,904,824 or 23.5%, as discussed above.

 

Liquidity and Capital Resources

 

As at August 31, 2021, the Company had liquidity of approximately $1,012,929, which is composed entirely of cash. The Company also had a working capital deficiency of approximately $6,264,427, due primarily to increase in accounts payable, convertible debentures, related party advances made to the Company and the value of the derivative liability as of August 31, 2021. To date, we have not generated sufficient revenue to support our operating and general and administrative expenses. During the year ended August 31, 2021, we raised $3,496,949 in private placements, $635,706 in warrants exercised by investors, a further net proceeds of $3,936,402 from convertible debt and a further $267,716 from Federal relief loans. These funds were primarily used to fund operational expenditure and investments into the oil extraction technology during the current year.

 

The Company continues to work on several other financing options to secure additional financing on reasonable terms. However, should the Company not be able to secure such funding its liquidity may not be sufficient to fund its operations, debt obligations, obligations under its mineral leases and the capital needed to complete development of its Extraction Technology.

 

The Company has not paid any dividends on its common shares. The Company has no present intention of paying dividends on its common shares as it anticipates that all available funds will be reinvested to finance the growth of its business.

 

44

 

 

Capital Expenditures 

 

The Company has spent an additional $5,512,715 on capital expenditure during the current year of which $We have spent an additional $2,408,515 was settled in cash and a further $3,104,200 was settled by the issuance of common shares.

 

The company is currently considering its options on utilizing the oil extraction plant to generate revenues and determining the feasibility of constructing new plants with substantial production capability, however at significant cost, estimated to be in excess of $100 million.

 

Other Commitments and Contingencies

 

In addition to commitments otherwise reported in this MD&A, the Company’s contractual obligations as at August 31, 2021, include:

 

       Contractual cash flows 
   Carrying       1 year       More than 
(in ’000s of dollars)  amount   Total   or less   2 - 5 years   5 years 
Accounts payable  $2,106   $2,106   $2,106   $-   $- 
Accrued liabilities   1,565    1,565    1,565    -    - 
Convertible debenture   6,148    12,084    6,690    5,394    - 
Finance lease liabilities   75    81    81    -    - 
Operating lease liabilities   167    195    63    132    - 
Federal relief loans   728    1,070    292    53    725 
   $10,789   $17,101   $10,797   $5,579   $725 

 

Legal Matters

 

On December 27, 2018, the Company executed and delivered: (i) a Settlement Agreement (the “Settlement Agreement”) with Redline Capital Management S.A. (“Redline”) and Momentum Asset Partners II, LLC; (ii) a secured promissory note payable to Redline in the principal amount of $6,000,000 (the “Note”) with a maturity date of 27 December 2020, bearing interest at 10% per annum; and (iii) a Security Agreement (together with the Settlement Agreement and the Note, the “Redline Agreements”) among the Company, Redline, and TMC Capital, LLC (“TMC”), an indirect wholly-owned subsidiary of the Company.

 

After undertaking an in-depth analysis of the Redline Agreements in the context of the underlying transactions and events, special legal counsel to the Company has opined that the Redline Agreements are likely void and unenforceable.

 

The Company’s special legal counsel regards the possibility of Redline’s success in pursuing any claims against the Company or TMC under the Redline Agreements as less than reasonably possible and therefore no provision has been raised against these claims.

 

The Company is currently evaluating the options and remedies that are available to it to ensure that the Redline Agreements are declared as void or are rescinded and extinguished.

   

Recently Issued Accounting Pronouncements

 

The recent Accounting Pronouncements are fully disclosed in note 2 to our consolidated financial statements.

 

Management does not believe that any other recently issued but not yet effective accounting pronouncements, if adopted, would have an effect on the accompanying unaudited condensed consolidated financial statements.

 

Off-balance sheet arrangements

 

We do not maintain off-balance sheet arrangements, nor do we participate in non-exchange traded contracts requiring fair value accounting treatment.

 

Inflation

 

The effect of inflation on our revenue and operating results was not significant.

 

Climate Change

 

We believe that neither climate change, nor governmental regulations related to climate change, have had, or are expected to have, any material effect on our operations.

 

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

 

The Company is a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and is not required to provide the information required under this item.

 

45

 

 

Item 8. Financial Statements and Supplemental Data

 

  Page
Report of Independent Registered Public Accounting Firm F-2
Consolidated Balance Sheets F-3
Consolidated Statements of Operations F-4
Consolidated Statements of Changes in Stockholders’ Deficit F-5
Consolidated Statements of Cash Flows F-6
Notes to Consolidated Financial Statements F-7

 

F-1

 

 

 

 

Report of Independent Registered Public Accounting Firm

  

To the Shareholders and the Board of Directors of Petroteq Energy Inc.

 

Opinion on the Financial Statements

 

We have audited the accompanying consolidated statements of financial position of Petroteq Energy Inc. (the “Company”) as of August 31, 2021 and 2020, the related consolidated statements of loss and comprehensive loss, changes in shareholders’ equity and cash flows for each of the two years in the period ended August 31, 2021, and the related notes (collectively referred to as the “financial statements”).

 

In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of August 31, 2021 and 2020, and the results of its operations and its cash flows for each of the years in the two year period ended August 31, 2021, in conformity with U.S. generally accepted accounting principles.

 

Going Concern

 

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the financial statements, the Company has had recurring losses from operations and has a net capital deficiency, which raises substantial doubt about its ability to continue as a going concern. The financial statements do not include any adjustments that might result from the outcome of this uncertainty. 

 

Basis for Opinion

 

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

 

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s control over financial reporting. Accordingly, we express no such opinion.

 

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements.

 

We believe that our audits provide a reasonable basis for our opinion.

 

/s/ Hay & Watson

 

Chartered Professional Accountants

Vancouver, British Columbia, Canada

December 14, 2021

We have served as the Company’s independent auditor since 2012

 

F-2

 

 

PETROTEQ ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

As at August 31, 2021 and 2020

Expressed in US dollars

  

   Notes   August 31,
2021
   August 31,
2020
 
             
ASSETS            
Current assets            
Cash       $1,012,929   $62,404 
Trade and other receivables   4    17,303    12,830 
Ore inventory   5    16,800    14,749 
Other inventory        90,176    12,250 
Current portion of notes receivable   6    522,959    89,159 
Prepaid expenses and other current assets   1,8    2,539,120    2,043,510 
Total Current Assets        4,199,287    2,234,902 
                
Non-Current assets               
Mineral leases   9    34,911,143    34,911,143 
Property, plant and equipment   10    41,049,417    35,582,512 
Right of use asset   11    167,048    209,101 
Intangible assets   12    707,671    707,671 
Total Non-Current Assets        76,835,279    71,410,427 
Total Assets       $81,034,566   $73,645,329 
                
LIABILITIES               
Current liabilities               
Accounts payable   13   $2,105,449   $2,406,665 
Accrued expenses   13    1,564,616    1,769,749 
Ore Sale advances        283,976    283,976 
Promissory notes payable   14    23,298    8,000 
Debt   15    -    683,547 
Current portion of convertible debentures, net of discount of $529,372 and $559,178, respectively   16    5,255,874    8,227,257 
Current portion of Federal relief loans   17    291,332    74,383 
Current portion of finance lease liabilities   11    75,058    172,374 
Current portion of operating lease liabilities   11    48,376    42,053 
Related party payables   24    493,549    680,647 
Derivative liability   18    322,186    841,385 
Total Current Liabilities        10,463,714    15,190,036 
                
Non-Current liabilities               
Convertible debentures, net of discount of $3,449,338 and $613,934, respectively   16    891,662    607,067 
Federal relief loans   17    437,096    505,969 
Finance lease liabilities   11    
-
    75,058 
Operating lease liabilities   11    118,672    167,048 
Reclamation and restoration provision   17    2,970,497    2,970,497 
Total Non-Current Liabilities        4,417,927    4,325,639 
Total Liabilities        14,881,641    19,515,675 
                
Commitments and contingencies   31    
 
    
 
 
SHAREHOLDERS’ EQUITY               
Share capital   20,21,22    166,291,517    144,794,003 
Deficit        (100,138,592)   (90,664,349)
Total Shareholders’ Equity        66,152,925    54,129,654 
Total Liabilities and Shareholders’ Equity       $81,034,566   $73,645,329 

  

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

  

F-3

 

 

PETROTEQ ENERGY, INC.

CONSOLIDATED STATEMENTS OF LOSS AND COMPREHENSIVE LOSS

For the years ended August 31, 2021 and 2020

Expressed in US dollars

  

   Notes   Year ended
August 31,
2021
   Year ended
August 31,
2020
 
             
Revenue from licensing fees       $2,000,000   $
-
 
Revenues from hydrocarbon sales        
-
    290,809 
Production and maintenance costs        (2,091,352)   (1,713,638)
Advance royalty payments applied or expired   7    
-
    (988,029)
Gross Loss        (91,352)   (2,410,858)
Expenses               
Depreciation, depletion and amortization   10    45,810    103,888 
Selling, general and administrative expenses   26    4,218,624    6,183,745 
Financing costs   27    4,727,580    2,671,611 
Impairment of investments   25    
-
    75,000 
Other expenses (income), net   28    1,563,902    746,564 
Derivative liability movements   18    (1,173,025)   187,401 
Total Expenses, net        9,382,891    9,968,209 
                
Net loss before income taxes        9,474,243    12,379,067 
Income tax expense        
-
    
-
 
Net loss and Comprehensive loss        9,474,243    12,379,067 
Weighted Average Number of Shares Outstanding        419,251,881    201,401,437 
Basic and Diluted Loss per Share       $(0.02)  $(0.06)

  

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

  

F-4

 

 

PETROTEQ ENERGY, INC.

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

For the years ended August 31, 2021 and 2020

Expressed in US dollars

  

   Number of
Shares
   Share       Shareholders’ 
   Outstanding   Capital   Deficit   Equity 
Balance at August 31, 2019   176,241,746   $136,104,245   $(78,285,282)  $57,818,963 
Settlement of acquisition obligation   250,000    75,000    
-
    75,000 
Settlement of liabilities   8,540,789    1,624,130    
-
    1,624,130 
Settlement of debt   19,853,808    822,529    
-
    822,529 
Settlement of related party payables   2,356,374    86,996    
-
    86,996 
Common share subscriptions   39,001,185    3,143,374    
-
    3,143,374 
Share-based payments   190,000    38,193    
-
    38,193 
Share-based compensation   -    887,818    
-
    887,818 
Conversion of convertible debt   28,016,435    1,155,059    
-
    1,155,059 
Beneficial conversion feature on debt extinguishment   -    109,275    
-
    109,275 
Fair value of convertible debt warrants issued   -    747,384    
-
    747,384 
Net loss   -    
-
    (12,379,067)   (12,379,067)
Balance at August 31, 2020   274,450,337    144,794,003    (90,664,349)   54,129,654 
Conversion of convertible debt   171,906,658    8,656,080    
-
    8,656,080 
Settlement of liabilities   73,596,345    3,618,971    
-
    3,618,971 
Common shares subscriptions   28,490,802    3,496,949    
-
    3,496,949 
Warrants exercised   14,690,739    635,706    
-
    635,706 
Share based payments   1,025,000    62,290    
-
    62,290 
Share-based compensation   -    603,244    
-
    603,244 
Fair value of convertible debt warrants issued   -    2,280,089    
-
    2,280,089 
Fair value of beneficial conversion feature of convertible notes issued   -    2,144,185    
-
    2,144,185 
Net loss        
 
    (9,474,243)   (9,474,243)
Balance at August 31, 2021   564,159,881    166,291,517    (100,138,592)   (66,152,925)

  

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

 

F-5

 

 

PETROTEQ ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the years ended August 31, 2021 and 2020

Expressed in US dollars

 

   Year ended
August 31,
2021
   Year ended
August 31,
2020
 
         
Cash flow used for operating activities:        
Net loss  $(9,474,243)  $(12,379,067)
Adjustments to reconcile net loss to net cash used in operating activities          
Depreciation, depletion and amortization   45,810    103,888 
Amortization of debt discount   2,907,121    1,414,626 
Loss on conversion of debt   1,033,921    744,918 
Penalty on convertible debt   202,908    610,312 
Loss (gain) on debt extinguishment   330,256    (54,378)
Loss (gain) on share based settlements   48,283    (524,971)
Impairment of investments   
-
    75,000 
Share-based compensation   603,244    887,818 
Shares issued for services   62,290    38,193 
Shares issued to settle liabilities   
-
    2,055,083 
Non-cash compensation expense   
-
    553,333 
Derivative liability movement   (1,173,025)   187,401 
Forgiveness of federal relief loan   (133,890)   
-
 
Non-cash amortization of advanced royalty payments   
-
    988,029 
Other   17,751    8,315 
Changes in operating assets and liabilities:          
Accounts payable   165,273    324,909 
Accounts receivable   (434,473)   131,183 
Accrued expenses   1,750,804    118,830 
Prepaid expenses and deposits   (495,610)   65,610 
Inventory   (79,977)   188,831 
Net cash used for operating activities   (4,623,557)   (4,462,137)
           
Cash flows used for investing activities:          
Purchase and construction of property and equipment   (2,408,515)   (2,072,750)
Mineral rights deposits paid   
-
    (610,000)
Investment in notes receivable   
-
    (702,612)
Proceeds from notes receivable   
-
    1,150,522 
Advance royalty payments - net   
-
    (120,000)
Net cash used for investing activities   (2,408,515)   (2,354,840)
           
Cash flows from financing activities:          
Advances from related parties   
-
    724,902 
Repayments to related parties   (187,098)     
Proceeds on private equity placements   3,496,949    3,143,374 
Proceeds from warrants exercised   635,706    - 
Payments of  debt   (10,000)   (35,808)
Payment of finance lease liability   (172,375)   (157,388)
Proceeds from convertible debt   4,138,500    2,337,438 
Repayment of convertible debt   (202,098)   (117,500)
Proceeds from promissory notes   600,000    356,154 
Repayment of promissory notes   (584,703)   
-
 
Proceeds from Federal relief loans   267,716    577,490 
Net cash from financing activities   7,982,597    6,828,662 
           
Increase in cash   950,525    11,685 
Cash, beginning of the period   62,404    50,719 
Cash, end of the period  $1,012,929   $62,404 
           
Supplemental disclosure of cash flow information:          
Cash paid for interest  $245,459   $284,753 
Non-cash financing and investing activities:          
Value of warrants issued to convertible debt holders  $2,280,089   $747,384 
Beneficial conversion feature on debt extinguishment  $-   $109,275 
Beneficial conversion feature of convertible debt issued  $2,144,185   $
-
 
Shares issued on conversion of convertible debt  $8,656,081   $1,155,059 
Shares issued to settle debt  $3,618,971   $822,529 
Shares issued to settle related party payables  $
-
   $86,996 

     

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

  

F-6

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2021 and 2020

Expressed in US dollars

  

1.GENERAL INFORMATION

 

The Company is a holding company organized under the laws of Ontario, Canada, that is engaged in various aspects of the oil and gas industry. Our primary focus is on the development and implementation of our proprietary oil sands mining and processing technology to recover oil from surface mined bitumen deposits. Our wholly-owned subsidiary, Petroteq Energy CA, Inc., a California corporation (“PCA”), conducts our oil sands extraction business through two wholly owned operating companies, Petroteq Oil Sands Recovery, LLC, a Utah limited liability company (“POR”), and TMC Capital, LLC, a Utah limited liability company (“TMC Capital”).

 

The Company’s registered office is located at Suite 6000, 1 First Canadian Place, 100 King Street West, Toronto, Ontario, M5X 1E2, Canada and its principal operating office is located at 15315 W. Magnolia Blvd, Suite 120, Sherman Oaks, California 91403, USA.

 

Through PCA, our wholly-owned subsidiary, and PCA’s two subsidiaries POR and TMC Capital, we are in the business of exploring for, extracting and producing oil and hydrocarbon products from oil sands deposits and sediments located in the Asphalt Ridge Are of Uintah County, Utah, utilizing our proprietary extraction technology (the “Petroteq Clean Oil Recovery Technology” or “Extraction Technology”). Our primary oil sands extraction and processing operations are conducted at our Asphalt Ridge processing facility (herein the “Asphalt Ridge Plant” or “Plant”), which is owned by POR.

 

Petroteq owns the intellectual property rights to the Petroteq Clean Oil Recovery Technology which is used at our Asphalt Ridge Plant to extract and produce crude oil from oil sands utilizing a closed-loop solvent based extraction system.

 

Through its acquisition of TMC Capital in June 2015, Petroteq indirectly acquired certain mineral rights under the TMC Mineral Lease, which encompassed approximately 1,229.82 acres of land in the Temple Mountain area of Asphalt Ridge in Uintah County, Utah. On or about August 10, 2020, the TMC Mineral Lease in its original form was terminated and a new Short-Term Mining Lease, dated the same date, was entered into between Asphalt Ridge, Inc., as lessor, and Valkor, as lessee. Valkor and TMC Capital thereafter entered into a Short-Term Mining and Mineral Sublease dated August 20, 2020, in which all of Valkor’s rights and interests under the Short-Term Mining Lease were subleased to TMC Capital.

 

In June 2018, Petroteq, acting through POSR, acquired the record lease title and all of the operating rights to produce oil from oil sands resources under two mineral leases entitled “Utah State Mineral Lease for Bituminous-Asphaltic Sands”, each dated June 1, 2018, between the State of Utah’s School and Institutional Trust Land Administration (“SITLA”), as lessor, and POSR, as lessee, covering lands consisting of approximately 1,351.91 acres that largely adjoin the lands covered by the TMC Mineral Lease. In March 2019, a third SITLA Lease was acquired by Petroteq that added 39.97 acres to the mix in the Temple Mountain area of Asphalt Ridge.

 

On January 18, 2019, the Company paid $10,800,000 for the acquisition of 50% of the operating rights under U.S. federal oil and gas leases, administered by the U.S. Department of Interior’s Bureau of Land Management (“BLM”) covering approximately 5,960 gross acres (2,980 net acres) within the State of Utah. The total consideration of $10,800,000 was settled by the payment of $1,800,000 and by the issuance of 15,000,000 shares at an issue price of $0.60 per share.

 

On July 22, 2019, the Company acquired the remaining 50% of the operating rights under U.S. federal oil and gas leases, administered by the BLM covering approximately 5,960 gross acres (2,980 net acres) within the State of Utah for a total consideration of $13,000,000 settled by the issuance of 30,000,000 shares at an issue price of $0.40 per share, and cash of $1,000,000, which has not been paid to date.

 

Between March 14, 2019 and August 31, 2021, the Company made cash deposits of $1,907,000 (acting through TMC Capital, included in prepaid expenses and other current assets on the consolidated balance sheets for the acquisition of 100% of the operating rights under U.S. federal oil and gas leases in Garfield and Wayne Counties, Utah, covering approximately 8,480 gross acres in P.R. Springs and the Tar Sands Triangle within the State of Utah. The total consideration of $3,000,000 has been partially settled by a cash payment of $1,907,000, with the balance of $1,093,000 still outstanding.

  

In a letter agreement dated April 17, 2020 between the transferor of the oil and gas leases and TMC Capital, as transferee, the parties, due to uncertainty as to whether all of the 10 leases for which the Company had initially paid deposits would be considered active by BLM and included in new Combined Hydrocarbon Leases (CHLs) under the Combined Hydrocarbon Act of 1981 - agreed to adjust the purchase price as follows: (a) should all 10 of the leases be available and included in CHL’s, the Company will pay the additional $1,093,000 for the rights under the leases; (b) if only a portion of the leases ranging from 4 to 9 of the leases are available and included in CHL’s, the final purchase price of the leases will be between $1.5 million and $2.5 million; and (c) notwithstanding the above, if after a period of 7 years from April 17, 2020, at least six of the leases are not determined to be active and are not included in CHLs the Company shall be entitled to demand a refund of $1.2 million or instruct the Seller to acquire other leases in the same area for up to $1.2 million.

 

Under the terms of a Management and operations Services Agreement (“Management Agreement”) entered into between the Company and Valkor LLC, (“Valkor”) dated November 22, 2020, effective May 1, 2020, Valkor will provide overall management and operations services at the oil sands recovery plant based in Utah. The agreement is for a period of one year and is renewable automatically for an additional four years unless either party provides the other party with written notice of non-renewal at least 90 days prior to the expiration of the original or renewal term. The company will reimburse Valkor for all costs and expenses incurred, as defined in the agreement, plus a Personnel Management Fee of 12% of the personnel costs and expenses and an operations Management Fee of 5% of the operations costs and expenses.

 

F-7

 

 

Valkor will provide the Company with quarterly production reports, including the following; (i) the quantity of oil bearing ore and sediments mined, extracted and produced from each of the leases and delivered to the plant; (ii) the quantity of oil products produced, saved and sold at the plant; (iii) the quantity of consumables purchased and used or consumed in operations and (iv) the gross proceeds derived from the sale of the oil products including applicable taxes and transportation costs incurred by Valkor.

 

Valkor will also provide quarterly operating reports detailing; (i) revenue received by Valkor from oil products sold; (ii) a detailed accounting of all costs and expenses; (iii) the operations Management fee and the Personnel Management fee earned during the quarter.

 

Valkor will also produce quarterly Royalty Reports to be delivered to a third party to calculate royalties due to the holders of royalty interest under the various mineral rights leases.

 

On November 24, 2020, the Company entered into a Technology License Agreement (“License Agreement”) with Greenfield Energy, LLC (“Greenfield”), whereby the Company grants to Greenfield a non-exclusive, non-transferable license under the patent rights and know-how for use in the design, construction and operation of any and all future oil sands plants in the US. Greenfield agrees to pay a license fee of $2,000,000 for oil sands plants designed, developed and constructed by Greenfield. The parties recognize that $1,500,000 has been invested in the Petroteq Oil Sands plant based in Utah and that another $500,000 in further plant development and improvements. Greenfield will pay to the Company a 5% royalty based on net revenue received from production and disposition of licensed products, unless the licensed product is not covered by a valid claim then the royalty is reduced to 3%.

 

The Company has agreed to utilize Valkor as the exclusive provider of engineering, planning and construction for all oil sands plants built or Greenfield under this agreement, provide the fees charged by Valkor are reasonable and competitive.

 

The agreement will remain in effect from November 14, 2020 until the expiration of the last valid patent claim, unless terminated by default or bankruptcy.

 

Subsequent to year end, TMC Capital, POR and Valkor entered the Exchange Agreement, under which (1) TMC and POSR assigned to Valkor all of their rights and interests in the TMC Mineral Lease (and the Short-Term Mining Lease dated August 10, 2020 held by Valkor) and in the Temple Mountain SITLA Leases, and (2) Valkor assigned to TMC Capital all of its rights and interests (including the record lease title and operating rights) in the Asphalt Ridge NW Leases consisting of three Utah state mineral leases located in the Asphalt Ridge Northwest area of Uintah County, Utah. Under this agreement, once the exchange of SITLA Leases is approved by SITLA, Petroteq (acting through TMC Capital) will hold three new SITLA Leases encompassing approximately 3,458.22 acres in an area called “Asphalt Ridge Northwest”.

 

In addition, under other agreements entered into between or among TMC Capital, POSR and Valkor in October 2021, (a) Valkor granted to TMC Capital the right to participate, up to a 50% working interest, in all exploratory, mining and production operations conducted by Valkor under its Short-Term Mining Lease encompassing the acreage that is subject to the TMC Mineral Sublease, and (b) TMC Capital granted to Valkor the operating rights in at or below 500 feet below the surface under the Asphalt Ridge NW Leases, with TMC Capital reserving the right to participate, at up to a 50% working interest, in all exploratory and production operations conducted by Valkor in deeper (below 500 feet subsurface or more) oil sands deposits and reservoirs.

 

With the recent exchange of mineral leases by TMC Capital, POSR and Valkor, Petroteq (through POSR) will continue to own the Asphalt Ridge Plant in the Temple Mountain area of Asphalt Ridge. It is anticipated that Petroteq (acting through TMC Capital) and Valkor will, during the ensuing year, will determine whether a new 5,000 BPD oil sands processing plant utilizing Petroteq’s Clean Oil Recovery Technology should be constructed and operated on lands covered by the Asphalt Ridge NW Leases.

 

The assignment of the Temple Mountain SITLA leases by Petroteq’s subsidiaries to Valkor, and Valkor’s assignment of the Asphalt Ridge NW Leases to TMC Capital, are subject to approval by SITLA before the transactions are considered final. See Subsequent events note 34.

 

F-8

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2021 and 2020

Expressed in US dollars

 

2.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

  

(a)Basis of preparation

 

The consolidated financial statements have been prepared in accordance with United States generally accepted accounting policies (“US GAAP”) and have been prepared on a historical cost basis except for certain financial assets and financial liabilities which are measured at fair value. The Company’s reporting currency and the functional currency of all of its operations is the U.S. dollar, as it is the principal currency of the primary economic environment in which the Company operates.

 

The Company is an “SEC Issuer” as defined under National Instrument 52-107 “Accounting Principles and Audit Standards” and is relying on the exemptions of Section 3.7 of NI 52-107 and of Section 1.4(8) of the Companion Policy to National Instrument 51-102 “Continuous Disclosure Obligations” (“NI 51-102CP”) which permits the Company to prepare its financial statements in accord with U.S. GAAP.

  

The consolidated financial statements were authorized for issue by the Board of Directors on December 14, 2021. 

 

(b)Consolidation

 

The consolidated financial statements include the financial statements of the Company and its subsidiaries in which it has at least a majority voting interest. All significant inter-company accounts and transactions have been eliminated in the consolidated financial statements. The entities included in these consolidated financial statements are as follows:

  

Entity  % of
Ownership
   Jurisdiction
Petroteq Energy Inc.   Parent   Canada
Petroteq Energy CA, Inc.   100%  USA
Petroteq Oil Recovery, LLC (Previously Petroteq Oil Sands Recovery, LLC)   100%  USA
TMC Capital, LLC   100%  USA
Petrobloq, LLC   100%  USA

  

An associate is an entity over which the Company has significant influence and that is neither a subsidiary nor an interest in a joint venture. Significant influence is the power to participate in the financial and operating policy decisions of the investee but is not control or joint control over those policies.

  

The results and assets and liabilities of associates are incorporated in the consolidated financial statements using the equity method of accounting. Under the equity method, investment in associate is carried in the consolidated statement of financial position at cost as adjusted for changes in the Company’s share of the net assets of the associate, less any impairment in the value of the investment. Losses of an associate in excess of the Company’s interest in that associate are not recognized. Additional losses are provided for, and a liability is recognized, only to the extent that the Company has incurred legal or constructive obligations or made payment on behalf of the associate.

 

The Company has accounted for its investment in Accord GR Energy, Inc. (“Accord”) on the equity basis since March 1, 2017. The Company had previously owned a controlling interest in Accord and the results were consolidated in the Company’s financial statements. However, subsequent equity subscriptions into Accord reduced the Company’s ownership to 44.7% as of March 1, 2017 and the results of Accord were deconsolidated from that date. As of August 31, 2020, the Company has impaired 100% of the remaining investment in Accord due to inactivity and a lack of adequate investment in Accord to progress to commercial production and viability.

  

F-9

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2021 and 2020

Expressed in US dollars

  

2.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

  

(c)Estimates

 

The preparation of these consolidated financial statements in accordance with US GAAP requires the Company to make judgements, estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. The Company continually evaluates its estimates, including those related to recovery of long-lived assets. The Company bases its estimates on historical experience and on other assumptions that it believes to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Any future changes to these estimates and assumptions could cause a material change to the Company’s reported amounts of revenues, expenses, assets and liabilities. Actual results may differ from these estimates under different assumptions or conditions. The Company believes the following critical accounting policies affect its more significant judgments and estimates used in the preparation of the consolidated financial statements. Significant estimates include the following;

 

the useful lives and depreciation rates for intangible assets and property, plant and equipment;

 

the carrying and fair value of oil and gas properties and product and equipment inventories;

 

All provisions;

 

the fair value of reporting units and the related assessment of goodwill for impairment, if applicable;

 

the fair value of intangibles other than goodwill;

 

income taxes and the recoverability of deferred tax assets

 

legal and environmental risks and exposures; and

 

general credit risks associated with receivables, if any.

  

(d)Foreign currency translation adjustments

  

The Company’s reporting currency and the functional currency of all its operations is the U.S. dollar. Assets and liabilities of the Canadian parent company are translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period. Income, expenses and cash flows are translated using an average exchange rate during the reporting period. Since the reporting currency as well as the functional currency of all entities is the U.S. Dollar there is no translation difference recorded.

   

(e)Revenue recognition

  

The Company recognizes revenue in terms of ASC 606 – Revenue from Contracts with Customers (ASC 606).

 

Revenue transactions are assessed using a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration in exchange for those goods or services. The five steps are as follows:

 

i.identify the contract with a customer;

 

ii.identify the performance obligations in the contract;

 

iii.determine the transaction price;

 

iv.allocate the transaction price to performance obligations in the contract; and

 

v.recognize revenue as the performance obligation is satisfied.

 

F-10

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2021 and 2020

Expressed in US dollars

  

2.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

  

(e)Revenue recognition (continued)

  

Revenue from hydrocarbon sales

  

Revenue from hydrocarbon sales include the sale of hydrocarbon products and are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, control has transferred and collectability of the revenue is probable. The Company’s performance obligations are satisfied at a point in time. This occurs when control is transferred to the purchaser upon delivery of contract specified production volumes at a specified point. The transaction price used to recognize revenue is a function of the contract billing terms. Revenue is invoiced, if required, upon delivery based on volumes at contractually based rates with payment typically received within 30 days after invoice date. Taxes assessed by governmental authorities on hydrocarbon sales, if any, are not included in such revenues, but are presented separately in the consolidated comprehensive statements of loss and comprehensive loss.

 

Transaction price allocated to remaining performance obligations

 

The Company does not anticipate entering into long-term supply contracts, rather it expects all contracts to be short-term in nature with a contract term of one year or less. The Company intends applying the practical expedient in ASC 606 exempting the 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 contracts with terms greater than one year, the Company will apply the practical expedient in ASC 606 exempting the disclosure of the transaction price allocated to remaining performance obligations if there is any variable consideration to be allocated entirely to a wholly unsatisfied performance obligation. The Company anticipates that with respect to the contracts it will enter into, each unit of product will typically represent a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

  

Contract balances

  

The Company does not anticipate that it will receive cash relating to future performance obligations. However if such cash is received, the revenue will be deferred and recognized when all revenue recognition criteria are met.

  

Disaggregation of revenue

 

The Company has limited revenues to date. Disaggregation of revenue disclosures can be found in Note 30. 

  

Customers

  

The Company anticipates that it will have a limited number of customers which will make up the bulk of its revenues due to the nature of the oil and gas industry.

 

(f)General and administrative expenses

  

General and administrative expenses will be presented net of any working interest owners, if any, of the oil and gas properties owned or leased by the Company. 

  

F-11

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2021 and 2020

Expressed in US dollars

 

2.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

  

(g)Share-based payments

 

The Company may grant stock options to directors, officers, employees and others providing similar services. The fair value of these stock options is measured at grant date using the Black-Scholes option pricing model taking into account the terms and conditions upon which the options were granted. Share-based compensation expense is recognized on a straight-line basis over the period during which the options vest, with a corresponding increase in equity.

 

The Company may also grant equity instruments to consultants and other parties in exchange for goods and services. Such instruments are measured at the fair value of the goods and services received on the date they are received and are recorded as share-based compensation expense with a corresponding increase in equity. If the fair value of the goods and services received are not reliably determinable, their fair value is measured by reference to the fair value of the equity instruments granted.

  

(h)Income taxes

  

The Company utilizes ASC 740, Accounting for Income Taxes, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred income taxes are recognized for the tax consequences in future years of differences between the tax bases of assets and liabilities and their financial reporting amounts at each period end based on enacted tax laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable income. Valuation allowances are established, when necessary, to reduce deferred tax assets to the amount expected to be realized.

  

The Company accounts for uncertain tax positions in accordance with the provisions of ASC 740, “Income Taxes”. Accounting guidance addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the consolidated financial statements, under which a company may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position.

  

The tax benefits recognized in the consolidated financial statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. Accordingly, the Company would report a liability for unrecognized tax benefits resulting from uncertain tax positions taken or expected to be taken in a tax return. The Company elects to recognize any interest and penalties, if any, related to unrecognized tax benefits in tax expense.

  

(i)Net income (loss) per share

 

Basic net income (loss) per share is computed on the basis of the weighted average number of common shares outstanding during the period.

  

Diluted net income (loss) per share is computed on the basis of the weighted average number of common shares and common share equivalents outstanding. Dilutive securities having an anti-dilutive effect on diluted net income (loss) per share are excluded from the calculation.

 

Dilution is computed by applying the treasury stock method for stock options and share purchase warrants. Under this method, “in-the-money” stock options and share purchase warrants are assumed to be exercised at the beginning of the period (or at the time of issuance, if later), and as if funds obtained thereby were used to purchase common shares at the average market price during the period.

  

F-12

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2021 and 2020

Expressed in US dollars

  

2.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

  

(j)Cash and cash equivalents

  

The Company considers all highly liquid investments with original contractual maturities of three months or less to be cash equivalents.

  

(k)Accounts receivable

  

The Company had minimal sales during the period of which all proceeds were collected therefore there are no accounts receivable balances.

  

(l)Oil and gas property and equipment

  

The Company follows the successful efforts method of accounting for its oil and gas properties. Exploration costs, such as exploratory geological and geophysical costs, and costs associated with delay rentals and exploration overhead are charged against earnings as incurred. Costs of successful exploratory efforts along with acquisition costs and the costs of development of surface mining sites are capitalized. 

 

Site development costs are initially capitalized, or suspended, pending the determination of proved reserves. If proved reserves are found, site development costs remain capitalized as proved properties. Costs of unsuccessful site developments are charged to exploration expense. For site development costs that find reserves that cannot be classified as proved when development is completed, costs continue to be capitalized as suspended exploratory site development costs if there have been sufficient reserves found to justify completion as a producing site and sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. If management determines that future appraisal development activities are unlikely to occur, associated suspended exploratory development costs are expensed. In some instances, this determination may take longer than one year. The Company reviews the status of all suspended exploratory site development costs quarterly.

  

Capitalized costs of proved oil and gas properties are depleted by an equivalent unit-of-production method. Proved leasehold acquisition costs, less accumulated amortization, are depleted over total proved reserves, which includes proved undeveloped reserves. Capitalized costs of related equipment and facilities, including estimated asset retirement costs, net of estimated salvage values and less accumulated amortization are depreciated over proved developed reserves associated with those capitalized costs. Depletion is calculated by applying the DD&A rate (amortizable base divided by beginning of period proved reserves) to current period production.

  

Costs associated with unproved properties are excluded from the depletion calculation until it is determined whether or not proved reserves can be assigned to such properties. The Company assesses its unproved properties for impairment annually, or more frequently if events or changes in circumstances dictate that the carrying value of those assets may not be recoverable.

  

Proved properties will be assessed for impairment annually, or more frequently if events or changes in circumstances dictate that the carrying value of those assets may not be recoverable. Individual assets are grouped for impairment purposes based on a common operating location. If there is an indication the carrying amount of an asset may not be recovered, the asset is assessed for potential impairment by management through an established process. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset, the carrying value is written down to estimated fair value. Because there is usually a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants or by comparable transactions. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments of future production volumes, commodity prices, operating costs, and capital investment plans, considering all available information at the date of review. 

  

F-13

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2021 and 2020

Expressed in US dollars

  

2.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

 

(l)Oil and gas property and equipment (continued)

 

Gains or losses are recorded for sales or dispositions of oil and gas properties which constitute an entire common operating field or which result in a significant alteration of the common operating field’s DD&A rate. These gains and losses are classified as asset dispositions in the accompanying consolidated statements of loss and comprehensive loss. Partial common operating field sales or dispositions deemed not to significantly alter the DD&A rates are generally accounted for as adjustments to capitalized costs with no gain or loss recognized.

 

The Company capitalizes interest costs incurred and attributable to material unproved oil and gas properties and major development projects of oil and gas properties.

  

(m)Other property and equipment

  

Depreciation and amortization of other property and equipment, including corporate and leasehold improvements, are provided using the straight-line method based on estimated useful lives ranging from three to ten years. Interest costs incurred and attributable to major corporate construction projects are also capitalized.

 

(n)Asset retirement obligations and environmental liabilities

  

The Company recognizes liabilities for retirement obligations associated with tangible long-lived assets, such as producing sites when there is a legal obligation associated with the retirement of such assets and the amount can be reasonably estimated. The initial measurement of an asset retirement obligation is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment on the consolidated balance sheet. When the assumptions used to estimate a recorded asset retirement obligation change, a revision is recorded to both the asset retirement obligation and the asset retirement cost. The Company’s asset retirement obligations also include estimated environmental remediation costs which arise from normal operations and are associated with the retirement of such long-lived assets. The asset retirement cost is depreciated using a systematic and rational method similar to that used for the associated property and equipment.

  

(o)Commitments and contingencies

  

Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Liabilities for environmental remediation or restoration claims resulting from allegations of improper operation of assets are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Expenditures related to such environmental matters are expensed or capitalized in accordance with the Company’s accounting policy for property and equipment.

  

(p)Fair value measurements

  

Certain of the Company’s assets and liabilities are measured at fair value at each reporting date. Fair value represents the price that would be received to sell the asset or paid to transfer the liability in an orderly transaction between market participants. This price is commonly referred to as the “exit price.” Fair value measurements are classified according to a hierarchy that prioritizes the inputs underlying the valuation techniques. This hierarchy consists of three broad levels:

 

Level 1 – Inputs consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. When available, the Company measures fair value using Level 1 inputs because they generally provide the most reliable evidence of fair value.

 

Level 2 – Inputs consist of quoted prices that are generally observable for the asset or liability. Common examples of Level 2 inputs include quoted prices for similar assets and liabilities in active markets or quoted prices for identical assets and liabilities in markets not considered to be active.

 

Level 3 – Inputs are not observable from objective sources and have the lowest priority. The most common Level 3 fair value measurement is an internally developed cash flow model.

  

F-14

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2021 and 2020

Expressed in US dollars

  

2.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

  

(q)Comparative amounts

  

The comparative amounts presented in these consolidated financial statements have been reclassified where necessary to conform to the presentation used in the current year.

  

(r)Recent accounting standards

  

Issued accounting standards not yet adopted

 

The Company will evaluate the applicability of the following issued accounting standards and intends to adopt those which are applicable to its activities.

 

In August 2020, the FASB issued ASU No. 2020-06, debt with Conversion and Other Options (subtopic 470-20): and Derivatives and Hedging – Contracts in Entity’s Own Equity (Subtopic 815-40). Certain accounting models for convertible debt instruments with beneficial conversion features or cash conversion features are removed from the guidance and for equity instruments the contracts affected are free standing instruments and embedded features that are accounted for as derivatives, the settlement assessment was simplified by removing certain settlement requirements.

 

This ASU is effective for fiscal years and interim periods beginning after December 15, 2021.

 

The effects of this ASU on the Company’s condensed consolidated financial statements is currently being assessed and is expected to have an immaterial impact on the financial statements.

  

Any new accounting standards, not disclosed above, that have been issued or proposed by FASB that do not require adoption until a future date are not expected to have a material impact on the financial statements upon adoption.

 

3.GOING CONCERN

 

The Company has incurred losses for several years and, at August 31, 2021, has an accumulated deficit of $100,138,592, (August 31, 2020 - $90,664,349) and working capital (deficiency) of $6,264,427 (August 31, 2020 - $12,955,134). These consolidated financial statements have been prepared on the basis that the Company will be able to realize its assets and discharge its liabilities in the normal course of business. The ability of the Company to continue as a going concern is dependent on obtaining additional financing, which it is currently in the process of obtaining. There is a risk that additional financing will not be available on a timely basis or on terms acceptable to the Company. These consolidated financial statements do not reflect the adjustments or reclassifications that would be necessary if the Company were unable to continue operations in the normal course of business.

 

F-15

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2021 and 2020

Expressed in US dollars

 

4.ACCOUNTS RECEIVABLE

 

The Company’s accounts receivables consist of:

  

   August 31,
2021
   August 31,
2020
 
           
Goods and services tax receivable  $17,303   $12,830 

 

Information about the Company’s exposure to credit risks for trade and other receivables is included in Note 31(a).

 

5.ORE INVENTORY

 

On June 1, 2015, the Company acquired a 100% interest in TMC Capital LLC (“TMC”), which through a sub-lease with Valkor, LLC (“Valkor”) held the rights to mine ore from the Asphalt Ridge deposit, refer subsequent events note 34. The mining and crushing of the bituminous sands has been contracted to an independent third party.

 

During the year ended August 31, 2021, the cost of mining, hauling and crushing the ore, amounting to $0 (2020 - $162,043), was recorded as the cost of the crushed ore inventory.

  

6.NOTES RECEIVABLE

  

The Company’s notes receivables consist of:

  

          Principal due   Principal due 
   Maturity Date  Interest
Rate
   August 31,
2021
   August 31, 
2020
 
                
Manhatten Enterprises  March 16, 2020         5%  $76,000   $76,000 
Deweast Limited  January 31, 2022   
-
    200,000    
-
 
Unhide Inc  September 30, 2021   
-
    230,000    
-
 
Interest accrued           16,959    13,159 
           $522,959   $89,159 
                   
Disclosed as follows:                  
Current portion          $522,959   $89,159 

 

Manhatten Enterprises 

 

The Company advanced Manhatten Enterprises the sum of $76,000 pursuant to a promissory note on March 16, 2017. The note, which bears interest at 5% per annum, matured on March 16, 2020. The Note has reached its maturity date, management has undertaken to enter into a new agreement or extend the terms of the existing agreement, there have been no successful negotiations to date.

 

Deweast Limited

 

On August 31, 2021, in terms of an unsecured loan agreement entered into with Deweast Limited (“Deweast”) the Company advanced the sum of $200,000 to Deweast, maturing on January 31, 2022. On or before the maturity date Deweast agreed to repay the Company $220,000. In the event that Deweast fails to repay the amount due on maturity date the full balance owing at maturity will accrue interest at 10% per annum until paid in full.

 

Unhide, Inc.

 

On August 31, 2021, in terms of an unsecured loan agreement entered into with Unhide Inc. (“Unhide”) the Company advanced the sum of $230,000 to Unhid, maturing on September 30, 2021. On or before the maturity date Unhide agreed to repay the Company $238,000. In the event that Unhide fails to repay the amount due on maturity date the full balance owing at maturity will accrue interest at 10% per annum until paid in full.

 

F-16

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2021 and 2020

Expressed in US dollars

 

7.ADVANCED ROYALTY PAYMENTS

  

Advance royalty payments to Asphalt Ridge, Inc.

  

During the year ended August 31, 2015, the Company acquired TMC, which has a mining and mineral lease with Asphalt Ridge, Inc. (the “TMC Mineral Lease”) (Note 8(a)). The mining and mineral lease with Asphalt Ridge, Inc. required the Company to make minimum advance royalty payments which could be used to offset future production royalties for a maximum of two years following the year the advance royalty payment was made.

 

As at August 31, 2020, the Company has paid advance royalties of $2,370,336 to the lease holder, of which all had been expensed as of August 31, 2020 due to the termination of the TMC Mineral Lease as discussed in note 8(a) below.

 

8.PREPAYMENTS AND OTHER CURRENT ASSETS

  

Included in prepayments and other current assets are cash deposits of $1,907,000 (acting through its wholly owned subsidiary, TMC Capital LLC (“TMC”), for the acquisition of 100% of the operating rights under U.S. federal oil and gas leases, administered by the U.S. department of Interiors’ Bureau of Land Management in Garfield and Wayne Counties covering approximately 8,480 gross acres in P.R. Springs and the Tar Sands Triangle within the State of Utah. The total consideration of $3,000,000 has been partially settled by a cash payment of $1,907,000, with the balance of $1,093,000 still outstanding.

  

In terms of a letter agreement dated April 17, 2020 between the transferor of the oil and gas leases and TMC, as transferee, due to uncertainty as to whether all of the 10 leases which the Company had initially paid deposits for are available, an adjustment to the purchase price has been agreed upon as follows: (i) should all 10 of the leases be available, the Company will pay the additional $1,093,000 for the rights under the leases; (ii) if only a portion of the leases ranging from 4 to 9 of the leases are available, the Company will adjust the final purchase price of the leases to between $1.5 million and $2.5 million; and (iii) notwithstanding the above, if after a period of 7 years from April 17, 2020, if at least six of the leases are not available to the Company, then the Company may demand a refund of $1.2 million or instruct the Seller to acquire other leases in the same area for up to $1.2 million.

 

In addition, included in prepayments and other current assets is an amount of $500,000 paid during the period July 8, 2021 and August 11, 2021, in terms of the agreements governing reciprocal assignment of mineral leases dated as of October 15, 2021 under which TMC and POR agreed to; (i) assign all of its interest in the TMC mineral leases and the short term mining lease dated August 10, 2020 as amended on July 1, 2021, sub-leased from Valkor and two mineral leases entered into between the State of Utah’s School and Institutional Trust Land Administration (“SITLA”), as lessor, and POR, as lessee, covering lands in Asphalt Ridge that largely adjoin the lands held under the TMC Mineral Lease and Valkor agreed to assign to TMC Capital LLC, the record lease title and all of its rights and interest under three SITLA Utah state oil sands leases located in an area referred to as “Asphalt Ridge Northwest” in Uintah County Utah.

 

The assignment of the SITLA leases are subject to approval by SITLA before the agreement comes into effect. See Subsequent events note 34.

 

F-17

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2021 and 2020

Expressed in US dollars

 

9.MINERAL LEASES

 

   TMC   SITLA   BLM     
   Mineral   Mineral   Mineral     
   Lease   Lease   Lease   Total 
Cost                
August 31, 2019  $11,091,388   $19,755   $23,800,000   $34,911,143 
Additions   
-
    
-
    
-
    
-
 
August 31, 2020   11,091,388    19,755    23,800,000    34,911,143 
Additions   
-
    
-
    
-
    
-
 
August 31, 2021  $11,091,388   $19,755   $23,800,000   $34,911,143 
                     
Accumulated Amortization                    
August 31, 2019, 2020 and 2021  $
-
   $
-
   $
-
   $
-
 
                     
Carrying Amounts                    
August 31, 2019  $11,091,388   $19,755   $23,800.000   $34,911,143 
August 31, 2020  $11,091,388   $19,755   $23,800,000   $34,911,143 
August 31, 2021  $11,091,388   $19,755   $23,800,000   $34,911,143 

 

Subsequent to year end, the Company acting through its indirect wholly owned subsidiaries TMC and Petroteq Oil Recovery, LLC (“POR”), and Valkor Energy LLC (“Valkor”), have entered into an agreement governing reciprocal assignment of mineral leases dated as of October 15, 2021 under which TMC and POR agreed to assign all of its interest in the TMC mineral leases and the short term mining lease dated august 10, 2020 as amended on July 1, 2021, sub-leased from Valkor and two mineral leases entered into between the State of Utah’s School and Institutional Trust Land Administration (“SITLA”), as lessor, and POR, as lessee, covering lands in Asphalt Ridge that largely adjoin the lands held under the TMC Mineral Lease and Valkor agreed to assign to TMC Capital LLC, the record lease title and all of its rights and interest under three SITLA Utah state oil sands leases located in an area referred to as “Asphalt Ridge Northwest” in Uintah County Utah.

 

In addition, the Corporation, acting through TMC, and Valkor entered into an Agreement and Assignment of Participation Rights in Mineral Leases and Properties, dated as of October 15, 2021, in which Valkor agreed to grant to TMC a right to participate in any oil sands development operations conducted by Valkor in the future on or within the privately owned Temple Mountain Lease; and the Company, acting through TMC and Valkor entered into an Agreement Governing Assignment of Operating Rights Under Utah State Mineral Leases, dated as of October 15, 2021, in under which TMC agreed to assign to Valkor all of the operating rights under the Asphalt Ridge North West Leases at depths and intervals located 500 feet or more below the surface, with TMC reserving the right to participate in (a) any exploratory or production operation conducted by Valkor at the deeper depths or intervals (below 500 feet from the surface) at and with up to a 50% working interest, and (b) in any oil sands processing plant proposed by either party at up to a 50% ownership interest in any such plant.

 

The assignment of the SITLA leases are subject to approval by SITLA before the agreement comes into effect. See Subsequent events note 34.

 

F-18

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2021 and 2020

Expressed in US dollars

      

9.MINERAL LEASES (continued)

 

(a)TMC Mineral Lease

 

Effective August 10, 2020, the TMC mineral lease was terminated and a new Short-Term Mining Lease agreement between Valkor and Asphalt Ridge, Inc was entered into with a back to back Short-Term Mining and Mineral sub-lease entered into between Valkor and TMC, whereby all of the rights and obligations of the lease were sub-let to TMC.

 

The salient terms of the lease were as follows:

 

  1. The exclusive right and privilege during the term of this Sublease to explore for and mine by any methods now known or hereafter developed, extract and sell or otherwise dispose of, any and all asphalt, bitumen, maltha, tar sands, oil sands (“Tar Sands”) and any and all other minerals of whatever kind or nature which are associated with or contained in any Tar Sands deposit, whether hydrocarbon, metalliferous, non-metalliferous or otherwise, including, but not limited to, gold, silver, platinum, sand and clays on and in the Property, and whether heretofore known or hereafter discovered (collectively, “Minerals”), from the ground surface to a depth of 3,000 feet above Mean Sea level (MSL), together with the products and byproducts of the processing of the Minerals, and together with the right to use so much of the surface of the Property as may be necessary in the exercise of said rights and in furtherance of the purposes expressed herein, including ingress and egress, and together with the right to construct on the Property such improvements as may be reasonably necessary to the exploration for and the mining, extraction, removal, processing, beneficiating, sale or other disposition of the Minerals, but not including the construction of any new roads without the prior written consent of Sublessor; and

 

  2. The right to use any or all of the Water Rights at any time during the term of this Sublease in conducting its activities as provided for herein; provided that approval of change applications may need to be obtained in order to allow use of the Water Rights on the Property for mining purposes.

 

  3. The term of the sub-lease is for the period ending June 30, 2021 unless the Short Term Mining Lease between Valkor and Asphalt Ridge is terminated earlier.

 

  4. During the Term and subject to the Lessor Reserved Rights, Sublessee shall have the right to explore, develop, mine, drill, pump, process, produce and market the Minerals in, on, or under the Property, including any existing stockpiles or dumps, whether by drilling, surface, strip, contour, quarry, bench, underground, solution, in situ or other mining methods, and in connection therewith, Sublessee shall have the right to conduct the following activities and operations (“Operations”) on the Property in accordance with the terms of this Sublease and applicable laws and regulations:

 

a.To mine, process, mill, beneficiate, treat, concentrate, extract, refine, leach, convert, upgrade, prepare for market, any and all Minerals mined or otherwise extracted from the Property;

 

b.To temporarily store or permanently dispose on the Property Minerals, water, waste or other materials resulting from Operations on the Property;

 

c.to use and develop any and all ditches, flumes, water and Water Rights and appurtenant to the Property; and

 

d.to use so much of the surface and surface resources of the Property as may be reasonably necessary in the exercise of said rights, or which Sublessee may deem desirable or convenient, including rights of ingress and egress in connection with its operations on the Property. During the term of the lease the sub-lessee has the right to use any or all of the Water Rights at any time during the term of this Sublease in conducting its activities as provided for herein; provided that approval of change applications may need to be obtained in order to allow use of the Water Rights on the Property for mining purposes.

 

F-19

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2021 and 2020

Expressed in US dollars

    

9.MINERAL LEASES (continued)

  

(a)TMC Mineral Lease (continued)

 

  5. TMC will pay Valkor the sum of $25,000 on lease commencement, and thereafter $15,000 per month until expiration of the lease

 

  6. TMC will pay a production royalty as follows:

 

a.For “Bitumen Product” produced from Tar Sands mined or otherwise extracted from the Property shall be eight percent (8%) of the gross sales revenue received by Sublessee from the sale of such Bitumen Product at the Property. As used herein, the term “Bitumen Product” means naturally occurring oil in the Tar Sands that is sold in whatever form, including run-of-mine, screened, processed, or after the addition of any additives and/or upgrading of the Bitumen Product

 

b.The Production Royalty on all other Minerals produced from Bitumen Product mined or otherwise extracted from the Property and sold shall be eight percent (8%) of the gross sales revenue received by Sublessee. Subject to the provisions of Paragraph 1, wherein sales of products and byproducts are wholly accounted for, should sales occur to a third party purchaser that is engaged in marketing a variety of products or by-products made from such materials, payments to Sublessor may vary. If Sublessee’s receipts are measurably greater than comparable sales by others of similar products or byproducts which may be due to the nature of high end by-products such as frac sands produced and sold by the third party, the Production Royalty to Sublessor shall be the greater of a 5% royalty on the gross value of the product and by-products sold by the third party or 50% of the gross revenue received by Sublessee from the sale of such products or byproducts, as the case may be.

 

c.The Production Royalty on oil and gas, and associated hydrocarbons produced by Sublessee using standard oil and gas drilling recovery techniques above 3000 feet MSL and sold shall be 1/6 of the gross market value.

 

d.Any sales of Minerals to third parties shall be of such a nature that the sales price adequately represents the market value of all potential products or by-products.

 

e.Minerals shall be deemed sold at the time they leave the Property or at the time the Minerals are transferred by Sublessee to an Affiliate. As used herein, “Affiliate” means any business entity which, directly or indirectly, is owned or controlled by Sublessee or owns or controls Sublessee, or any entity or firm acquiring Minerals from Sublessee otherwise than at arm’s-length.

 

  7. Prior to commencing any Operations, Sublessee shall have obtained final approval of all necessary mining and reclamation plans from the Utah Division of Oil, Gas and Mining, or its successor agency (the “Division”) authorizing Sublessee’s Operations and shall have posted with and obtained approval from the Division of a surety bond or other financial guarantee (“Reclamation Surety”) in the amount and form acceptable to the Division and sufficient to guarantee Sublessee’s performance of reclamation in accordance with Utah laws and regulations. The amount of the surety bond or financial guarantee shall be periodically reviewed in accordance with Division’s regulations and, if the Division directs, increased or otherwise modified as directed by the Division. Sublessee shall keep Sublessor fully informed as to reclamation costs and bonding requirements and Sublessor’s approval of the bond amount shall be required. Sublessor will not unreasonably withhold such approval.

 

  8. Under the terms of the Lease, Asphalt Ridge , Inc. has reserved the right at any time during the term of the Lease to convey all or part of the Property or the Water Rights, or rights therein, subject to the Lease and shall give Sublessor Notice of any such conveyance. This Sublease shall be subject to the right reserved by the Lessor as described herein. Upon Sublessor’s receipt of any sale or conveyance of the Property by Lessor, Sublessor shall promptly notify Sublessee in writing of any such conveyance.

 

F-20

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2021 and 2020

Expressed in US dollars

    

9.MINERAL LEASES (continued)

 

(b)SITLA Mineral Lease (Petroteq Oil Recovery, LLC mineral lease)

 

On June 1, 2018, the Company acquired mineral rights under two mineral leases entered into between the State of Utah’s School and Institutional Trust Land Administration (“SITLA”), as lessor, and POR, as lessee, covering lands in Asphalt Ridge that largely adjoin the lands held under the TMC Mineral Lease (collectively, the “SITLA Mineral Leases”). The SITLA Mineral Leases are valid until May 30, 2028 and have rights for extensions based on reasonable production. The leases remain in effect beyond the original lease term so long as mining and sale of the tar sands are continued and sufficient to cover operating costs of the Company.

 

Advanced royalty of $10 per acre are due annually each year the lease remains in effect and can be applied against actual production royalties. The advanced royalty is subject to price adjustment by the lessor after the tenth year of the lease and then at the end of each period of five years thereafter.

 

Production royalties payable are 8% of the market price of marketable product or products produced from the tar sands and sold under arm’s length contract of sale. Production royalties have a minimum of $3 per barrel of produced substance and may be increased by the lessor after the first ten years of production at a maximum rate of 1% per year and up to 12.5%.

 

(c)BLM Mineral Lease

 

On January 18, 2019, the Company paid $10,800,000 for the acquisition of 50% of the operating rights under U.S. federal oil and gas leases, administered by the U.S. Department of Interior’s Bureau of Land Management (“BLM”) covering approximately 5,960 gross acres (2,980 net acres) within the State of Utah. The total consideration of $10,800,000 was settled by a cash payment of $1,800,000 and by the issuance of 15,000,000 shares at an issue price of $0.60 per share, amounting to $9,000,000.

 

On July 22, 2019, the Company acquired the remaining 50% of the operating rights under U.S. federal oil and gas leases, administered by the BLM covering approximately 5,960 gross acres (2,980 net acres) within the State of Utah, for a total consideration of $13,000,000 settled by the issuance of 30,000,000 shares at an issue price of $0.40 per share, amounting to $12,000,000 and cash of $1,000,000, of which $100,000 has not been paid to date.

 

10.PROPERTY, PLANT AND EQUIPMENT

  

   Oil
Extraction
Plant
   Other
Property and
Equipment
   Total 
Cost            
August 31, 2019  $35,555,827    438,168    35,993,995 
Additions   2,072,058    692    2,072,750 
August 31, 2020   37,627,885   $438,860   $38,066,745 
Additions   5,512,715    
-
    5,512,715 
August 31, 2021  $43,140,600   $438,860   $43,579,460 
                
Accumulated Amortization               
August 31, 2019  $2,148,214    232,131    2,380,345 
Additions   
-
    103,888    103,888 
August 31, 2020   2,148,214   $336,019   $2,484,233 
Additions   
-
    45,810    45,810 
August 31, 2021  $2,148,214   $381,829   $2,530,043 
                
Carrying Amount               
August 31, 2019  $33,407,613   $206,037   $33,613,650 
August 31, 2020  $35,479,671   $102,841   $35,582,512 
August 31, 2021  $40,992,386   $51,562   $41,049,417 

 

F-21

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2021 and 2020

Expressed in US dollars

 

10.PROPERTY, PLANT AND EQUIPMENT (continued)

 

(a)Oil Extraction Plant

  

In June 2011, the Company commenced the development of an oil extraction facility on its mineral lease in Maeser, Utah and entered into construction and equipment fabrication contracts for this purpose. On September 1, 2015, the first phase of the plant was completed and was ready for production of hydrocarbon products for resale to third parties. During the year ended August 31, 2017 the Company began the dismantling and relocating the oil extraction facility to its TMC Mineral Lease facility to improve production and logistical efficiencies while continuing its project to increase production capacity to a minimum capacity of 400-500 barrels per day. The plant has been substantially relocated to the TMC mining site and expansion of the plant to production of 400-500 barrels per day has been substantially completed.

  

Included in the cost of construction is capitalized borrowing costs as at August 31, 2021 and 2020 of $4,421,055. No borrowing costs were capitalized for the years ended August 31, 2021 and 2020.

 

As a result of the relocation of the plant and the expansion that has taken place to date, the Company reassessed the reclamation and restoration provision and raised an additional liability of $2,375,159  during the fiscal year ended August 31, 2019 which is capitalized to the cost of the plant and will be depreciated according to our depreciation policy.

  

As a result of the relocation of the plant and the planned expansion of the plant’s production capacity to 400-500 barrels per day, and subsequently to an additional 3,000 barrels per day, the Company re-evaluated the depreciation policy of the oil extraction plant and the oil extraction technologies (Note 11) and determined that depreciation should be recorded on the basis of the expected production of the completed plant at various capacities. No amortization has been recorded during the 2021 and 2020 fiscal years as there has only been test production during these years.

  

11.LEASES

 

Adoption of ASC Topic 842, “Leases”

 

On September 1, 2019, the Company adopted Topic 842 using the prospective transition method applied to leases that were in place as of September 1, 2019. Results for reporting periods beginning after September 1, 2019 are presented under Topic 842, while prior period amounts are not adjusted and continue to be reported in accordance with the Company’s historic accounting under Topic 840.

 

The Company entered into a real property lease for office space located at 15315 Magnolia Blvd., Sherman Oaks, California. The lease commenced on September 1, 2019 and expires on August 31, 2024, monthly rental expense is $4,941 per month with annual 3% escalations during the term of the lease.

 

The initial value of the right-of-use asset was $245,482 and the operating lease liability was $245,482. The Company monitors for events or changes in circumstances that require a reassessment of our lease. When a reassessment results in the remeasurement of a lease liability, a corresponding adjustment is made to the carrying amount of the corresponding right-of-use asset unless doing so would reduce the carrying amount of the right-of-use asset to an amount less than zero. In that case, the amount of the adjustment that would result in a negative right-of-use asset balance is recorded as a loss in the statement of operations and comprehensive loss.

 

During April 2015, the Company entered into two equipment loan agreements in the aggregate amount of $282,384, with financial institutions to acquire equipment for the oil extraction facility. The loans had a term of 60 months and bore interest at rates between 4.3% and 4.9% per annum. Principal and interest were paid in monthly installments. These loans were secured by the acquired assets.

 

On May 7, 2018, the Company entered into a negotiable promissory note and security agreement with Commercial Credit Group to acquire a crusher from Power Equipment Company for $660,959. An implied interest rate was calculated as 12.36% based on the timing of the initial repayment of $132,200 and subsequent 42 monthly instalments of $15,571. The terms of the note were renegotiated during June 2020, and the instalments were amended to $16,140 per month due to payments not being made during the pandemic. The promissory note is secured by the crusher.

 

F-22

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2021 and 2020

Expressed in US dollars

 

11.LEASES (continued)

 

Discount Rate

 

To determine the present value of minimum future lease payments for operating leases at September 1, 2019, the Company was required to estimate a rate of interest that it would have to pay to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment (the “incremental borrowing rate” or “IBR”).

 

The Company determined the appropriate IBR by identifying a reference rate and making adjustments that take into consideration financing options and certain lease-specific circumstances. For the reference rate, the Company used the 5 year ARM interest rate at the time of entering into the agreement and compared that rate to the Company’s weighted average cost of funding at the time of entering into the operating lease. The Company determined that 10.00% was an appropriate incremental borrowing rate to apply to its real-estate operating lease.

 

Right of use assets

 

Right of use assets included in the consolidated Balance Sheet are as follows:

 

   August 31,
2021
   August 31,
2020
 
Non-current assets        
Right of use assets – operating leases, net of amortization  $167,048   $209,101 
Right of use assets – finance leases, net of depreciation – included in property, plant and equipment   677,853    718,193 

 

Lease costs consist of the following:

 

  

Year ended

August 31,
2021

  

Year ended

August 31,
2020

 
         
Finance lease cost:  $63,165   $82,878 
Depreciation of right of use assets   40,341    40,341 
Interest expense on lease liabilities   22,824    42,537 
           
Operating lease expense   61,071    59,292 
           
Total lease cost  $124,236   $142,170 

 

F-23

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2021 and 2020

Expressed in US dollars

 

11.LEASES (continued)

 

Other lease information:

  

Year ended August 31,

2021

  

Year ended August 31,

2020

 
Cash paid for amounts included in the measurement of lease liabilities        
Operating cash flows from finance leases  $(22,824)  $(42,537)
Operating cash flows from operating leases   (61,071)   (59,292 
Financing cash flows from finance leases  $(172,375)  $(157,388)
           
Right-of -use assets obtained in exchange for new operating leases  $
-
    245,482 
Weighted average remaining lease term – finance leases   5 months    1.25 years 
Weighted average remaining lease term – operating leases   3 years    4 years 
Weighted average discount rate – finance leases   12.36%   12.36%
Weighted average discount rate – operating leases   10.00%   10.00 

 

Maturity of Leases

 

The amount of future minimum lease payments under finance leases is as follows:

 

   August 31,
2021
   August 31,
2020
 
Undiscounted minimum future lease payments        
Total instalments due:        
Within 1 year  $80,700   $193,680 
1 to 2 years   -    80,700 
2 to 3 years   
-
    
-
 
    80,700    274,380 
Imputed interest   (5,642)   (26,948)
Total finance lease liability  $75,058   $247,432 
           
Disclosed as:          
Current portion  $75,058   $172,374 
Non-current portion   
-
    75,058 
   $75,058   $247,432 

 

The amount of future minimum lease payments under operating leases is as follows:

 

   August 31,
2021
   August 31,
2020
 
Undiscounted minimum future lease payments        
Total instalments due:        
Within 1 year  $62,903   $61,070 
1 to 2 years   64,790    62,903 
2 to 3 years   66,734    64,790 
3 to 4 years   -    66,734 
    194,427    255,497 
Imputed interest   (27,379)   (46,396 
Total operating lease liability  $167,048   $209,101 
           
Disclosed as:          
Current portion  $48,376   $42,053 
Non-current portion   118,672    167,048 
   $167,048   $209,101 

 

F-24

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2021 and 2020

Expressed in US dollars

 

12.INTANGIBLE ASSETS

  

   Oil
Extraction
 
   Technologies 
     
Cost    
August 31, 2019  $809,869 
Additions   
-
 
August 31, 2020   809,869 
Additions   
-
 
August 31, 2021  $809,869 
      
Accumulated Amortization     
August 31, 2019  $102,198 
Additions   
-
 
August 31, 2020   102,198 
Additions   
-
 
August 31, 2021  $102,198 
      
Carrying Amounts     
August 31, 2019  $707,671 
August 31, 2020  $707,671 
August 31, 2021  $707,671 

  

Oil Extraction Technologies

 

During the year ended August 31, 2012, the Company acquired a closed-loop solvent based oil extraction technology which facilitates the extraction of oil from a wide range of bituminous sands and other hydrocarbon sediments. The Company has filed patents for this technology in the USA and Canada and has employed it in its oil extraction plant. The Company commenced partial production from its oil extraction plant on September 1, 2015 and was amortizing the cost of the technology over fifteen years, the expected life of the oil extraction plant. Since the company has increased the capacity of the plant to 400 to 500 barrels daily during 2018, and expects to further expand the capacity to an additional 3,000 barrels daily, it determined that a more appropriate basis for the amortization of the technology is the units of production at the plant after commercial production begins again.

 

No amortization of the technology was recorded during the 2021 and 2020 fiscal years.

 

13.ACCOUNTS PAYABLE AND ACCRUED EXPENSES

  

Accounts payable as at August 31, 2021 and 2020 consist primarily of amounts outstanding for construction and expansion of the oil extraction plant and other operating expenses that are due on demand.

  

Accrued expenses as at August 31, 2021 and 2020 consist primarily of other operating expenses and interest accruals on promissory notes (Note 14) debt (Note 15) and convertible debentures (Note 16).

  

Information about the Company’s exposure to liquidity risk is included in Note 33(c).

 

F-25

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2021 and 2020

Expressed in US dollars

 

14.PROMISSORY NOTES PAYABLE

  

           Principal
due
   Principal
due
 
Lender  Maturity Date   Interest
Rate
   May 31,
2021
   August 31,
2020
 
                 
Private lender  On demand    
-
%  $
-
   $8,000 
Private lender  On Demand    
-
%   
-
    
      -
 
Private lender  April 29, 2022    10.00%   23,298    
-
 
                    
            $23,298   $8,000 

  

Two private lenders advanced $80,000 and $20,000 to the Company, these amounts are non-interest bearing, have no fixed terms of repayment and were repaid during the current year.

 

On April 29,2021 the Company issued a promissory note to a private lender in the aggregate sum of $500,000. The promissory note bears interest at 10% per annum and is repayable on April 29, 2022. The Company repaid $476,702 of the outstanding balance as at August 31, 2021. The balance remaining at August 31, 2021 is $23,298.

  

15.DEBT

  

       Principal
due
   Principal
due
 
Lender  Interest
Rate
   August 31,
2021
   August 31,
2020
 
             
Private lender   10.00%   
-
    115,000 
Private lenders   5.00%   
-
    468,547 
Private lender   10.00%   
-
    100,000 
                
        $
                 -
   $683,547 

  

The maturity date of debt is as follows:

  

   August 31,
2021
   August 31,
2020
 
           
 Principal classified as repayable within one year  $
               -
   $683,547 

  

(a)Private lenders

  

  (i)

On July 3, 2018, the Company received a $200,000 advance from a private lender bearing interest at 10% per annum and repayable on September 2, 2018. The loan is guaranteed by the Chairman of the Board. During the year ended August 31, 2020 the Company repaid $35,000 of the principal outstanding and a further $10,000 during the nine months ended May 31, 2021. On July 6, 2020 in accordance with the terms of a debt settlement agreement entered into, the lender converted $50,000 into 1,250,000 shares at a conversion price of $0.04 per share.

 

During June 2021, the remaining aggregate principal amount outstanding of $105,000, including interest and penalty interest thereon of $86,779, was acquired in terms of an Assignment and Purchase of Debt Agreement by Equilibris Management AG. In terms of an Exchange Agreement entered into between the Company and Equilibris Management, the promissory note was exchanged for a Convertible Redeemable Note, bearing interest at 10% per annum, maturing on June 30, 2021 and convertible into common stock at $0.041 per share. On June 16, 2021, in terms of conversion notice received, the Company issued 4,677,532 shares of common stock to Equilibris at a conversion price of $0.041 per share, thereby extinguishing the note.

 

F-26

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2021 and 2020

Expressed in US dollars

   

15.DEBT (continued)

 

(a)Private lenders (continued)

 

  (ii)

On October 10, 2014, the Company issued two secured debentures for an aggregate principal amount of CAD $1,100,000 to two private lenders. The debentures initially bore interest at a rate of 12% per annum, were originally scheduled to mature on October 15, 2017 and are secured by all of the assets of the Company. In addition, the Company issued common share purchase warrants to acquire an aggregate of 16,667 common shares of the Company. On September 22, 2016, the two secured debentures were amended to extend the maturity date to January 31, 2017. The terms of these debentures were renegotiated with the debenture holders to allow for the conversion of the secured debentures into common shares of the Company at a rate of CAD $4.50 per common share and to increase the interest rate, starting June 1, 2016, to 15% per annum. On January 31, 2017, the two secured debentures were amended to extend the maturity date to July 31, 2017. Additional transaction costs and penalties incurred for the loan modifications amounted to $223,510. On February 9, 2018, the two secured debentures were renegotiated with the debenture holders to extend the loan to May 1, 2019. A portion of the debenture amounting to CAD $628,585 was amended to be convertible into common shares of the Company, of which, CAD $365,000 were converted on May 1, 2018. The remaining convertible portion is interest free and was to be converted from August 1, 2018 to January 1, 2019. The remaining non-convertible portion of the debenture was to be paid off in 12 equal monthly instalments beginning May 1, 2018, bearing interest at 5% per annum. On September 11, 2018, the remaining convertible portion of the debenture was converted into common shares of the Company and a portion of the non-convertible portion of the debenture was settled through the issue of 316,223 common shares of the Company. On December 13, 2019, the maturity date of the non-convertible portion of the debenture was extended to January 31, 2020 and the interest rate was increased to 10% per annum. Effective January 31, 2020, the terms of the debenture were renegotiated and the maturity date was extended to August 31, 2020.

 

On June 24, 2021, in terms of an Assignment and Purchase of Corporate Debt Agreement entered into, the debt holder assigned the promissory note due to him of CDN$962,085, including interest and late payment penalties thereon to Equilibris Management AG. Effective June 30, 2021, the Company entered into a Securities Exchange Agreement with Equilibris Management exchanging the CDN$962,085 promissory note with a convertible promissory note for US$771,610 bearing interest at 8% per annum, convertible into shares of common stock at a conversion price of $0.041 per share and maturing on June 22, 2022. On July 1, 2021, in terms of a conversion notice received from Equilibris Management AG, the Company issued 18,819,756 shares of common stock converting the aggregate principal amount of $771,610, thereby extinguishing the debenture.

 

On June 24, 2021, in terms of an Assignment and Purchase of Corporate Debt Agreement entered into with a debt holder, the debt holder assigned the promissory note due to him of CDN$38,217, including interest and late payment penalties thereon to Equilibris Management AG. Effective June 30, 2021, the Company entered into a Securities Exchange Agreement with Equilibris Management exchanging the CDN$38,217 promissory note with a convertible promissory note for US$30,652 bearing interest at 8% per annum, convertible into shares of common stock at a conversion price of $0.041 per share and maturing on June 22, 2022. On July 1, 2021, in terms of a conversion notice received from Equilibris Management AG, the Company issued 747,616 shares of common stock converting the aggregate principal amount of $30,652, thereby extinguishing the debenture.

     
  (iii) On October 4, 2018, the Company entered into a debenture line of credit of $9,500,000 from Bay Private Equity and received an advance of $100,000. The debenture matured on September 17, 2019 and bears interest at 10% per annum. On September 23, 2020, the principal amount of the debenture of $100,000 plus accrued interest of $18,904 was converted into 2,161,892 shares at a conversion price of $0.055 per share.

 

F-27

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2021 and 2020

Expressed in US dollars

  

16.CONVERTIBLE DEBENTURES

  

          Principal
due
   Principal
due
 
Lender  Maturity Date  Interest
Rate
   August 31,
2021
   August 31,
2020
 
                
Calvary Fund I LP  September 4, 2019   10.00%   
-
    
-
 
   July 31, 2021   12.00%   
-
    250,000 
   July 31, 2021   12.00%   80,000    480,000 
   August 7, 2021   0%   25,000    150,000 
SBI Investments LLC  October 15, 2020   10.00%   
-
    250,000 
   January 16, 2021   10.00%   
-
    55,000 
Bay Private Equity, Inc.  January 15, 2020   5.00%   
-
    3,661,874 
   February 20, 2021   5.00%   
-
    2,400,000 
Cantone Asset Management LLC  October 19, 2021   7.00%   
-
    300,000 
   December 17, 2021   7.00%   240,000    240,000 
   October 19, 2021   18.00%   
-
    240,000 
   December 30, 2021   18.00%   50,000    - 
   July 1, 2023   8.00%   300,000    
-
 
Private lender  October 29, 2020   10.00%   200,000    200,000 
Petroleum Capital Funding LP.  November 26, 2023   10.00%   318,000    318,000 
   December 4, 2023   10.00%   432,000    432,000 
   March 30, 2024   10.00%   471,000    471,000 
   July 21, 2025   10.00%   3,000,000    
-
 
Power Up Lending Group LTD  May 7, 2021   12.00%   
-
    64,300 
   June 4, 2021   12.00%   
-
    69,900 
   June 19, 2021   12.00%   
-
    82,500 
   November 6, 2021   12.00%   
-
    
-
 
   January 12, 2022   12.00%   
-
    
-
 
   February 24, 2022   12.00%   
-
    
-
 
   April 21, 2022   12.00%   92,125    
-
 
   May 20, 2022   12.00%   141,625    
-
 
   July 2, 2022   12.00%   114,125    
-
 
EMA Financial, LLC  April 22, 2021   8.00%   3,120    150,000 
Morison Management S.A  July 31, 2021   10.00%   
-
    192,862 
   October 15, 2020   10.00%   184,251    
-
 
   January 16, 2021   10.00%   55,000    
-
 
Bellridge Capital LP.  March 31, 2021   15.00%   2,900,000    
-
 
   September 30, 2021   5.00%   1,400,000    
-
 
Stirling Bridge Resources  October 29, 2021   10.00%   
-
    
-
 
Alpha Capital Anstalt  August 6, 2021   21.00%   
-
    
-
 
Rijtec Enterprises Limited Pension scheme  November 11, 2021   10.00%   
-
    
-
 
Private lender  November 30, 2021   10.00%   
-
    
-
 
Private lender  January 26, 2022   10.00%   
-
    
-
 
Equilibris Management AG  June 30, 2021   10.00%   
-
    
-
 
   June 22, 2022   8.00%          
   June 22, 2022   8.00%          
Private lender  July 24, 2022   8.00%   120,000    
-
 
            10,126,246    10,007,436 
Unamortized debt discount           (3,978,710)   (1,173,112)
Total loans          $6,147,536   $8,834,324 

 

F-28

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2021 and 2020

Expressed in US dollars

 

16.CONVERTIBLE DEBENTURES (continued)

 

The maturity date of the convertible debentures are as follows:

 

   August 31, 2021   August 31, 2020 
         
Principal classified as repayable within one year  $5,255,874   $8,227,257 
Principal classified as repayable later than one year   891,662    607,067 
           
   $6,147,536   $8,834,324 

 

(a)Cavalry Fund I LP

 

    (i)

On September 4, 2018, the Company issued units to Cavalry Fund I LP (“Cavalry”) for $250,000, which was originally advanced on August 9, 2018. The units consist of 250 units of $1,000 convertible debentures and a common share purchase warrant exercisable for 1,149,424 shares. The convertible debenture bore interest at 10% per annum and matured on September 4, 2019 and was convertible into common shares of the Company at a price of $0.87 per common share. The common share purchase warrants entitle the holder to acquire additional common shares of the Company at a price of $0.87 per share, expiring on September 4, 2019.

 

On September 9, 2019, the Company repaid $75,000 of principal and $1,096 in interest in partial settlement of the convertible debenture. On September 19, 2019, the Company entered into an agreement with Calvary Fund, whereby the remaining principal and interest of $200,000 was settled by the issue of 1,111,111 common shares and a warrant exercisable for 1,111,111 common shares at an exercise price of $0.23 per share.

 

On August 7, 2020 the Company entered into an Amended and Restated Amending Agreement (“ARA”) with Cavalry whereby the maturity date of the warrant exercisable for 1,111,111 common shares was extended to July 31, 2021 and the exercise price was amended to $0.0412 per share. 

       
    (ii)

On October 12, 2018, the Company issued 250 one year units to Cavalry for gross proceeds of $250,000, each unit consisting of a $1,000 principal convertible unsecured debenture, bearing interest at 10% per annum and convertible into common shares at $0.86 per share, and a common share purchase warrant exercisable for 290,500 shares at an exercise price of $0.86 per share with an expiry date of October 12, 2019.

 

During December 2019, the maturity date of the convertible debenture was amended to October 12, 2020 and the conversion price was amended to $0.18 per share. In terms of the ARA entered into on August 7, 2020, the maturity date of the convertible debenture was amended to July 31, 2021, the interest rate was amended to 12% per annum and the conversion price was amended to $0.0412 per share.

 

On May 26, 2021, in terms of a conversion notice received, the Company issued a total of 9,101,942 shares of common stock converting $250,000 of the aggregate principal of this note entered into on October 12,2018 and $125,000 of the aggregate principal of the note entered into on August 7, 2020, see Note 16(a)(iv) below.

 

On July 6, 2021, in terms of a debt conversion agreement entered into with Cavalry, the Company agreed to convert unpaid interest of $22,500 on this note; and unpaid principal of $80,000 and unpaid interest of $30,560 on a convertible note entered into on August 19, 2019; and unpaid principal of $25,000 on a convertible note entered into on August 7, 2020 into 1,681,488 shares of common stock at a conversion price of $0.094 per share for a total of 1,681,488 shares, which have not been issued as yet and are subject to TSXV approval. The Company may have to renegotiate the terms of the debt conversion agreement based on the recommendations of the TSXV.

 

F-29

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2021 and 2020

Expressed in US dollars

  

16.CONVERTIBLE DEBENTURES (continued)

     

(a)Cavalry Fund I LP (continued)

 

    (iii)

On August 19, 2019, the Company issued a convertible debenture to Calvary for an aggregate principal amount of $480,000, including an original issue discount of $80,000, for net proceeds of $374,980 after certain legal expenses, and a warrant exercisable for 2,666,666 common shares at an exercise price of $0.15 per share. The convertible debenture bore interest at 3.3% per annum and matured on August 29, 2020. The convertible debenture may be converted into common shares of the Company at a conversion price of $0.17 per share.

 

In terms of the ARA entered into on August 7, 2020, the maturity date of the convertible debenture was amended to July 31, 2021 and the conversion price was amended to $0.0412 per share and the exercise price of the warrant was amended to $0.0412 per share and the maturity date was amended to July 31, 2021.

 

On April 13, 2021, in terms of a conversion notice received, the Company issued a total of 9,708,737 shares of common stock converting $400,000 of the aggregate principal of the note entered into on August 19, 2019.

 

On July 6, 2021, in terms of a debt conversion agreement entered into with Cavalry, the Company agreed to convert unpaid interest of $22,500 on the note entered into on October 12, 2018; and unpaid principal of $80,000 and unpaid interest of $30,560 on this convertible note; and unpaid principal of $25,000 on a convertible note entered into on August 7, 2020 into 1,681,488 shares of common stock at a conversion price of $0.094 per share for a total of 1,681,488 shares, which have not been issued as yet and are subject to TSXV approval. The Company may have to renegotiate the terms of the debt conversion agreement based on the recommendations of the TSXV.

 

The aggregate principal amount of $80,000 of the convertible loan, which has past the maturity date of July 31, 2021, remains outstanding.

       
    (iv)

On August 7, 2020, the Company issued a convertible debenture to Calvary for an aggregate principal amount of $150,000, including an original issue discount of $25,000, for net proceeds of $125,000, and a warrant exercisable for 3,033,980 common shares at an exercise price of $0.0412 per share. The convertible debenture bore interest at 0.0% per annum and maturing on August 7, 2021. The convertible debenture may be converted into common shares of the Company at a conversion price of $0.0412 per share.

 

On May 26, 2021, in terms of a conversion notice received, the Company issued a total of 9,101,942 shares of common stock converting $250,000 of the aggregate principal of the note entered into on October 12,2018, see note 16(a)(ii) above, and $125,000 of the aggregate principal of this note entered into on August 7, 2020.

 

On July 6, 2021, in terms of a debt conversion agreement entered into with Cavalry, the Company agreed to convert unpaid interest of $22,500 on the note entered into on October 12, 2018; and unpaid principal of $80,000 and unpaid interest of $30,560 on the convertible note entered into on August 19, 2019; and unpaid principal of $25,000 on this convertible note, into 1,681,488 shares of common stock at a conversion price of $0.094 per share for a total of 1,681,488 shares, which have not been issued as yet and are subject to TSXV approval. The Company may have to renegotiate the terms of the debt conversion agreement based on the recommendations of the TSXV.

 

The aggregate principal amount of $25,000 of the convertible loan, which has past the maturity date of August 7, 2021, remains outstanding.

 

F-30

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2021 and 2020

Expressed in US dollars

  

16.CONVERTIBLE DEBENTURES (continued)

   

(b)SBI Investments, LLC

  

    (i)

On October 15, 2018, the Company entered into an agreement with SBI Investments, LLC (“SBI”) whereby the Company issued 250 one year units for proceeds of $250,000, each debenture consisting of a $1,000 principal convertible unsecured debenture, bearing interest at 10% per annum and convertible into common shares at $0.86 per share, and a warrant exercisable for 1,162 shares of common stock at an exercise price of $0.86 per share, expiring on October 15, 2019.

 

During December 2019, the maturity date of the convertible loan was extended to October 15, 2020 and the conversion price of the note was reset to $0.18 per share.

 

On February 25, 2021, the Company repaid principal of $16,516 and interest thereon of $33,484, totaling $50,000 and on March 9, 2021, the Company repaid a further $49,232 of principal and interest of $768, totaling 50,000.

 

On August 3, 2021, in terms of a debt assignment agreement entered into with Morison Management SA, SBI Investments assigned this October 15, 2018 convertible debenture and the January 26, 2020 convertible debenture to Morison Management SA. 

       
    (ii)

On January 16, 2020, the Company entered into an agreement with SBI whereby the Company issued a convertible promissory note for $55,000 for gross proceeds of $50,000, bearing interest at 10% per annum and convertible into common shares at $0.14 per share. The convertible note matured on January 16, 2021. In conjunction with the convertible promissory note, the Company issued a warrant exercisable for 357,142 shares of common stock at an exercise price of $0.14 per share, which warrant expired unexercised on January 16, 2021.

 

On August 3, 2021, in terms of a debt assignment agreement entered into with Morison Management SA, SBI Investments assigned this October 15, 2018 convertible debenture and the January 26, 2020 convertible debenture to Morison Management SA 

 

(c)Bay Private Equity, Inc.

 

    (i)

On September 17, 2018, the Company issued 3 one year convertible units of $1,100,000 each to Bay Private Equity, Inc. (“Bay”), including an OID of $100,000 per unit, for net proceeds of $2,979,980. These units bear interest at 5% per annum and matured one year from the date of issue. Each unit consists of one senior secured convertible debenture of $1,100,000 and 250,000 common share purchase warrants. Each convertible debenture may be converted to common shares of the Company at a conversion price of $1.00 per share. Each common share purchase warrant entitles the holder to purchase an additional common share of the Company at a price of $1.10 per share for one year after the issue date.

 

On January 23, 2019, $400,000 of the principal outstanding was repaid out of the proceeds raised on the January 16, 2019 Bay convertible debenture, see (ii) below.

 

During December 2019, the maturity date was extended to January 15, 2020. The maturity date was not extended further during the year and the note was in default as at August 31, 2020.

 

On September 1, 2020, the convertible debenture was assigned to Bellridge Capital, LP (“Bellridge”). Bellridge enforced the penalty provisions of the original agreement, resulting in an increase in the capital due under the debenture by $610,312 , and an increase of 10% to the interest rate, from the date of original default which was September 19, 2019.

 

On September 23, 2020, in accordance with the terms of the amended agreement entered into with Bellridge, the maturity date was extended to March 31, 2021 and the conversion price was amended to $0.055 per share. 

       
    (ii)

On January 16, 2019, the Company issued a convertible debenture of $2,400,000, including an OID of $400,000, for net proceeds of $2,000,000. The convertible debenture bears interest at 5% per annum and matured on October 15, 2019. The convertible debenture may be converted to 5,000,000 common shares of the Company at a conversion price of $0.40 per share. $400,000 of the proceeds raised was used to repay a portion of the $3,300,000 convertible debenture issued to Bay Private Equity on September 17, 2018, see (i) above.

 

On August 20, 2020, in accordance with the terms of an amendment entered into with Bay, the maturity date was extended to February 20, 2021.

 

On April 23, 2021, the convertible debenture was assigned to Bellridge and the terms of the debenture were amended as follows; the maturity date was extended to September 30, 2021.

 

F-31

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2021 and 2020

Expressed in US dollars

  

16.CONVERTIBLE DEBENTURES (continued)

   

(d)Cantone Asset Management, LLC

  

    (i)

On July 19, 2019, the Company issued a convertible debenture to Cantone Asset Management, LLC (“Cantone”) in the aggregate principal amount of $300,000, including an OID of $50,000 for net proceeds of $234,000 after certain issue expenses. The convertible debenture bears interest at 7% per annum and the gross proceeds, less the OID, of $