UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K/A

Amendment No. 1

 

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

 

For the Fiscal Year Ended August 31, 2019

 

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 ☒

 

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 16, 2019 was 197,938,969.

 

Documents incorporated by reference: None.

 

 

 

 

 

 

PETROTEQ ENERGY INC.

 

EXPLANATORY NOTE

 

Petroteq Energy Inc. (“Petroteq” or the “Company”) is filing this Amendment No. 1 to Form 10-K (this “Amendment”) to amend the Company’s annual report on Form 10-K for the year ended August 31, 2019 (the “Original Filing”), originally filed by the Company with the Securities and Exchange Commission (“SEC”) on December 16, 2019. This Amendment restates the Company’s previously issued audited consolidated financial statements and related note disclosures as of and for the years ended August 31, 2019 and 2018.

 

Background of Restatement

 

On July 16, 2021, the independent members of the Audit Committee (with Mr. Alex Blyumkin abstaining, the “Audit Committee”) of the Board of Directors of the Company, after discussion with the Company’s Chief Financial Officer, concluded that:

 

1. the Company’s previously-issued financial statements (the “Periodic Financial Statements”) contained in the following periodic reports should no longer be relied upon:
     
(a) the Original Filing and the Company’s annual report (together with the Original Filing, the “Annual Reports”) on Form 10-K for the financial year ended August 31, 2020, originally filed on December 15, 2020;
   
(b) Amendment No. 1 to the Annual Report for the financial year ended August 31, 2020, originally filed on December 28, 2020; and

 

(c) the Company’s quarterly reports on Form 10-Q for the periods ended May 31, 2019, November 30, 2019, February 29, 2020, May 31, 2020, November 30, 2020 and February 28, 2021, originally filed on October 7, 2019, January 21, 2020, June 3, 2020, July 20, 2020, January 19, 2021 and April 20, 2021; and
   
 

(d)

Amendments to the quarterly reports for the periods ended February 29, 2020, and February 28, 2021, originally filed on June 8, 2020 and April 21, 2021.
   
2. the Company’s previously-issued unaudited condensed consolidated financial statements for the three and six months ended February 28, 2019 and 2018 (together with the Periodic Financial Statements, the “Financial Statements”) contained in the original Filing should no longer be relied on.

 

i

 

 

The Board of Directors has concurred with the conclusions of the Audit Committee.

 

The Company had issued a secured promissory note dated December 27, 2018 (the “Note”) payable to Redline Capital Management S.A. (“Redline”) in the principal amount of $6,000,000, maturing 24 months following its date of issue, and bearing interest at the rate of 10% per annum based on a 360-day year. The Company’s obligations under the Note are purportedly secured by collateral consisting of the Company’s right, title and interest in certain federal oil and gas leases (the “Oil and Gas Leases”) relating to the Company’s Asphalt Ridge Project, pursuant to a security agreement between the parties dated December 27, 2018 (the “Security Agreement”).

 

The Note had been issued pursuant to the terms of a settlement agreement between the parties dated December 27, 2018 (the “Settlement Agreement”) which purported to settle certain claims asserted by Redline against the Company. Shortly following the Settlement Agreement, in early 2019, Mr. Blyumkin, who was then the Company’s Executive Chairman, had indicated he undertook an internal review of the claims made by Redline and concluded that the Settlement Agreement, the Note and the Security Agreement are void and unenforceable, and that they did not have to be disclosed to the Board of Directors or to the Company’s Chief Financial Officer. Mr. Blyumkin has indicated he verbally advised Redline that the Company now considered the Settlement Agreement, and therefore the Note and the Security Agreement, to be void and unenforceable. However, no action was taken to document this position. Since maturity of the Note, on December 27, 2020, Redline has not filed any legal action to enforce payment of the Note.

 

In response to a request from Staff at the Securities and Exchange Commission, Mr. Blyumkin determined that it was appropriate to raise the Settlement Agreement, the Note and the Security Agreement for consideration by the Company’s Chief Financial Officer and the Audit Committee, and, in particular, to review his conclusion that they did not have to be disclosed in the Financial Statements. The Audit Committee has determined that, notwithstanding the results of the internal review of Redline’s claims undertaken by Mr. Blyumkin in early 2019, the Settlement Agreement, the Note and the Security Agreement should have been disclosed, and that the obligations referenced in the Note should have been disclosed in the Financial Statements regardless of the Company’s position of their validity and enforceability.

 

Special legal counsel was subsequently engaged by the Company to undertake a review of the Settlement Agreement, the Note and the Security Agreement with the view to determining whether they are enforceable (and, in particular, whether the Security Agreement has properly charged the Company’s right, title and interest in the Oil and Gas Leases as personal property, and whether any security interests purportedly granted pursuant to the Security Agreement have been perfected under applicable law), and whether the related liability should be classified as an actual or contingent liability. Based on the advice of such legal counsel, the Company has determined that the liability purportedly represented by the Note should be classified as a contingent liability.

 

ii

 

 

Internal Control Considerations

 

As disclosed in the Original Filing, we do not yet have effective disclosure controls and procedures, or internal controls over all aspects of our financial reporting, and we have identified material weaknesses in our internal control over financial reporting. Management has concluded that, due to a lack of segregation of duties, the Company’s disclosure controls and procedures are ineffective to ensure that information required to be disclosed by the Company in the reports that the Company files or submits under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to the Company’s management, including the Company’s Chief Executive Officer and the Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In addition, we do not yet have effective internal controls over all aspects of our financial reporting, and we have identified material weaknesses in our internal control over financial reporting. 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.

 

In connection with the restatement, management has re-evaluated the effectiveness of Petroteq’s disclosure controls and procedures, and internal controls over financial reporting as of August 31, 2019. As a result of that assessment, management has concluded that the Company’s disclosure controls and procedures, and internal controls over financial reporting, were not effective as of August 31, 2019, due to the factors described in the Original Filing.

 

Items Amended

 

Each of the following items are amended and restated in their entirety in this Amendment: (i) Part I, Item 1A. - Risk Factors is amended to add certain additional risks factors associated with the addition of the obligations referenced in the Note as a contingent liability; (ii) Part I, - Item 3. Legal Proceedings; Part II, Item 7, - Management’s Discussion and Analysis of Financial Condition and Results of Operations; and Part II, Item 8. – Financial Statements and Supplementary Data.

 

Except for the foregoing amended and/or restated information required to reflect the effects of the restatement of the financial statements as described above, and applicable cross-references within this Amendment, this Amendment does not amend, update, or change any other items or disclosures contained in the Original Filing. This Amendment continues to describe conditions as of the date of the Original Filing, and the disclosures herein have not been updated to reflect events, results or developments that have occurred after the date of the Original Filing, or to modify or update those disclosures affected by subsequent events. Accordingly, forward looking statements included in this Amendment represent management’s views as of the date of the Original Filing and should not be assumed to be accurate as of any date thereafter. This Amendment should be read in conjunction with the Original Filing and our filings made with the SEC subsequent to the Original Filing date.

 

iii

 

 

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.

 

iv

 

 

PETROTEQ ENERGY INC.

 

FORM 10-K

 

TABLE OF CONTENTS

 

    Page
     
  PART I. 1
Item 1. Business 1
Item 1A. Risk Factors 16
Item 1B. Unresolved Staff Comments 31
Item 2. Properties 32
Item 3. Legal Proceedings 32
Item 4. Mine Safety Disclosures 33
  PART II. 34
Item 5. Market price of, and dividends of the Registrant’s Common Equity and Related Stockholder Matters 34
Item 6. Selected Financial Data 35
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 35
Item 7A. Quantitative and Qualitative Disclosures About Market Risk 38
Item 8. Financial Statements and Supplementary Data F-1
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 39
Item 9A. Controls and Procedures 39
Item 9B. Other Information 39
  PART III. 40
Item 10. Directors, Executive Officers and Corporate Governance 40
Item 11. Executive Compensation 42
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 46
Item 13. Certain Relationships and Related Transactions, and Director Independence 47
Item 14. Principal Accountant Fees and Services 48
  PART IV.  
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 10-K 49
Item 16. Form 10-K Summary 51
SIGNATURES 52

  

v

 

 

PART I

 

ITEM 1. BUSINESS.

  

BUSINESS OVERVIEW

 

We are a Canadian-registered holding company 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 (“PQE”), conducts our oil sands extraction business through two wholly owned operating companies, Petroteq Oil Sands Recovery, LLC, a Utah limited liability company (“PQE Oil”), and TMC Capital, LLC, a Utah limited liability company (“TMC”). Another subsidiary, Petrobloq LLC, a California limited liability company (“Petrobloq”), also wholly owned by PQE, is developing a blockchain-powered supply chain management platform for the oil and gas industry.

 

 

OIL SANDS MINING & PROCESSING

 

PQE, through its wholly owned subsidiaries PQE Oil and TMC, is in the business of oil sands mining and processing. Historically, all of PQE’s oil sands mining has occurred on a mineral lease located in the Asphalt Ridge area in eastern Utah, where it mines oil sands deposits containing heavy oil and bitumen located at or near the surface. Once mined, the oil sands ore is treated and processed for the extraction and upgrade of crude oil through the application of PQE’s proprietary extraction technology (the “Extraction Technology”) at a processing facility owned/operated by PQE Oil. In 2016, PQE Oil’s mining operations were temporarily suspended due to the relocation of its processing facility to a site within the TMC Mineral Lease in order to improve logistical and processing efficiencies and increase production capacity. PQE recommenced its oil sands mining and processing activities at the end of May 2018 and commenced commercial production during the first quarter of fiscal 2020 (the quarter ended November 30, 2019). Production at or near full capacity is expected in the second quarter of fiscal 2020. During the year ended August 31, 2019 we generated revenue of $59,335 which represents the sale of hydrocarbon products to refineries to determine the commercial quality of our hydrocarbon products.

 

1

 

 

Oil Sands Exploration and Processing Plant 

 

In June 2011, PQE commenced the development of an oil sands extraction facility near Maeser, Utah and entered into construction and equipment fabrication contracts for the purpose of evaluating the Extraction Technology in producing a marketable crude oil from the extraction and processing of oil sands mined from the TMC Mineral Lease and from other deposits located in the Asphalt Ridge area. 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 this initial pilot plant during 2015 allowed us to test and evaluate the Extraction 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 oil prices, PQE determined that the transportation costs of hauling mined ore from our mine site to the processing facility, a distance of approximately 17 miles, were adversely affecting the economics of our processing operations. For that reason and because of a downturn in world oil prices at that time, in 2016 we temporarily suspended operations. In 2017, the plant was disassembled and moved from its original location to the site of our Temple Mountain mining site (referred to as the Asphalt Ridge Mine #1) located within the TMC Mineral Lease, where the plant was reconstructed. During the reassembly of the facility, additional equipment was installed to increase the plant’s capacity from 250 barrels per day to 1,000 barrels per day. In May 2018, mining operations at the Asphalt Ridge Mine #1 recommenced and the new processing plant commenced a test production phase of heavy crude oil from oil sands deposits at this site. Production at or near full capacity at the plant is not anticipated until the second quarter of fiscal 2020.

 

Since May 2018, following completion of the test production phase at our new processing plant, we have operated only one of three production lines at the plant while awaiting the installation of equipment that will enable us to operate the other two production lines. We recently curtailed operations during a maintenance program in order to make equipment alterations and to install new equipment. With construction and installation of the expanded facilities at the plant having been substantially completed, we expect that the plant will have a capacity of up to 1,000 barrels per day and we anticipate that production at or near the expanded capacity will be achieved by the second quarter of fiscal 2020 and do not anticipate that the delays in completing the plant’s expansion will materially impact any of the requirements for continuous operations under the TMC Mineral Lease. Management’s current estimate of the total cost of our Utah oil sands processing facility, including the expansion of processing capacity in order to meet the requirements under the TMC Mineral Lease, exclusive of capitalized borrowing costs and lease costs, is between $28 million and $30 million.

 

Resources and Mining Operations

 

Through its acquisition of TMC in June 2015, PQE indirectly acquired certain mineral rights under the TMC Mineral Lease, consisting of a Mining and Mineral Lease Agreement, dated as of July 1, 2013, between Asphalt Ridge, Inc., as lessor, and TMC, as lessee, covering approximately 1,229.82 acres of land in the Asphalt Ridge area of Uintah County, Utah. In June 2018, PQE acquired additional mineral rights 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 PQE Oil, as lessee, covering lands that largely adjoin the lands covered by the TMC Mineral Lease ( “SITLA Leases”). More recently, in April 2019 and in July 2019, in two separate transactions, TMC acquired an initial 50% and then the remaining 50% of the 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 southeastern Utah (“BLM Leases”). At this time, PQE (through its subsidiaries) holds mineral leases (or the operating rights under leases) covering approximately 8,501.76 net acres within the State of Utah, consisting of 1,229.82 acres held under the TMC Mineral Lease, 1,311.94 acres held under the SITLA Leases and 5.960 acres under the BLM Leases.

 

2

 

 

The following table sets forth the gross/net developed and undeveloped acreage held under the TMC Mineral 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 Lease 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 a substantial part of the lands included in the TMC Mineral Lease, particularly the acreage located in T5S-R21E (Section 25) and T5S-R22E (Section 31) where our Asphalt Ridge Mine #1 is located. Bitumen-saturated pay thicknesses in lands covered by the TMC Mineral Lease generally range from 50-200 feet, with some deposits approaching 300 feet in pay thickness. PQE believes that oil sands deposits in this area may be mined economically at depths up to 250-300 feet below the surface.

 

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
   
All Acreage is Currently Undeveloped

 

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 as a “Special Tar Sands Area” by the (U.S.) Department of Interior.

 

3

 

 

The TMC Mineral Lease

 

Under the TMC Mineral Lease, TMC has the exclusive right to explore for, mine and produce oil and other minerals associated with oil sands, subject to certain depth limits. The TMC Mineral Lease was amended on October 1, 2015 and further amended on March 1, 2016, on February 1, 2018, and most recently on November 21, 2018. The primary term (the “Primary Term”) of the TMC Mineral Lease, as amended, commenced July 1, 2013 and continues for six years, plus an extension period. The term “extension period” was originally defined as a period of time measured from March 1, 2018 to the earlier of (i) March 1, 2019, or (ii) the date on which TMC delivers to the lessor a written financial commitment for the construction of PQE’s second proposed facility (or an expansion to PQE’s existing processing facility), this has since been superseded by the terms as described below.

 

During the Primary Term, if TMC fails to satisfy the requirements of “continuous operations”, the TMC Primary Lease will terminate unless the parties agree in writing to continue the Lease. If TMC, at the end of the Primary Term, has satisfied the requirements of continuous operations, the TMC Mineral Lease will continue in effect beyond the Primary Term as long as TMC continues to comply with any applicable requirements of continuous operations. Under the Lease, the term “continuous operations” consists of the following two requirements:

 

Processing Capacity. TMC must construct or operate one or more facilities (or any expansion to an existing facility) having the capacity to produce an average daily quantity (“ADQ”) of oil or other hydrocarbon products from oil sands mined or extracted from the Lease that, in the aggregate, will achieve (or exceed) the following:

 

By 07-01-2019, 80% of an ADQ of 1,000 barrels/day;

By 07-01-2020, 80% of an ADQ of 2,000 barrels/day; and

By 07-01-2021 (and for the remaining term of the Lease), 80% of an ADQ of 3,000 barrels/day.

  

Minimum Operations. From and after July 1, 2019, TMC must achieve oil sands processing operations that equal (or exceed) the applicable ADQ requirements specified above, either (i) during at least 180 days in each lease year, or (ii) during at least 600 days in any three consecutive lease years.

 

The TMC Mineral Lease is also subject to termination under the circumstances described below:

 

(i)Termination will be automatic if TMC fails to obtain (a) by July 1, 2019, a written financial commitment to fund a second processing facility (or a facility expansion) that will increase our processing capacity by an additional 1,000 barrels per day (achieving an aggregate capacity of 2,000 barrels per day), and (b) by July 1, 2020, a written financial commitment to fund a third processing facility (or facility expansion) that will increase our processing capacity by an additional 1,000 barrels per day (achieving an aggregate capacity of 3,000 barrels per day). We expect that the cost of constructing each of the two additional processing facilities (or any expansion) will range between $10 million and $12 million, which we intend to fund from revenue derived from operations or from third party funding sources.  However, to date revenue from our operations has been minimal and we currently have no financial commitment to fund the capital costs for these facilities  as required under the TMC Mineral Lease.  (See Risk Factors – “Our operations are dependent upon maintaining our mineral lease for the Asphalt Ridge Property”).

 

(ii)Cessation of operations or inadequate production due to increased operating costs or decreased marketability and production is not restored to 80% of capacity within three months of any such cessation will cause a termination.

 

(iii)Cessation of operations for longer than 180 days during any lease year or 600 days in any three consecutive years will cause a termination.

 

(iv)From and after July 1, 2021, a failure of PQE’s processing facility to produce a minimum of 80% of a rated capacity of 3,000 barrels per day during a period of at least 180 calendar days during any lease year, the Lease may be terminated by the lessor.

 

(v)TMC may surrender the lease with 30 days written notice.

 

(vi)In the event of a breach of the material terms of the lease, the lessor will inform TMC in writing and TMC will have 30 days to cure any monetary breach and 150 days to cure any non-monetary breach.

 

4

 

 

We are currently in full compliance with the terms of the TMC Mineral Lease. As of August 31, 2019, we have paid advance royalties of $2,250,336 (August 31, 2018 - $1,890,336) to the lessor, of which a total of $1,382,307 has been used as a credit against production royalties that have accrued under the terms of the TMC Mineral Lease. The royalties expensed have been recognized in cost of goods sold on the consolidated statement of loss and comprehensive loss.

 

From and after July 1, 2021, we must make a minimum annual expenditure of $2,000,000 under the TMC Mineral Lease if an average daily production of 3,000 barrels is not achieved during a 180 day period each year.

 

During the year ended August 31, 2019, we received (gross) proceeds of $59,335 from the sale of upgraded or finished oil produced at our Asphalt Ridge processing facility from oil sands mined under the TMC Mineral Lease. During our fiscal years ending August 31, 2018, August 31, 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 our process facility 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 our processing facility. 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. 

 

Our average sales from production, average costs of production and average API gravity of the oil produced at our initial pilot processing facility during the fiscal year ending August 31, 2015 were as follows:

 

i)Average production sales and sales prices for fiscal year 2015.

 

Month  Average Sales Price (Bbls)  

API Gravity

(Avg)

  

Production Sold

(Gross Bbls1)

 
August  $30.39    43.75    1,277.00 
September  $32.97    46.36    1,926.53 
October  $33.79    45.65    1,866.99 
November  $30.42    45.00    898.21 
December  $24.83    44.51    1,808.60 
Total             7,777.33 

 

(1)Production sold during this period is not subject to adjustment for royalties or taxes. Oil sold during this period was produced from bitumen ore purchased from third parties and from a stockpile of mined ore at our Asphalt Ridge Mine #1 site that is exempt from royalties under the TMC Mineral Lease and from the overriding royalty held by Temple Mountain Energy, Inc. Under Utah law, no severance tax is imposed on oil and gas produced from oil sands or oil shale until June 2026.

 

5

 

 

ii)Average production costs for fiscal year 2015

 

Average Monthly Production Costs 2015 (per Barrel of Produced Oil) (1)
 
   August   September   October   November   December 
Fixed Costs(2)                    
Operator Labor   5.31    5.31    5.31    5.31    5.31 
Electricity   0.48    0.48    0.49    0.52    0.55 
Propane   1.07    1.07    1.33    1.35    1.41 
Nitrogen   0.21    0.21    0.21    0.21    0.21 
Water   0.10    0.10    0.10    0.10    0.10 
Diesel Fuel   0.19    0.19    0.19    0.32    0.37 
Rental Equipment   0.79    0.79    0.79    0.79    0.79 
Variable Costs                         
Oil Sands Ore   4.58    4.61    4.61    4.59    4.58 
Aromatic Solvents   0.65    0.65    0.65    0.65    0.65 
Condensate(3)   18.32    17.90    16.87    15.94    15.56 
Total Average Production Cost (by month)   31.70    31.31    30.55    29.78    29.53 

 

(1)The Average Monthly Production Costs for fiscal year 2015 are based on a total (gross) production of 10,000 barrels of oil during the five-month period (consisting of 7,777.33 barrels of oil that was sold and approximately 2,223 barrels that was used to fuel plant generators).

 

(2)Fixed Costs do not include costs associated with produced oil consumed or used by our plant as a fuel source during production shut-downs since produced oil used as fuel (to keep units “warm”) during periods in which production is not occurring has been deemed not to be production-related

 

(3)Variable costs for condensate are determined by multiplying (a) the fractional percentage of a barrel of condensate used in producing one barrel of finished oil during each month, by (b) the average monthly cost, on a per barrel basis, of condensate that we acquired during the month from our supplier (the table below shows our average monthly purchase costs for natural gas liquids (condensate) acquired from third parties during fiscal 2015).

 

iii)Average purchase costs for natural gas liquids (condensate) for fiscal year 2015:

 

Month  

Average

Condensate

Costs (1)

 
August   $ 28.38  
September   $ 29.75  
October   $ 29.26  
November   $ 26.25  
December   $ 22.15  

 

(1)The Average Condensate Costs, expressed on a “per barrel” basis, represent a monthly average of the price(s) paid for natural gas liquids supplied by third parties.

 

The costs associated with extraction and processing operations at our Asphalt Ridge processing facility which 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 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 our Asphalt Ridge facility 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 open pit 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 increase 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 (ranging from $2.62/barrel of oil to achieve an API gravity of 15.7 to $16.27/barrel of oil for an API gravity of 42).

 

6

 

 

In determining our “Average Production Costs” for 2015, our average fixed costs for each barrel of oil produced at our Asphalt Ridge processing facility during the period of August 2015 through December 2015 were: operator labor ($5.31); electricity ($ 0.50), propane ($1.25); nitrogen ($0.21); water ($0.1); diesel fuel ($ 0.25); and rental equipment ($0.79). For our variable costs (expressed for each barrel of oil produced at our facility), our average oil sands ore cost was $4.59 per barrel, the primary component of which was the cost of transporting the mined ore approximately 17 miles from our lease to the original location of our pilot plant, and our average cost for aromatic solvent and condensate was $0.65 and $16.92, respectively.

 

For comparison purposes, during the period of August 2018 through December 2018, our “Average Production Costs” decreased to $27 per barrel of oil produced at our Asphalt Ridge facility. During this period, our fixed costs did not differ materially from our August 2015 to December 2015 fixed costs. We do anticipate that we will experience an increase in fixed costs as we increase our capacity and operate at full capacity.

 

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

 

We do not expect our operating costs to materially change as the depth of the Asphalt Ridge #1 Mine increases with additional mining over time. We further anticipate that increased efficiencies in our mining operations and various economies of scale (such as bulk quantity purchases of aromatic solvents at quantity/price discounts), will assist in managing and potentially reducing our average production costs as production at our Asphalt Ridge facility increases over time.

 

The API gravity for the raw heavy oil or bitumen extracted from oil sands ores initially treated at our Asphalt Ridge processing facility averages approximately 10 degrees. Through the application of the Extraction Technology at our plant, a new or distinct crude oil is produced having a range of API gravity of between 20 degrees and 35 degrees. Through our solvent formulation and the select distillation capabilities, the plant is able to craft a final crude oil product to meet the specifications of a range of (refinery and pipeline) customers.

 

The finished crude oil produced at our Asphalt Ridge processing facility is currently sold to an independent purchaser under short-term or spot delivery contracts where the purchaser takes delivery of finished crude oil at or near the plant and transports it for resale to a refinery in Nevada. The specifications of the oil produced at the plant are effectively tailored to meet customer (pipeline and refinery) specifications and requirements. From time to time we sell oil produced at our Asphalt Ridge facility pursuant to the terms of product off take agreements However, none of our agreements with our current purchaser and none of the offtake agreements are firm commitments requiring the purchaser to acquire a specified quantity of our produced oil. If we increase our production beyond the needs of our current purchaser, we expect to attempt to find additional purchasers for such additional production. Although we believe that larger production quantities will attract certain purchasers that only purchase larger quantities of product and will require transportation of our products to locations closer to our processing facility, resulting in lower transportation costs, to date we have only had preliminary discussions with such purchasers and have no purchase commitments from such purchasers. If purchasers located closer to our processing facility are not interested in acquiring such additional quantities produced, we may sell our product to purchasers that may require transportation of our products to locations that are further from our processing facility, which would result in higher transportation costs and lower profit margins for us.

 

Generally, the finished oil produced at our Asphalt Ridge processing facility is sold 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 U.S. 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.

 

We anticipate that, as production from our oil sands facility increases, longer term contracts will be secured by PQE Oil utilizing market-based pricing formulas.

 

The SITLA Leases

 

The SITLA Leases have a primary term of ten (10) years, and will remain in effect thereafter for as long as (a) bituminous sands are produced in paying quantities, or (b) PQE Oil is otherwise engaged in diligent operations, exploration or development activity and certain other conditions are satisfied. Generally, the term of the SITLA Leases may not be extended beyond the twentieth year of their effective dates except by production in paying quantities. An annual minimum royalty of $10 an acre must be paid during the first ten years of the SITLA 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 SITLA Leases. Annual minimum royalties paid in any lease year may be credited against production royalties accruing in the same year.

 

7

 

 

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 Payable

 

Technology Transfer Agreement

 

Pursuant to the terms of a technology transfer agreement dated November 7, 2011 that we entered into with Vladimir Podlipskiy, the developer of the Extraction Technology, we are obligated to pay Mr. Podlipskiy a royalty on production from each processing plant that we own or operate that uses the Extraction 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 $60.00 per barrel; 3% of gross sales if the price of heavy oil is between $60.00 and $69.99 per barrel; 3.5% of gross sales if the price of heavy oil is between $70.00 and $79.99 and 4% of gross sales if the price of heavy oil is greater than $80.00 per barrel.

 

TMC Mineral Lease

 

Under the TMC Mineral Lease, TMC holds 100% of the working interests (subject to a 1.6 % overriding royalty previously granted to Temple Mountain Energy, Inc.).

 

In addition, TMC is required to make certain advance royalty payments to the lessor. Future advance royalties required are:

 

  (i) From July 1, 2018 to June 30, 2020, minimum payments of $100,000 per quarter.

 

  (ii) From July 1, 2020, minimum payments of $150,000 per quarter.

 

Minimum payments commencing on July 1, 2020 will be adjusted for CPI inflation.

 

Production royalties payable under the TMC Mineral Lease are eight percent (8%) of the gross sales revenue, subject to certain adjustments up until June 30, 2020. After that date, royalties will be calculated on a sliding scale based on crude oil prices ranging from 8% to 16% of gross sales revenues, subject to certain adjustments.

 

8

 

 

SITLA Leases

 

The SITLA Leases provide that PQE Oil must 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 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, 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. As the sole lessee under the SITLA Leases, PQE Oil owns 100% of the working interests under the Leases, subject to payment of annual rentals, advance annual minimum royalties, and production royalties.

 

BLM Leases

 

Under the BLM Leases, production royalties are governed by BLM regulations and are payable to the United States (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 land included within the TMC Mineral Lease.

 

On or about July 9, 2015, UDOGM approved an application filed by TMC 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. On October 27, 2017, UDOGM granted final approval to TMC’s “Amended Notice of Intention to Commence Large Mining Operations” and issued final Permit # M/047/0089 authorizing TMC to conduct operations at Asphalt Ridge Mine #1. On or about August 6, 2018, PQE Oil filed an amended “Notice of Intention to Commence Large Mining Operations” at the Asphalt Ridge Mine #1, primarily for the purpose of notifying UDOGM that PQE Oil will be the operator under the TMC Mineral Lease and to provide an update on the mining and oil sands processing plan developed by PQE Oil for Asphalt Ridge Mine #1. The August 2018 Notice of Intention to Commence Large Mining Operations has been approved by the UDOGM on July 23, 2019.

 

Mining operations, including the initial development of the mine at the property and removal of the overburden soil layer has already been performed. 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 PQE.

 

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 was required by Utah law even though our processing facility does not use a water-based process and 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 our processing facility at Asphalt Ridge 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 our current processing facility. The CUP is a right/interest in land under Utah law and will continue in effect in perpetuity. A local business license was issued to PQE Oil by the Uintah County Commission on November 19, 2018. The business license must be renewed annually on payment of a license renewal fee.

 

9

 

 

The oil and gas properties (including plants, equipment etc.) included in or under the TMC Mineral Lease 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 Lease or the SITLA Leases until after June 30, 2026.

 

Extraction Technology

 

PQE intends to continue to develop its operations by processing purchased native oil sands ore, as well as native oil sands ore produced through the mining operations of its subsidiary (TMC) using its patented closed loop, continuous flow, scalable and environmentally safe Extraction Technology. The Extraction Technology process allows the extraction of hydrocarbons from a wide range of both “water- wet” and/or “oil-wet” oil sands deposits and other hydrocarbon sediment types. PQE’s oil extraction process takes place in a completely closed loop system that continuously recirculates and recycles the solvent after it has completely separated the asphaltene and heavy oils from the oil sands. The closed loop system is capable of recovering over 99% of all hydrocarbons from the oil sands, making this technology very environmentally friendly. The only two end products of the process are high quality heavy oil and clean sand.

 

The Extraction Technology, which has been modified since 2015 and unlike the technology utilized in 2015, utilizes no water in the process, is anticipated to produce no greenhouse gases, requires no high temperature and/or pressure for the extraction process, and expects to extract up to 99% of all hydrocarbon content and recycle up to 99% of the solvents. The proprietary solvent composition consists of hydrophobic, hydrophilic and polycyclic hydrocarbons. It 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 70 – 75 C degrees and it is expected to allow recycling of over 99% of the solvent. These features, in the event they produce as anticipated by PQE, make it possible to perform hydrocarbon extraction from oil sands at mild temperatures of 50 – 60 degrees C, with no vacuum or/and pressure applied that would lead to high energy and economic efficiency of the extraction of oil from the overall oil sands extraction process.

  

In the oil extraction and upgrade process utilized at our Asphalt Ridge processing facility, the bitumen crude oil that we extract from mined oil sands (used as a primary feedstock) has an average API gravity of 10 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 (which we distill from natural gas condensate, ordinary chemicals, and recycled 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 sandstones during the initial extraction process. This process yields an unfinished crude oil containing the solvent and a second residual consisting of clean sand (that contains virtually no hydrocarbons).

 

The unfinished crude oil containing solvent is then introduced or subjected to a simple distillation process where, as the temperature is increased to certain boiling points, virtually all of the solvent is recovered and recycled for future use and the hydrocarbons contained in the unfinished oil are manipulated. During this process – and depending on the API gravity target of the customer – as temperatures are increased, a greater number of increasingly longer hydrocarbon chains are removed (starting with shorter chains of light hydrocarbons and moving to longer heavier hydrocarbon chains having higher boiling points), resulting in a finished crude oil having a higher API gravity (and requiring larger quantities of solvent/condensate in the process). Conversely, at lower temperatures, the solvent and lighter hydrocarbon chains are removed and recycled for future use, resulting in a lower API gravity finished crude oil (and requiring smaller quantities of solvent/condensate in the process).

 

The finished crude oil produced and sold to our customers, for purposes of disclosure under the SEC’s classifications, qualifies as a “synthetic crude oil”. However, the finished oil that we produce is not bitumen and contains virtually no residual solvents or synthetic compounds, is not a blend of separate oils or hydrocarbon products and does not contain diluent. Instead, our finished oil is produced by the extraction, processing and refinement of natural petroleum and is not manufactured by synthesis or with feedstocks that contain or utilize synthetic compounds. For that reason, we market the finished oil that we produce as an upgraded crude oil, a distinct oil product consisting of naturally occurring hydrocarbons and having its own specifications.

 

The oil extraction process has a reboiler, vapors vessel, heat exchangers, air fin condenser, and an oil heater plus a propane tank as the energy source. The reboiler and vapor vessel are used to recycle the solvent. The oil-solvent mixture is subject to increased temperatures in the reboiler to the solvent’s boiling temperature(s), overheated vapors travel through the vapor vessel into the condenser and the solvents are condensed back into a liquid in the air fin cooler/condenser and returned (recycled) back to the process.

 

During the recovery of the solvent through the distillation process, the plant’s engineering and technical personnel are able to select the hydrocarbon chains in the condensate/solvent that are to be flashed off and recovered for recycled reuse in the plant, which in turn produces a crafted finished crude oil. In other words, by selectively stripping or flashing off different hydrocarbon chains from the solvent (whether it be heavier hydrocarbons such as C7 heptanes or C8 octane, or lighter hydrocarbons such as C5 pentane or C6 hexane, plant personnel are able, by design, to use the condensate component of the solvent as a feedstock to produce a relatively sweet heavy to medium crude oil (with an API gravity in the 20-30 degree range) or a sweet lighter crude oil (with an API gravity in the 30-40 degree range). The final product is a distinct crude oil, having its own specifications, produced through the processing and distillation of hydrocarbons derived from two feedstocks: (a) crude bitumen oil or heavy oil extracted from native oil sands, and (b) natural gas condensate.

 

10

 

 

As part of a hydrocarbon refining process utilizing basic chemistry, the natural gas condensate used in the solvent serves dual functions of (1) a solvent that effectively causes a release of heavy oil from the bitumen-saturated stream, and (2) a feedstock that, through distillation with a primary feedstock consisting of the raw heavy oil or bitumen stream extracted from raw oil sands ores, produces a finished crude oil product. The solvent that is not recovered in the refining process effectively acts as a feedstock to produce the crude oil.

 

While the initial tests of the Extraction Technology in 2015 did not include recycling of solvents, we believe that recent improvements to this technology will achieve the recovery/recycling of over 99% of the solvent and between 50% and 99% of the natural gas condensate. This was based, among other things, on the results of tests previously conducted internally and with third parties at PQE’s laboratory in San Diego using different batches of heavy oil extracted from oil sands in a solvent-extraction process. The actual amount of natural gas condensate recovered/recycled is expected to vary depending upon the API gravity of the finished oil that we elect to produce. Using our Extraction Technology, the production of oil having a higher API gravity will consume more condensate and recycle/recover less condensate.

 

Another key element of our Extraction Technology is that it applies its own extractor using a proprietary/patented “liquid fluidized bed” solvent extraction system for bitumen/oil impregnated in oil sands. A “liquid fluidized bed” style reactor is anticipated to provide continuous mixing of the (liquid) solvent and the solid ore particles. It is intended to allow a continuous flow process with optimal material/mass/energy balances. The Extraction Technology uses only a fraction of the energy needed to produce a barrel of oil when compared with the water-based technologies used in Canada. PQE’s process also employs multiple energy saving technologies to reduce energy consumption. This has resulted in a high level of energy efficiency in the oil extraction process that we use in our Asphalt Ridge processing facility. PQE’s patented design also includes exceptionally efficient heat exchange and distillation/rectification systems. This energy efficiency should significantly improve the economics involved in operating our processing facility.

 

PQE has received patents in the United States, Canada and Russia that protect the claims and processes embodied in the Extraction Technology. See “Intellectual Property” below.

  

INTELLECTUAL PROPERTY

 

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

 

On July 2, 2019, PQE entered into an intellectual property license agreement with Valkor LLC, a company based in Katy, Texas, for the non-exclusive, non-transferable use of the Extraction Technology worldwide (subject to any exclusive license agreements in effect) in the engineering, construction and operation of oil sands extraction plants. The agreement requires Valkor to invest (or secure investment of) a minimum of US$20 million towards the construction of an oilsands 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 US$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.

 

We rely upon patents to protect our intellectual property. We have obtained patents in the United States, Canada and Russia that protect the Extraction 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

 

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

 

11

 

 

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.

 

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 sulfur, 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. The development of oil sands domestically has the potential to turn the United States into a major supplier of heavy oil to world markets. 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, PQE has developed and patented an extraction technology that aims to develop oil sands reserves in an economical and environmentally responsible manner. PQE is currently expanding its commercial oil sands extraction operations in the Asphalt Ridge area, utilizing a process that is economical, environmentally friendly and produces high quality heavy oil.

 

We have tested our Extraction Technology both at Asphalt Ridge and with oil sands sourced from different parts of the world and having 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 PQE’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 centrifugation and dried under the vacuum.

 

Through our testing of oil sands sourced from different countries, we found that the efficiency and consistency of PQE’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.

 

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PETROBLOQ LLC

 

In November 2017, we formed a subsidiary Petrobloq LLC to focus on developing digital supply chain management solutions. Petrobloq has entered into an agreement with First Bitcoin Capital Corp. (“FBCC”), a global developer of blockchain-based applications, to design and develop a blockchain-powered supply chain management platform for the oil and gas industry. The platform is being designed to be a “one-stop shop” that will provide both small and large oil and gas producers and operators with the ability to customize their own distributed ledger modules that will permit each company, in a secure “closed” environment, to document, track, and account for the supply of equipment, materials and services in project, field, and lease development. The agreement with FBCC requires that Petroteq pay FBCC $500,000 for the services to be provided, of which $252,500 has been paid.

 

The supply chain management platform is currently in early stage development and we are in the process of continuing research and development activities. The current development plans are that the platform will be blockchain agnostic and able to run on any blockchain that is commercially available. The Company’s business does not entail, and it is not anticipated that it will entail, the creation, issuance, or use of any digital assets.

 

In February 2018, Petrobloq leased an 1,800 square foot office in Calabasas, California. The office is staffed with four contract employees hired by FBCC serving as Project Manager; Director of Operations, Solutions Architect and Senior Database Developer, respectively.

 

In June 2018 and September 2018, we entered into statements of work with MehzOhanian, a software engineering firm based in Austin, Texas, to develop blockchain applications for Petrobloq. MetzOhanian specializes in blockchain engineering, supply chain management software development, and digital security consulting. MetzOhanian will be working with Petrobloq to develop blockchain applications aimed at increasing supply chain transparency and efficiency in the oil and gas sector. The statements of work entered into on June 5, 2018 was for services to be provided from June 5, 2018 until August 10, 2018 and the statement of work entered into on September 24, 2018 is for services to be provided between October 1, 2018 and October 1, 2019. The services are provided on an hourly basis and the estimated cost of the services to be provided under the second statement of work is $129,850.

 

OTHER INVESTMENTS

 

In addition, we own a 44.7% interest in Accord GR Energy, Inc., a Delaware corporation (“Accord”), which uses two oil enhanced recovery technologies that it licenses from one of its affiliated entities to conduct oil and gas production activities. We also own a 25% interest in Recruiter.com Oil and Gas Group LLC, a Delaware limited liability company (“Recruiter. OGG”), a recruitment venture that provides a website focused on careers in the oil and gas industry. Due to the lack of activity in both Accord and Recruiter.OGG, our investment in each has been fully written off on our balance sheet for the year ended August 31, 2019.

 

13

 

 

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 PQE Oil 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 PQE Oil. 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.

 

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 sulfur 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 and we intend to consider entering in those states with our technologies offering to the regulators and the public solutions that we believe would help to lift the bans and ease resistance to oil and gas field development.

  

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.

 

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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.

 

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”), 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 means the market value of our common shares that is held by non-affiliates exceeded $700.0 million as of the prior June 30th, 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.

 

15

 

 

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 and our principal place of business is located at 15315 W. Magnolia Blvd., Suite 120, Sherman Oaks, California 91403. Our telephone number is (866) 571-9613.

 

Our common shares are publicly traded on the TSX Venture Exchange (the “TSXV”) under the trading symbol “PQE”, 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.

 

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. 

 

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

 

Our oil extraction segment has a limited operating history. 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.  In May 2018 we recommenced our oil extraction activities, which is expected to be a significant source of our revenue. From 2015 until 2018, we temporarily ceased our oil sands mining and processing operations while we relocated our processing plant. For a limited period, we made sales of hydrocarbon products to customers produced at our initial processing facility following completion of its construction and fabrication on September 1, 2015. Due to the volatility in the oil markets production ceased as we were not able to operate profitably at low volumes of output. The losses from continuing operations over the past four fiscal years are largely due to the relocation, reassembly and expansion or our processing facility on land located within our TMC Mineral Lease located in Uintah County, Utah. As of the date of this Fork 10-K, 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 new (and expanded) processing facility is fully operational for at least a few months, which is not expected until the second quarter of fiscal 2020.  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, 2019, August 31, 2018 and August 31, 2017, we had an accumulated deficit of ($78,285,282), ($62,497,396) and ($46,856,367), 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 ($15,787,886) and ($15,641,029), as of the years ended August 31, 2019 and August 31, 2018, respectively.  As a result, we are sustaining substantial operating and net losses, and it is possible that we will never be able to sustain or develop 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.

 

As discussed in the Explanatory Note, we have 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 years ended August 31, 2019 and 2018, and included them in this Amendment. As of the date of this Amendment, we have not yet completed the restatement of our previously issued audited consolidated financial statements and related note disclosures as of and for the years ended August 31, 2020 and 2019 or the quarterly reports on form 10-Q for the periods ended November 30, 2019, February 29, 2020, May 31, 2020, November 30, 2020 and February 28, 2021. 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 is 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 II, Item 1. - Legal Proceedings and elsewhere in this Amendment. 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.

 

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, 2019, we had issued and outstanding notes in the principal amount of $1,272,858 and convertible notes in the principal amount of $6,329,469 to certain private investors which mature between January 1, 2019 and August 31, 2020 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.

 

17

 

 

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.

 

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

 

At August 31, 2019, we had not yet achieved profitable operations, had accumulated losses of ($78,285,282) since our inception and a working capital deficit of ($9,268,763), 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 four years. As at August 31, 2018 and August 31, 2017, we had an accumulated deficit of ($62,497,396) and ($46,856,367), respectively and a working capital deficit of ($374,567) and ($4,250,552), respectively. The opinion of our independent registered accounting firm on our audited financial statements for the years ended August 31, 2019 and 2018 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.

 

18

 

 

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

 

Our operations are dependent upon us maintaining our mineral lease for the Asphalt Ridge Property.

 

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. We recently moved our processing facility to the TMC Mineral Lease site. The TMC Mineral Lease is subject to termination under various circumstances, including our non-payment of certain advance and production royalties as well as a failure to comply with certain minimum production requirements and receiving funding commitments for expanding or building additional production facilities. We currently intend to fund the expansion/additional facilities through revenue generated from the processing facility at the TMC Mineral Lease, which to date has been minimal, and/or third party funding sources for which we currently have no commitments. If the TMC Mineral Lease were to be terminated, our operations would be significantly impacted until such time that we were able to relocate our processing facility to a site within the SITLA Lease or to secure other acceptable mineral leases for our operations. Any relocation of our 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 the SITLA 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.

 

19

 

 

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.

 

The Sarbanes-Oxley Act requires, among other things, that we 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.

 

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.

 

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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 Sarbanes-Oxley Act requires, among other things, that we maintain effective internal controls for financial reporting and disclosure controls and procedures. In particular, 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.

 

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.

 

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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.

 

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.

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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.

 

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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.

 

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.

 

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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.

  

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.

 

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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.

  

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, 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.

 

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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.

 

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.

 

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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.

  

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.

 

We currently have share purchase warrants to purchase 43,689,556 common shares outstanding at exercise prices ranging from US$0.37 to US$3.55 (CDN$4.725) and options to purchase 9,808,333 common shares with a weighted average exercise price of CDN $1.20 and notes convertible into 16,037,862 common shares based on conversion prices ranging from $0.18 to $1.00 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.

 

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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.

 

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.

 

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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 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 acquire our direct control, 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 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 acquire our direct control and the value of our assets equaled 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 2018 threshold for WTO investors that are SOEs will be CDN$398 million based on the book value of the Canadian business’ assets, up from CDN$379 million in 2017.

 

The 2018 thresholds for review for direct acquisitions of control of Canadian businesses by private sector investor WTO investors (CDN$1 billion) and private sector trade-agreement investors (CDN$1.5 billion) remain the same and are both based on the “enterprise value” of the Canadian business being acquired.

 

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:

 

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;

 

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

 

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.

 

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 and NASDAQ 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 if we were required to comply with the 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.

 

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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,” or EGC, as defined in the Jumpstart Our Business Start-ups Act of 2012, or the JOBS Act. For as long as we continue to be an EGC, 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, or Section 404, 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 EGC, 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 EGC. We could be an EGC for up to five years, although circumstances could cause us to lose that status earlier, including if the aggregate market value of our common shares held by non- affiliates exceeds $700 million as of any February 28 (the end of our second fiscal quarter) before that time, in which case we would no longer be an EGC as of the following August 31 (our fiscal year-end). 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.

 

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

 

As of August 31, 2018, 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.

 

Item 1B. Unresolved Staff Comments

 

Not applicable. 

 

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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 $4,941 for the approximately 2,196 square foot premises and the lease term is five years.

 

We also lease 500 square feet of laboratory space in San Diego pursuant to the terms of a lease agreement that commenced January 1, 2018 and expires on December 31, 2019. The monthly rent for this laboratory facility is $5,000.

 

Petrobloq’s headquarters are located at 4768 Park Granada, Calabasas, California 91302. The monthly base rent is $3,870 for the 1,800 square foot premises and the lease is for a three-year term.

 

TMC and PQE Oil hold 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 2,541.76 acres in the Asphalt Ridge area of Utah (Uintah County), including 1,229.82 acres held under the TMC Mineral Lease and an additional 833.03 and 478.91 acres, respectively, held under the SITLA Leases. In addition, TMC recently 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 processing facility, which currently covers an area of approximately 20,000 square feet and is located on three acres of land within our TMC Mineral Lease in Uintah County, Utah.

 

A map of the TMC Mineral Lease property is set forth below:

 

 

 

Figure 1. The Index map showing the location of the PQE Oil’s Asphalt Ridge Mine #1 located within the TMC Mineral Lease on lands situated in Uintah County, Utah.

 

Source: JT Boyd, 2015.

 

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 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.

 

 

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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 site once our plant is fully operational. In terms of the additional disclosure required, we provide the following information.

 

1.TMC Mining Operations:

The TMC mining operation is conducted at the TMC Mineral Lease on 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, particularly the acreage located in T5S-R21E (Section 25) and T5S-R22E (Section 31) where our 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.

 

(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

 

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PART II.

 

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

 

Quotations for our common shares are included in the Toronto Ventures Exchange Market TSQV under the symbol “PQE.V”.

 

At December 13, 2019, there were approximately 252 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.

 

Transfer Agent and Registrar

 

The transfer agent and registrar for our common stock is Computershare Limited.

 

Equity Compensation Plan Information

 

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

 

Recent Sales of Unregistered Securities

 

As at August 31, 2019, there were 176,241,746 common shares issued and outstanding, which are listed for trading on the TSXV, share purchase warrants to purchase 38,734,629 common shares were outstanding and share purchase options to purchase 9,808,333 common shares were outstanding under the 2018 Option Plan (or its predecessors plans) and 25,440,016 shares reserved for other issuances. See Item 6.B “Compensation – Stock Plan” for additional information regarding the 2018 Option Plan (or its predecessors plans).

 

The following sets forth information regarding our share capital issuances that have not previously been reported. None of these transactions involved any underwriters, underwriting discounts or commissions, or any public offering.

 

1. On July 5, 2019, we issued to seven (7) U.S. accredited investors and seven (7) non U.S. investors an aggregate of 6,732,402 common shares and warrants exercisable for 4,501,980 common shares at exercise prices ranging from $0.25 to $0.40 per share,  pursuant to a private offering for aggregate gross proceeds of $1,511,025.
   
2. On July 19, 2019, we issued to a U.S. accredited investor a $300,000 convertible debenture due October 19, 2020, convertible into common shares at $0.19 per share, for net proceeds of $234,000 after certain legal expenses, and warrants exercisable for 1,315,789 common shares at an exercise price of $0.24 per share.
   
3. On July 22, 2019, we issued 30,000,000 common shares to settle an outstanding liability in connection with a lease acquisition to a U.S accredited investor.
   
4. On August 7, 2019, we issued 410,000 common shares in settlement of $93,500 of debt to two (2) U.S. accredited investors.
   
5. On August 15, 2019, we issued 838,714 common shares to our attorney in settlement of $176,130 of debt.
   
6. On August 16, 2019, we issued to four (4) U.S. accredited investors and five (5) non U.S. investors an aggregate of 5,481,349 common shares and warrants exercisable for 4,683,725 common shares at exercise prices ranging from US$0.18 to US$0.29 per share, pursuant to a private placement for aggregate gross proceeds of $774,585, including 246,153 common shares issued to Aleksandr Blyumkin, the chairman of the board for gross proceeds of $32,000.
   
7. On August 19, 2019, we issued to a U.S. accredited investor a $480,000 convertible debenture due August 29, 2020, convertible into common shares at $0.17 per share, for net proceeds of $374,980 after certain legal expenses, and warrants exercisable for 2,666,666 common shares at an exercise price of $0.15 per share.
   
8. On August 21, 2019, we issued 50,000 common shares to a U.S. accredited investor for services rendered.
   
9. On August 27, 2019 we issued 1,328,809 common shares to twenty (20) U.S. accredited investors and one (1) non U.S. investor in settlement of $405,550 of debt.
   
10. On September 17, 2019, we issued to a U.S. investor a 7% convertible debenture of $240,000 due December 17, 2020, including an original issue discount of $40,000, convertible into common shares at $0.26 per share, to an investor for net proceeds of $200,000.
   
11. On September 19, 2019, we issued 6,091,336 common shares to six (6) U.S. accredited investors and one (1) non U.S. investor pursuant to a private offering for gross proceeds of $791,874, including 696,153 common shares issued to Aleksandr Blyumkin, the chairman of the board for gross proceeds of $90,500.
   
12. On September 20, 2019, we issued to one (1) U.S. accredited investor and one (1) non U.S. investor an aggregate of 9,444,444 common shares and warrants exercisable for 1,111,111 common shares at an exercise price of  $0.23 per share, pursuant to a private placement for aggregate gross proceeds of $1,700,000.

 

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13. On September 24, 2019, we issued 1,290,000 common shares in settlement of $456,750 of debt to six (6) U.S. accredited investors and one (1) non U.S. investor.
   
14. On September 30, we issued to one (1) non U.S. investor an aggregate of 2,777,777 common shares and warrants exercisable for 2,777,777 common shares at an exercise price of  $0.23 per share, pursuant to a private placement for aggregate gross proceeds of $500,000.
   
15. On October 11, 2019, we issued to a U.S. investor a 12% convertible debenture of $158,000 due October 11, 2020, including an original issue discount of $13,000, convertible into common shares at a 25% discount to the 3 lowest trading prices during the prior 15 trading days, for net proceeds of $143,000.

 

16. On October 14, 2019, we issued to a U.S. investor a 7% convertible debenture of $240,000 due January 14, 2021, including an original issue discount of $40,000, convertible into common shares at $0.20 per share for net proceeds of $200,000.
   
17. On October 28, 2019, we issued 1,891,666 common shares in settlement of $422,833 of debt to two (2) U.S. accredited investors and four (4) non U.S. investors.
   
18. On October 29, 2019, we issued to a non U.S. investor a 10% convertible debenture of $200,000 due October 29, 2020 convertible into common shares at $0.18 per share for net proceeds of $200,000.
   
19. On November 14, 2019, we issued 352,000 common shares in settlement of $70,400 of debt to one (1) U.S. accredited investor.
   
20. On November 21, 2019, we issued 50,000 common shares to a U.S. accredited investor for services rendered.

 

All sales to U.S. persons in each of the transactions set forth above were issued relying on Section 4(a)(2) of the Securities Act and/or Rule 506 promulgated thereunder, except for debt conversions which were effected relying on Section 3(a)(9) of the Securities Act as the common stock was exchanged by us with our existing security holders exclusively and no commission or other remuneration was paid or given directly or indirectly for soliciting such exchange. The recipients of the securities in each of these transactions relying on Section 4(a)(2) of the Securities Act and/or Rule 506 promulgated thereunder represented their intentions to acquire the securities for investment only and not with a view to or for sale in connection with any distribution thereof, and appropriate legends were placed upon the stock certificates issued in these transactions. All recipients had adequate access, through their employment or other relationship with us or through other access to information provided by us, to information about us. The sales of these securities were made without any general solicitation or advertising.

 

All sales to non U.S. persons in each of the transactions set forth above were issued relying on Regulation S. The recipients of the securities in each of these transactions relying on Regulation S represented that they were not a U.S. Person as that term is defined in Regulation S, that at the time of purchase of the securities they were located outside the United States and that they acquired the securities solely for their own account and not for the account or the benefit of a U.S. person.

 

Issuer Purchases of Equity Securities

 

There were no issuer purchases of equity securities during the fiscal year ended August 31, 2019.

 

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.

 

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

 

Results of Operations for the years ended August 31, 2019 and August 31, 2018

 

Net Revenue, Cost of Sales and Gross Loss

 

The Company continues to run test production on its 1,000 barrel per day plant and continuing with its expansion project to increase production capacity by an additional 3,000 barrels per day. Revenue generation during the year ended August 31, 2019 of $59,335 represents the sale of hydrocarbon products to refineries to determine the commercial quality of our hydrocarbon products. Prior to August 31, 2018, due to the volatility in oil markets and the limited production capacity at the plant, no production took place during the year ended August 31, 2018, resulting in no revenue generation. During the year ended August 31, 2018, the Company relocated its production plant to the Asphalt Ridge mineral site and has expanded production capacity to approximately 1,000 barrels per day with a further expansion to 3,000 barrels per day underway. We commenced commercial production during the first quarter of fiscal 2020 (the quarter ending November 30, 2019) and expect to generate revenue from the sale of the hydrocarbon products produced during the first quarter of 2020.

 

The cost of sales during the years ended August 31, 2019 and 2018 consists of; i) advance royalty payments which may be applied against production royalties for two years after the year in which the payment was made; and ii) certain production related expenses consisting of labor and maintenance expenditure.

 

35

 

 

Expenses

 

Expenses of $14,208,398 and $15,208,270 were incurred during the years ended August 31, 2019 and 2018, respectively, a decrease of $999,872 or 6.6%. The decrease in operating expenses is primarily due to:

 

Depletion, depreciation and amortization

 

Depletion, depreciation and amortization of $73,650 and $51,181 for the years ended August 31, 2019 and 2018, respectively, an increase of $22,469 or 43.9%. 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 during the first quarter of fiscal 2020. The increase in depreciation expense is primarily related to office leasehold improvements during the current fiscal year.

 

Selling, general and administrative expenses

 

Selling, general and administrative expenses of $11,543,432 and $14,309,914 for the years ended August 31, 2019 and 2018, respectively, a decrease of $2,766,482 or 19.3%. Included in selling, general and administrative expenses are the following major expenses:

 

  a. Investor relations fees were $302,742 and $2,487,029 for the years ended August 31, 2019 and 2018, a decrease of $2,184,287 or 87.8%. The decrease is primarily due to management concentrating its efforts and resources on completing the plant re-commissioning for an anticipated start up in the first quarter of fiscal 2020.  
     
  b. Professional fees were $6,194,176 and $3,582,986 for the years ended August 31, 2019 and 2018, respectively, an increase of $2,611,190. The increase is primarily related to legal fees incurred on the expansion of the plant, the recent filing of the Registration Statement on Form 10G/A with the SEC in the United States; the various fund-raising initiatives undertaken by the Company during the current fiscal period; and professional fees incurred on the plant expansion and management advisory fees incurred during the current fiscal year.
     
  c. Public relations fees were $1,182,103 and $921,223 for the years ended August 31, 2019 and 2018, respectively, an increase of $260,880 or 28.3%. The increase in public relations fees is due to communications about our plant expansion which has recently been completed and commercial production has recommenced.
     
  c. Salaries and wages were $1,404,793 and $511,260 for the years ended August 31, 2019 and 2018, respectively, an increase of $893,533 or 174.8%. The increase in salaries and wages expense is primarily due to the increase in headcount as the Company plans for commercial production of hydrocarbon products, an increased headcount on administrative functions; and in the prior period all plant salaries and wages were capitalized during the plant expansion process. During the current fiscal period we ceased capitalizing salaries and wages expenses as the plant expansion was substantially completed and personnel were concentrating their efforts on plant testing and maintenance functions.
     
  d. Share based compensation was $916,240 and $5,980,322 for the years ended August 31, 2019 and 2018, respectively, a decrease of $5,064,082 or 84.7%. The decrease related to stock options with immediate vesting issued to certain directors in the prior fiscal year. The current fiscal year charge represents the charge for stock options with a three year vesting period.
     
  e. Travel and promotional expenses were $683,409 and $127,757 for the years ended August 31, 2019 and 2018, respectively, an increase of $555,652 or 434.9%. The increase is primarily related to travel expense incurred by management and professionals directly attributed to the expansion and completion of the plant.

 

Financing costs

 

Financing costs were $1,225,435 and $811,432 for the years ended August 31, 2019 and 2018, respectively, an increase of $414,003 or 51.0%. The increase is primarily due to the amortization of debt discount related to convertible notes of $1,217,340.

 

36

 

 

Impairment of investments

 

Impairment of investments was $914,468 and $0 for the years ended August 31, 2019 and 2018, respectively. We provided against our equity investment in Accord GR Energy and Recruiter.com due to inactivity in these operations and the lack of demonstrable funding in each entity to justify the carrying value of the investments.

 

Other expense (income), net

 

Other expense (income), net were $451,413 and $35,743 for the years ended August 31, 2019 and 2018, respectively, an increase of $415,670 and represents the following:

 

  a. Interest income on funds advanced to third parties of $83,067 and $5,550 for the years ended August 31, 2019 and 2018, respectively, an increase of $77,517. During the current fiscal year, the Company advanced a net amount of $459,981 to certain borrowers, these advances bear interest at 5% per annum.
     
  b. Loss on settlement of liabilities was $534,480 and $92,275 for the years ended August 21, 2019 and 2018, respectively, an increase of $442,205. We settled debt of $3,388,798 by the issuance of shares during the current fiscal year, realizing 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.
     
  c. Nonrefundable deposits received of $0 and $50,982 for the years ended August 31, 2019 and 2018, respectively, a decrease of $50,982. A nonrefundable deposit received from a debenture holder was recognized as income in the prior fiscal year.

 

Net loss before income tax and equity loss

 

Net loss before income tax and equity loss was $15,787,886 and $15,480,603 for the years ended August 31, 2019 and 2018, respectively, an increase of $307,283 or 2.0% was primarily due to the labor and maintenance expenses discussed under cost of sales above, the increase in professional fees, offset by the reduction in share based compensation, the amortization of the debt discount discussed under financing costs, net above and the provision raised against investments and equity investments as discussed under other expense (income) above.

  

Equity loss from investment in Accord GR Energy, net of tax

 

Equity loss from investment in Accord GR Energy, net of tax was $0 and $160,426 for the years ended August 31, 2019 and 2018, respectively, a decrease of $160,426 is due to the provision raised against the full equity investment during the current fiscal year as discussed under other expense (income) above.

 

Net loss and comprehensive loss

 

Net loss and comprehensive loss was $15,787,886 and $15,641,029 for the years ended August 31, 2019 and 2018, an increase of $146,857 or 0.9% is discussed above.

 

Liquidity and Capital Resources

 

As at August 31, 2019, the Company had liquidity of approximately $50,719, which is composed entirely of cash. The Company also had a working capital deficiency of approximately $9,268,763, due primarily to accounts payable, short term loans and convertible loans and accrued interest thereon which remains outstanding as of August 31, 2019. To date, we have not generated sufficient revenue to support our operating and general and administrative expenses. During the year ended August 31, 2019, we raised $12,177,513 in private placements, a further net proceeds of $517,000 from debt and $6,227,730 from convertible debt. These funds were primarily used on the expansion of the oil facility, expenditures related thereto such as professional fees, marketing costs and notes receivable advanced to third parties.

 

Subsequent to August 31, 2019, in terms of various subscription agreements entered into with third parties, we raised an additional $2,991,874 in proceeds from private equity issues and issued 18,313,557 common shares and a further 3,888,888 warrants exercisable for common shares.

 

Between September 17, 2019 and December 3, 2019, we raised an additional $902,800 from convertible debentures issued to various investors.

 

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.

 

37

 

 

Capital Expenditures

 

We have substantially completed our 1,000 barrel per day plant and expect capital expenditure to be channeled into construction of new oil extraction facilities to increase our production output. We expect to construct a further two facilities, each facility is estimated to cost $10,000,000 and minor modifications to the existing facility may cost an additional $2,000,000.

 

Other Commitments and Contingencies

 

In addition to commitments otherwise reported in this MD&A, the Company’s contractual obligations as at August 31, 2019, include:

 

       Contractual cash flows 
   Carrying       1 year       More than 5 
(in ’000s of dollars)  amount   Total(1)   or less   2 - 5 years   years 
Accounts payable  $2,082   $2,082   $2,082   $-   $- 
Accrued liabilities   774    774    774    -    - 
Convertible debenture   6,329    6,836    6,510    326    - 
Long-term debt   1,273    1,427    1,147    280    - 
   $10,458   $11,119   $10,513   $606   $- 

 

[1]Amount includes estimated interest payments.

  

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.

 

38

 

  

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, 2019 and 2018, 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, 2019, 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, 2019 and 2018, and the results of its operations and its cash flows for each of the years in the two year period ended August 31, 2019, 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 15, 2019

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

 

  

F-2

 

 

PETROTEQ ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

As at August 31, 2019 and 2018

Expressed in US dollars

  

   Notes  August 31,
2019
   August 31,
2018
 
            
ASSETS             
Current assets             
Cash     $50,719   $2,640,001 
Trade and other receivables  4   144,013    404,013 
Current portion of advanced royalty payments  7(a)   446,362    331,200 
Ore inventory  6   176,792    122,242 
Other inventory      39,038    71,390 
Related party receivables  19(c)   -    297,256 
Current portion of notes receivable  5   85,359    - 
Prepaid expenses and other current assets  1   1,499,120    331,688 
Total Current Assets      2,441,403    4,197,790 
              
Non-Current assets             
Advanced royalty payments  7(a)   421,667    467,886 
Notes receivable  5   760,384    381,550 
Mineral leases  8   34,911,143    11,111,143 
Investments  20   -    68,331 
Investment in Accord GR Energy  2(b)   -    981,137 
Property, plant and equipment  9   33,613,650    21,188,895 
Intangible assets  10   707,671    707,671 
Total Non-Current Assets      70,414,515    34,906,613 
Total Assets     $72,855,918   $39,104,403 
              
LIABILITIES             
Current liabilities             
Accounts payable  11  $2,081,756   $1,102,327 
Accrued expenses  11   2,048,399    1,900,081 
Ore Sale advances      283,976    283,976 
Current portion of long-term debt  12   1,057,163    1,027,569 
Current portion of convertible debentures  13   6,188,872    258,404 
Related party payables  19(b)   50,000    - 
Total Current Liabilities      11,710,166    4,572,357 
              
Non-Current liabilities             
Unearned advance royalties received  7(b)   -    170,000 
Long-term debt  12   215,695    598,982 
Convertible debentures  13   140,597    250,000 
Reclamation and restoration provision  14   2,970,497    583,664 
Total Non-Current Liabilities      3,326,789    1,602,646 
Total Liabilities      15,036,955    6,175,003 
              
Commitments and contingencies  26          
SHAREHOLDERS’ EQUITY             
Share capital  15,16,17   136,104,245    95,426,796 
Deficit      (78,285,282)   (62,497,396)
Total Shareholders’ Equity      57,818,963    32,929,400 
Total Liabilities and Shareholders’ Equity     $72,855,918   $39,104,403 

  

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, 2019 and 2018

Expressed in US dollars

  

   Notes  Year ended
August 31,
2019
   Year ended
August 31,
2018
 
            
Revenues from hydrocarbon sales     $59,335   $- 
Production and maintenance costs      (1,347,766)   - 
Advance royalty payments applied or expired  7(a)   (291,057)   (272,333)
Gross Loss      (1,579,488)   (272,333)
Expenses             
Depreciation, depletion and amortization  9   73,650    51,181 
Selling, general and administrative expenses  21   11,543,432    14,309,914 
Financing costs  22   1,225,435    811,432 
Impairment of investments 

2(b) 20

   914,468    - 
Other expenses (income), net  23   451,413    35,743 
Total Expenses, net      14,208,398    15,208,270 
              
Net loss before income taxes and equity loss      15,787,886    15,480,603 
Income tax expense      -    - 
Equity loss from investment of Accord GR Energy, net of tax  2(b)   -    160,426 
Net loss and Comprehensive loss      15,787,886    15,641,029 
Weighted Average Number of Shares Outstanding  18   114,166,768    64,492,911 
Basic and Diluted Loss per Share     $0.14   $0.24 

  

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, 2019 and 2018

Expressed in US dollars

  

      Number of Shares   Share       Shareholders’ 
   Notes  Outstanding   Capital   Deficit   Equity 
Balance at August 31, 2017      54,220,699    68,874,513    (46,856,367)   22,018,146 
Settlement of loans      2,485,486    1,794,080    -    1,794,080 
Conversion of debentures  13(c)   1,753,447    508,500    -    508,500 
Settlement of liabilities      1,745,393    1,710,304    -    1,710,304 
Common shares subscriptions  15,17   23,080,159    15,911,298    -    15,911,298 
Share-based payments  16(a)   125,000    95,444    -    95,444 
Share-based compensation  15   -    5,980,322    -    5,980,322 
Share purchase warrants exercised  15   1,753,447    552,335    -    552,335 
Net loss      -    -    (15,641,029)   (15,641,029)
Balance at August 31, 2018      85,163,631   $95,426,796   $(62,497,396)  $32,929,400 
Settlement of loans  15(a)   462,011    424,604    -    424,604 
Settlement of liabilities  15(b)   7,793,557    3,313,380    -    3,313,380 
Common shares subscriptions  15(c)   36,397,547    12,177,513    -    12,177,513 
Share based payment for mineral rights  15(d)   45,000,000    21,000,000         21,000,000 
Share-based payments  15(e)   1,425,000    1,364,086    -    1,364,086 
Share-based compensation  16(a)   -    916,240    -    916,240 
Beneficial conversion feature of convertible debt  13   -    728,356    -    728,356 
Fair value of convertible debt warrants issued  13   -    753,270    -    753,270 
Net loss      -    -    (15,787,886)   (15,787,886)
Balance at August 31, 2018      176,241,746   $136,104,245   $(78,285,282)  $57,818,963 

  

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, 2019 and 2018

Expressed in US dollars

  

   Year ended
August 31,
2019
   Year ended
August 31,
2018
 
         
Cash flow used for operating activities:          
Net loss  $(15,787,886)  $(15,641,029)
Adjustments to reconcile net loss to net cash used in operating activities          
Depreciation, depletion and amortization   73,650    51,181 
Amortization of debt discount   1,217,340      
Loss on conversion of debt   99,548    95,444 
Impairment of investment in Accord GR Energy and Recruiter.com   914,468    - 
Loss on settlement of liabilities   434,933    92,275 
Share-based compensation   916,240    5,980,322 
Shares issued for services   470,602    - 
Equity loss from investment in Accord GR Energy   -    160,426 
Other   218,386    1,579 
Changes in operating assets and liabilities:          
Accounts payable   3,474,380    1,891,383 
Accounts receivable   225,000    (454,104)
Accrued expenses   (235,765)   11,164 
Prepaid expenses and deposits   129,568    (238,869)
Inventory   (22,198)   (193,632)
Net cash used for operating activities   (7,871,734)   (8,243,860)
           
Cash flows used for investing activities:          
Purchase and construction of property and equipment   (7,932,937)   (6,314,457)
Purchase of mineral lease rights   (1,800,000)   (19,755)
Mineral rights deposits paid   (1,297,000)   - 
Investment in notes receivable   (2,694,000)   - 
Proceeds from notes receivable   1,043,500    - 
Advance royalty payments - net   (360,000)   (534,296)
Net cash used for investing activities   (13,040,437)   (6,868,508)
           
Cash flows from financing activities:          
Advances from related parties   347,256    838,846 
Proceeds on private equity placements   12,177,514    15,911,409 
Proceeds from share purchase warrants exercised   -    552,335 
Payments of long-term debt   (546,611)   (4,685,836)
Proceeds from long-term debt   517,000    4,830,195 
Proceeds from convertible debt   6,227,730    250,000 
Proceeds from convertible debt   (400,000)   - 
Net cash from financing activities   18,322,889    17,696,949 
           
(Decrease) Increase in cash   (2,589,282)   2,584,581 
Cash, beginning of the period   2,640,001    55,420 
Cash, end of the period  $50,719   $2,640,001 
           
Supplemental disclosure of cash flow information          
Cash paid for interest  $19,700   $44,997 

     

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, 2019 and 2018

Expressed in US dollars

  

1.GENERAL INFORMATION

 

Petroteq Energy Inc. (the “Company”) is an Ontario, Canada corporation which conducts oil sands mining and oil extraction operations in the USA. It operates through its indirectly wholly owned subsidiary company, Petroteq Oil Sands Recovery, LLC (“PQE Oil”), which is engaged in mining and oil extraction from tar sands.

  

The Company’s registered office is located at Suite 6000, 1 First Canadian Place, 100 King Street West, Toronto, Ontario, M5X IE2, Canada and its principal operating office is located at 15315 W Magnolia Blvd, Suite 120, Sherman Oaks, California 91403, USA.

 

PQE Oil is engaged in a tar sands mining and oil processing operation, using a closed-loop solvent based extraction system that recovers bitumen from surface mining, and has completed the construction of an oil processing plant in the Asphalt Ridge area of Utah.

 

On July 4, 2016, the Company acquired 57.3% of the issued and outstanding common shares of Accord which, due to additional share subscriptions in Accord by other shareholders since August 31, 2016, was reduced to 44.7% as of August 31, 2017. The investment in Accord has therefore been recorded using the equity method for the years ended August 31, 2018 and 2017. Due to inactivity and the lack of adequate investment in Accord, the Company has written down its carrying value of the investment in Accord to $0 as of August 31, 2019.

  

In November 2017, the Company formed a wholly owned subsidiary, Petrobloq, LLC, to design and develop a blockchain-powered supply chain management platform for the oil and gas industry.

  

On June 1, 2018, the Company finalized the acquisition of a 100% interest in two leases for 1,312 acres of land within the Asphalt Ridge, Utah area.

 

On January 18, 2019, the Company made a cash deposit of $1,800,000 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 $1,800,000 cash deposit 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 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 $13,000,000 was settled by the issuance of 30,000,000 shares at an issue price of $0.40 per share, and a cash consideration of $1,000,000, which has not been paid as yet.

 

Between March 14, 2019 and August 22, 2019, the Company made cash deposits of $1,297,000, 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 U.S. Department of Interior’s Bureau of Land Management (“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 $1,297,000 cash deposit, with the balance of $1,703,000 still outstanding.

  

F-7

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2019 and 2018

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 15, 2019. 

  

(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 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, 2019, 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-8

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2019 and 2018

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

  

Impact of ASC 606 Adoption

  

In January 2018, the Company adopted ASC 606 – Revenue from Contracts with Customers (ASC 606). Since the Company does not have any existing contracts, ASC 606 will be applied to all future contracts with customers. ASC 606 supersedes previous revenue recognition requirements in ASC 605 – Revenue Recognition and includes 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-9

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2019 and 2018

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 25. 

  

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-10

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2019 and 2018

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-11

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2019 and 2018

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-12

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2019 and 2018

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-13

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2019 and 2018

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

  

Recently adopted

 

In January 2018, the Company adopted ASU 2014-09, Revenue from Contracts with Customers (ASC 606), using the modified retrospective method. See revenue recognition section above for further discussion regarding the Company’s adoption of this revenue recognition standard.

 

In January 2018, the Company adopted ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash. This ASU requires an entity to show the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statement of cash flows and to provide a reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. The adoption of this ASU did not have a material impact on the Company’s consolidated statements of cash flows.

 

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.

 

On February 25, 2016, the FASB issued ASU 2016-02, Leases (Topic 842)

 

Effective September 1, 2019, the Company will adopt the Financial Accounting Standards Board’s standard, Leases (Topic 842), as amended. The standard requires all leases to be recorded on the balance sheet as a right of use asset and a lease liability. The company intends to use a transition method that applies the new lease standard at September 1, 2019, and recognizes any cumulative effect adjustments to the opening balance of fiscal year 2020 retained earnings. The Company intends to apply a policy election to exclude short-term leases from balance sheet recognition and also intends to elect certain practical expedients at adoption. As permitted under these expedients the company will not reassess whether existing contracts are or contain leases, the lease classification for any existing leases, initial direct costs for any existing lease and whether existing land easements and rights of way, that were not previously accounted for as leases, are or contain a lease.

 

The Company is currently assessing the impact of the adoption of this ASU on the consolidated financial statements.

  

In November 2018, the FASB issued ASU 2018-18, Collaborative Arrangements (Topic 808) Clarifying the Interaction between Topic 808 and Topic 606.

  

A collaborative arrangement, as defined by the guidance in Topic 808, is a contractual arrangement under which two or more parties actively participate in a joint operating activity and are exposed to significant risks and rewards that depend on the activity’s commercial success. Topic 808 does not provide comprehensive recognition or measurement guidance for collaborative arrangements, and the accounting for those arrangements is often based on an analogy to other accounting literature or an accounting policy election.

  

The amendments in this Update provide guidance on whether certain transactions between collaborative arrangement participants should be accounted for with revenue under Topic 606. The amendments in this Update make targeted improvements to generally accepted accounting principles (GAAP) for collaborative arrangements as follows:

  

  1. Clarify that certain transactions between collaborative arrangement participants should be accounted for as revenue under Topic 606 when the collaborative arrangement participant is a customer in the context of a unit of account. In those situations, all the guidance in Topic 606 should be applied, including recognition, measurement, presentation, and disclosure requirements.
     
  2. Add unit-of-account guidance in Topic 808 to align with the guidance in Topic 606 (that is, a distinct good or service) when an entity is assessing whether the collaborative arrangement or a part of the arrangement is within the scope of Topic 606
     
  3. Require that in a transaction with a collaborative arrangement participant that is not directly related to sales to third parties, presenting the transaction together with revenue recognized under Topic 606 is precluded if the collaborative arrangement participant is not a customer.  

  

F-14

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2019 and 2018

Expressed in US dollars

 

2.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued)

 

(r)Recent accounting standards (continued)

 

For public business entities, the amendments in this Update are effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. Early adoption is permitted, including adoption in any interim period. An entity may not adopt the amendments earlier than its adoption date of Topic 606. The amendments in this Update should be applied retrospectively to the date of initial application of Topic 606. An entity should recognize the cumulative effect of initially applying the amendments as an adjustment to the opening balance of retained earnings of the later of the earliest annual period presented and the annual period that includes the date of the entity’s initial application of Topic 606. An entity may elect to apply the amendments in this Update retrospectively either to all contracts or only to contracts that are not completed at the date of initial application of Topic 606. An entity should disclose its election.

 

The impact of this ASU on the consolidated financial statements is not expected to be material.

 

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, 2019, has an accumulated deficit of $78,285,282, (August 31, 2018 - $62,497,396) and working capital (deficiency) of $9,268,763 (August 31, 2018 - $374,567). 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.

  

4.ACCOUNTS RECEIVABLE

 

The Company’s accounts receivables consist of:

  

   August 31,
2018
   August 31,
2018
 
         
Goods and services tax receivable  $59,013   $59,013 
Other receivables   85,000    345,000 
   $144,013   $404,013 

 

Information about the Company’s exposure to credit risks for trade and other receivables is included in Note 28(a).

  

5.NOTES RECEIVABLE

  

The Company’s notes receivables consist of:

  

          Principal
due
   Principal
due
 
   Maturity Date  Interest Rate   August 31,
2019
   August 31, 
2018
 
                
Private debtor  March 15, 2020   5%  $76,000   $76,000 
Private debtor  August 20, 2021   5%   642,581    - 
Private debtor  August 20, 2021   5%   117,000    300,000 
Interest accrued           10,162    5,550 
           $845,743   $381,550 
                   
Disclosed as follows:                  
Current portion          $85,359   $- 
            760,384    381,550 
           $845,743   $381,550 

 

F-15

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2019 and 2018

Expressed in US dollars

 

6.ORE INVENTORY

 

On June 1, 2015, the Company acquired a 100% interest in TMC Capital LLC, which holds the rights to mine ore from the Asphalt Ridge deposit. The mining and crushing of the bituminous sands has been contracted to an independent third party.

 

During the year ended August 31, 2019, the cost of mining, hauling and crushing the ore, amounting to $176,792 (2018 - $122,242), was recorded as the cost of the crushed ore inventory.

 

7.ADVANCED ROYALTY PAYMENTS

  

  (a) Advance royalty payments to Asphalt Ridge, Inc.

  

During the year ended August 31, 2015, the Company acquired TMC Capital, LLC, 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 can be used to offset future production royalties for a maximum of two years following the year the advance royalty payment was made.

  

On October 1, 2015, the Company and Asphalt Ridge, Inc. amended the advance royalty payments in the TMC Mineral Lease. All previous advance royalty payments required under the original agreement were deemed to be paid in full. The amended advance royalty payments required were: $60,000 per quarter from October 1, 2015 to September 30, 2017, $100,000 per quarter from October 1, 2017 to June 30, 2020 and $150,000 per quarter thereafter.

  

On March 12, 2016, a second amendment was made to the TMC Mineral Lease. The amended advanced royalty payments required are $60,000 per quarter from October 1, 2015 to February 28, 2018, $100,000 per quarter from March 1, 2018 to December 31, 2020 and $150,000 per quarter thereafter.

 

Effective February 21, 2018, a third amendment was made to the TMC Mineral Lease. The amended advanced royalty payments required are $100,000 per quarter from July 1, 2018 to June 30, 2020 and $150,000 per quarter thereafter.

 

As at August 31, 2019, the Company has paid advance royalties of $2,250,336 (2018 - $1,890,336) to the lease holder, of which a total of $1,382,307 have been used to pay royalties as they have come due under the terms of the TMC Mineral Lease. During the year ended August 31, 2019, $360,000 in advance royalties were paid and $291,057 have been used to pay royalties which have come due. The royalties expensed have been recognized in cost of goods sold on the consolidated statements of loss and comprehensive loss.

 

As at August 31, 2019, the Company expects to record minimum royalties paid of $446,362 from these advance royalties either against production royalties or for the royalties due within a two year period.

  

  (b) Unearned advance royalty payments from Blackrock Petroleum, Inc.

  

During the year ended August 31, 2015, the Company entered into a sublease agreement with Blackrock Petroleum, Inc. (“Blackrock”), pursuant to which it received $170,000 of unearned advance royalties. The sublease was for a portion of the mining and mineral lease with Asphalt Ridge, Inc. (Note 8(b)). Blackrock is a company associated with Accord and the sublease was effectively terminated in the acquisition by the Company of control of Accord on July 4, 2016. The advanced royalty payment has been offset against the investment in Accord and receivables due from Accord, which have been fully provided for (Note 2(b)).

  

F-16

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2019 and 2018

Expressed in US dollars

  

8.MINERAL LEASES

 

   TMC   SITLA   BLM     
   Mineral   Mineral   Mineral     
   Lease   Lease   Lease   Total 
Cost                
August 31, 2017  $11,091,388   $     -   $     -   $11,091,388 
Additions   -    19,755    -    19,755 
August 31, 2018   11,091,388    19,755    -    11,111,143 
Additions   -    -    23,800,000    23,800,000 
August 31, 2019  $11,091,388   $19,755   $23,800,000   $34,911,143 
                     
Accumulated Amortization                    
August 31, 2017, 2018 and 2019  $-   $-   $-   $- 
                     
Carrying Amounts                    
August 31, 2017  $11,091,388   $-   $-   $11091,388 
August 31, 2018  $11,091,388   $19,755   $-   $11,111,143 
August 31, 2019  $11,091,388   $19,755   $23,800,000   $34,911,143 

  

  (a) TMC Mineral Lease

  

On June 1, 2015, the Company acquired TMC Capital, LLC (“TMC”). TMC holds a mining and mineral lease, subleased from Asphalt Ridge, Inc., on the Asphalt Ridge property located in Uintah County, Utah (the “TMC Mineral Lease”).

 

The primary term of the TMC Mineral Lease is from July 1, 2013 to July 1, 2018. During the primary term, the Company must meet certain requirements for oil production. After July 1, 2018, the TMC Mineral Lease will remain in effect as long as certain requirements for oil production continue to be met by the Company. If the Company fails to meet these requirements, the lease will automatically terminate 90 days after the calendar year in which the requirements are not met. In addition, the Company is required to make certain advance royalty payments to the lessor (Note 7(a)). The TMC Mineral Lease was subject to a 10% royalty for the first three years and varying percentages thereafter based on the price of oil. An additional 1.6% royalty is payable to the previous lessees of the TMC Mineral Lease. The TMC Mineral Lease also required the Company to make minimum expenditures on the property of $1,000,000 for the first three years, increasing to $2,000,000 for the next three years.

  

On October 1, 2015, the Company amended the TMC Mineral Lease to defer the requirements for oil extraction until July 1, 2016 and to include the oil extraction from the MCW Mineral Lease as well. The advance royalty payments required under the TMC Mineral Lease were also amended (Note 7(a)). Production royalties were amended to 7% until June 30, 2020 and a varying percentage thereafter, based on the price of oil. Minimum expenditures were amended to $1,000,000 per year until June 30, 2020 and $2,000,000 thereafter if certain operational requirements for oil extraction are not met.

  

F-17

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2019 and 2018

Expressed in US dollars

   

8.MINERAL LEASES (continued)

  

(a)TMC mineral lease (continued)

  

On March 1, 2016, a second amendment to the TMC Mineral Lease amended the termination clause in the lease to:

  

  (i) Termination will be automatic if there is a lack of a written financial commitment to fund the proposed 3,000 barrel per day production facility prior to March 1, 2018.
     
  (ii) Cessation of operations or inadequate production due to increased operating costs or decreased marketability and production is not restored to 80% of capacity within six months of such cessation.
     
  (iii) The proposed 3,000 barrel per day plant fails to produce a minimum of 80% of its rated capacity for at least 180 calendar days during the lease year commencing July 1, 2020 plus any extension periods.
     
  (iv) The lessee may surrender the lease with 30 days written notice.
     
  (v) Breach of material terms of the lease, the lessor will inform the lessee in writing and the lessee will have 30 days to cure financial breaches and 150 days to cure any other non-monetary breach.

  

The term of the lease was extended by the termination clause, providing a written commitment is obtained to fund the 3,000 barrel per day proposed plant. The Company is required to produce a minimum average daily quantity of bitumen, crude oil and/or bitumen products, for a minimum of 180 days during each lease year and 600 days in three consecutive lease years, of:

  

  (i) By July 1, 2016 plus any extension periods, 80% of 100 barrels per day.
     
  (ii) By July 1, 2018 plus any extension periods, 80% of 1,500 barrels per day.
     
  (iii) By July 1, 2020, plus any extension periods, 80% of 3,000 barrels per day.

  

Advance royalties required are:

  

  (i) From October 1, 2015 to February 28, 2018, minimum payments of $60,000 per quarter.
     
  (ii) From March 1, 2018 to December 31, 2020, minimum payments of $100,000 per quarter.
     
  (iii) From January 1, 2021, minimum payments of $150,000 per quarter.
     
  (iv) Minimum payments commencing on July 1, 2020 will be adjusted for CPI inflation.

  

Production royalties payable are amended to 7% of the gross sales revenue, subject to certain adjustments up until June 30, 2020. After that date, royalties will be calculated on a sliding scale based on crude oil prices ranging from 7% to 15% of gross sales revenues, subject to certain adjustments.

  

Minimum expenditures to be incurred on the properties are $1,000,000 per year up to June 30, 2020 and $2,000,000 per year after that if a minimum daily production of 3,000 barrels per day during a 180 day period is not achieved.

  

On February 1, 2018, a third amendment to the TMC Mineral Lease amended the termination clause in the lease to:

  

  (i) Termination will be automatic if there is a lack of a written financial commitment to fund the proposed 1,000 barrel per day production facility prior to March 1, 2019 and another 1,000 barrel per day production facility prior to March 1, 2020.
     
  (ii) Cessation of operations or inadequate production due to increased operating costs or decreased marketability and production is not restored to 80% of capacity within six months of such cessation.
     
  (iii) The proposed 5,000 barrel per day plant fails to produce a minimum of 80% of its rated capacity for at least 180 calendar days during the lease year commencing July 1, 2020 plus any extension periods.
     
  (iv) The lessee may surrender the lease with 30 days written notice.
     
  (v) Breach of material terms of the lease, the lessor will inform the lessee in writing and the lessee will have 30 days to cure financial breaches and 150 days to cure any other non-monetary breach.

  

F-18

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2019 and 2018

Expressed in US dollars

  

8.MINERAL LEASES (continued)

  

  (a) TMC mineral lease (continued)

  

The term of the lease was extended by the extension of the termination clause, providing a written commitment is obtained to fund the 3,000 barrel per day proposed plant. The Company is required to produce a minimum average daily quantity of bitumen, crude oil and/or bitumen products, for a minimum of 180 days during each lease year and 600 days in three consecutive lease years, of:

  

  (i) By July 1, 2018 plus any extension periods, 80% of 1,000 barrels per day.
     
  (ii) By July 1, 2020 plus any extension periods, 80% of 3,000 barrels per day.
     
  (iii) By July 1, 2022, plus any extension periods, 80% of 5,000 barrels per day.

  

Advance royalties required are:

  

  (i) From July 1, 2018 to June 30, 2020, minimum payments of $100,000 per quarter.
     
  (ii) From July 1, 2020, minimum payments of $150,000 per quarter.
     
  (iii) Minimum payments commencing on July 1, 2020 will be adjusted for CPI inflation.

  

Production royalties payable are amended to 8% of the gross sales revenue, subject to certain adjustments up until June 30, 2020. After that date, royalties will be calculated on a sliding scale based on crude oil prices ranging from 8% to 16% of gross sales revenues, subject to certain adjustments.

  

Minimum expenditures to be incurred on the properties are $2,000,000 beginning July 1, 2020 if a minimum daily production of 3,000 barrels per day during a 180 day period is not achieved.

  

On November 21, 2018, a fourth amendment was made to the mining and mineral lease agreement whereby certain properties previously excluded from the third amendment were included in the lease agreement.

 

The termination clause was amended to:

  

  (i) Termination will be automatic if there is a lack of a written financial commitment to fund the proposed 1,000 barrel per day production facility prior to July 1, 2019 and another 1,000 barrel per day production facility prior to July 1, 2020.
     
  (ii) Cessation of operations or inadequate production due to increased operating costs or decreased marketability and production is not restored to 80% of capacity within six months of such cessation.
     
  (iii) The proposed 3,000 barrel per day plant fails to produce a minimum of 80% of its rated capacity for at least 180 calendar days during the lease year commencing July 1, 2021 plus any extension periods.
     
  (iv) The lessee may surrender the lease with 30 days written notice.
  (v) Breach of material terms of the lease, the lessor will inform the lessee in writing and the lessee will have 30 days to cure financial breaches and 150 days to cure any other non-monetary breach.

  

The term of the lease was extended by the termination clause, providing a written commitment is obtained to fund the 3,000 barrel per day proposed plant. The Company is required to produce a minimum average daily quantity of bitumen, crude oil and/or bitumen products, for a minimum of 180 days during each lease year and 600 days in three consecutive lease years, of:

  

  (i) By July 1, 2019 plus any extension periods, 80% of 1,000 barrels per day.
     
  (ii) By July 1, 2020 plus any extension periods, 80% of 2,000 barrels per day.
     
  (iii) By July 1, 2021, plus any extension periods, 80% of 3,000 barrels per day.

  

Minimum expenditures to be incurred on the properties are $2,000,000 beginning July 1, 2021 if a minimum daily production of 3,000 barrels per day during a 180 day period is not achieved.

  

F-19

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2019 and 2018

Expressed in US dollars

  

8.MINERAL LEASES (continued)

 

  (b) SITLA Mineral Lease (Petroteq Oil Sands 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 PQE Oil, 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 a cash deposit of $1,800,000 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 $1,800,000 cash deposit 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 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 $13,000,000 was settled by the issuance of 30,000,000 shares at an issue price of $0.40 per share, amounting to $12,000,000 and a cash consideration of $1,000,000, which has not been paid as yet.

  

F-20

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2019 and 2018

Expressed in US dollars

  

9.PROPERTY, PLANT AND EQUIPMENT

  

   Oil
Extraction
Plant
   Other
Property and
Equipment
   Total 
Cost            
August 31, 2017  $16,846,500   $315,967   $17,162,467 
Additions   6,254,535    78,588    6,333,123 
August 31, 2018   23,101,035    394,555    23,495,590 
Additions   12,454,792    43,613    12,498,405 
August 31, 2019  $35,555,827   $438,168   $35,993,995 
                
Accumulated Amortization               
August 31, 2017  $2,148,214   $107,300   $2,255,514 
Additions   -    51,181    51,181 
August 31, 2018   2,148,214    158,481    2,306,695 
Additions   -    73,650    73,650 
August 31, 2019  $2,148,214   $232,131   $2,380,345 
                
Carrying Amount               
August 31, 2017  $14,698,286   $208,667   $14,906,953 
August 31, 2018  $20,952,821   $236,074   $21,188,895 
August 31, 2019  $33,407,613   $206,037   $33,613,650 

 

(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 1,000 barrels per day. The plant has been substantially relocated to the TMC mining site and expansion of the plant to production of 1,000 barrels per day has been substantially completed.

  

The cost of construction includes capitalized borrowing costs for the year ended August 31, 2019 of $2,190,309 (2018 - $18,666) and total capitalized borrowing costs as at August 31, 2019 of $4,421,055 (2018 - $2,230,746).

 

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 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 1,000 barrels per day, and subsequently to an additional 3,000 barrels per day, the Company reevaluated the depreciation policy of the oil extraction plant and the oil extraction technologies (Note 10) 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 2019 and 2018 fiscal years as there has only been test production during these years.

 

F-21

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2019 and 2018

Expressed in US dollars

  

10.INTANGIBLE ASSETS

  

   Oil
Extraction
 
   Technologies 
     
Cost    
August 31, 2017  $809,869 
Additions   - 
August 31, 2018   809,869 
Additions   - 
August 31, 2019  $809,869 
      
Accumulated Amortization     
August 31, 2017  $102,198 
Additions   - 
August 31, 2018   102,198 
Additions   - 
August 31, 2019  $102,198 
      
Carrying Amounts     
August 31, 2017  $707,671 
August 31, 2018  $707,671 
August 31, 2019  $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 1,000 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 2019 and 2018 fiscal years.

 

11.ACCOUNTS PAYABLE AND ACCRUED EXPENSES

  

Accounts payable as at August 31, 2019 and 2018 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, 2019 and 2018 consist primarily of other operating expenses and interest accruals on long-term debt (Note 12) and convertible debentures (Note 13).

  

Information about the Company’s exposure to liquidity risk is included in Note 28(c).

  

F-22

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2019 and 2018

Expressed in US dollars

  

12.LONG-TERM DEBT

  

          Principal
due
   Principal
due
 
Lender  Maturity Date  Interest
Rate
   August 31,
2019
   August 31,
2018
 
                
Private lenders  January 15, 2020   10.00%   200,000    200,000 
Private lenders  January 1, 2020   5.00%   567,230    632,512 
Private lenders 

September 17, 2019

   10.00%   100,000    - 
Private lenders  July 28, 2020   10.00%   -    120,900 
Private lenders  August 31, 2020   5.00%   -    70,900 
Equipment loans  April 20, 2020 –
November 7, 2021
   4.30 - 12.36%   405,628    602,239 
                   
           $1,272,858   $1,626,551 

  

The maturity date of the long term debt is as follows:

  

   August 31,
2019
   August 31,
2018
 
         
Principal classified as repayable within one year  $1,057,163   $1,027,569 
Principal classified as repayable later than one year   215,695    598,982 
           
   $1,272,858   $1,626,551 

  

(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.
     
  (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 bear interest at a rate of 12% per annum, maturing 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. 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.
     
  (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 matures on September 17, 2019 and bears interest at 10% per annum. As compensation for the debenture line of credit the Company issued 950,000 commitment shares to Bay Private Equity and a further 300,000 shares as a finder’s fee to a third party.

 

F-23

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2019 and 2018

Expressed in US dollars

  

12.LONG-TERM DEBT (continued)

 

(a)Private lenders (continued)

 

  (iv) The Company received advances in the aggregate of $120,900 from various private lenders during the year ended August 31, 2018 and 2017 in the form of unsecured promissory notes. These promissory notes matured at various dates, between demand and July 28, 2020, and bore interest at 10% per annum. These loans were repaid in full.
     
  (v) The Company received advances in the aggregate of $70,900 from a private lender during the year ended August 31, 2018 and 2017 in the form of unsecured promissory notes. This promissory note matures on August 31, 2020 and bore interest at 5% per annum. On May 31, 2019, the parties entered into a debt settlement agreement and the Company issued 363,073 shares of common stock at an issue price of $0.30 per share to settle the outstanding liability of $70,900 including interest thereon of $27,130.

  

(b)Equipment loans

 

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 promissory note was secured by the crusher.

  

13.CONVERTIBLE DEBENTURES

  

          Principal
due
   Principal
due
 
Lender  Maturity Date  Interest
Rate
   August 31,
2019
   August 31,
2018
 
                
Alpha Capital Anstalt  October 31, 2018   5.00%  $-   $56,500 
Private lenders  January 1, 2019   0.00%   -    201,904 
GS Capital Partners  January 15, 2020   10.00%   143,750    - 
Calvary Fund I LP  September 4, 2019   10.00%   250,000    250,000 
Calvary Fund I LP  October 12, 2020   10.00%   250,000    - 
SBI Investments LLC  October 15, 2020   10.00%   250,000    - 
Bay Private Equity, Inc.  January 15, 2020   5.00%   2,900,000    - 
Bay Private Equity, Inc.  October 15, 2019   5.00%   2,400,000    - 
Cantone Asset Management LLC  October 19, 2020   7.00%   300,000    - 
Calvary Fund I, LP  August 29, 2020   3.30%   480,000    - 
            6,973,750    508,404 
Unamortized debt discount           (644,281)   - 
Total loans          $6,329,469   $508,404 

  

The maturity date of the convertible debentures are as follows:

 

   August 31, 2019   August 31, 2018 
         
Principal classified as repayable within one year  $6,188,872   $258,404 
Principal classified as repayable later than one year   140,597    250,000 
           
   $6,329,469   $508,404 

   

F-24

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2019 and 2018

Expressed in US dollars

  

13.CONVERTIBLE DEBENTURES (continued)

   

(a)Alpha Capital Anstalt

  

On December 15, 2015, the Company issued a convertible secured note for $555,556 to Alpha Capital Anstalt. The convertible secured note had interest at a rate of 5% per annum, matured on June 15, 2017 and was convertible into units, consisting of one common share of the Company and one common share purchase warrant of the Company.

 

On April 5, 2016, $55,556 of the principal of the convertible secured note was settled by the issuance of 22,991 common shares of the Company. The remaining $500,000 of the principal and $12,577 of accrued interest of the convertible secured note was settled on April 8, 2016 using the proceeds from the issuance of an additional convertible secured note to Alpha Capital Anstalt.

 

During the year ended August 31, 2019, the remaining principal amount of $56,500 was settled through the issue of common shares.

  

(b)Private lenders

  

According to the terms of an amendment between two debenture holders and the Company on February 9, 2018, a portion of their debentures was convertible into common shares (see Note 12(a)(ii)). On September 11, 2018, the remaining convertible portion of the debenture was converted into common shares of the Company through the issue of 316,223 common shares of the Company

  

(c)GS Capital Partners

 

On December 28, 2018, the Company issued a convertible debenture of $143,750 including an original issue discount of $18,750, together with warrants exercisable for 260,416 shares of common stock at an exercise price of $0.48 per share with a maturity date of April 29, 2019. The debenture has a term of four months and one day and bears interest at a rate of 10% per annum payable at maturity and at the option of the holder the purchase amount of the debenture (excluding the original issue discount of 15%) is convertible into 260,416 common shares of the Company at $0.48 per share in accordance with the terms and conditions set out in the debenture.

  

(d)Calvary Fund I LP

 

On September 4, 2018, the Company issued units to Calvary Fund I LP for $250,000, which was originally advanced on August 9, 2018. The units consist of 250 units of $1,000 convertible debentures and 1,149,424 common share purchase warrants. The convertible debenture bears interest at 10%, matures on September 4, 2019 and is 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 and expired on September 4, 2019.

 

(e)Calvary Fund I LP

 

On October 12, 2018, the Company entered into an agreement with Calvary Fund I LP whereby the Company issued 250 one year units for 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 warrant exercisable for 1,162 common shares at an exercise price of $0.86 per share.

 

(f)SBI Investments, LLC

  

On October 15, 2018, the Company entered into an agreement with SBI Investments LLC 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.

  

F-25

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2019 and 2018

Expressed in US dollars

  

13.CONVERTIBLE DEBENTURES (continued)

  

(g)Bay Private Equity, Inc.

  

On September 17, 2018, the Company issued 3 one year convertible units of $1,100,000 each to Bay Private Equity, Inc. (“Bay”) for net proceeds of $2,979,980. These units bear interest at 5% per annum and mature 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 Private Equity convertible debenture (see Note 13(h)).

  

(h)Bay Private Equity, Inc.

  

On January 16, 2019, the Company issued a convertible debenture of $2,400,000, including an original issue discount of $400,000, to Bay for net proceeds of $2,000,000 related to this agreement. 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 Note 13(g)).

  

(i)Cantone Asset Management, LLC

  

On July 19, 2019, the Company issued a convertible debenture of $300,000, including an original issue discount of $50,000 for net proceeds of $234,000 after certain legal expenses, and warrants exercisable for 1,315,789 common shares at an exercise price of $0.24 per share. The convertible debenture bears interest at 7% per annum and matures on October 19, 2020. The convertible debenture may be converted to 1,578,947 common shares of the Company at a conversion price of $0.19 per share.

  

(j)Calvary Fund I LP

  

On August 19, 2019, the Company issued a convertible debenture of $480,000, including an original issue discount of $80,000 for net proceeds of $374,980 after certain legal expenses, and warrants exercisable for 2,666,666 common shares at an exercise price of $0.15 per share. The convertible debenture bears interest at 3.3% per annum and matures on August 29, 2020. The convertible debenture may be converted to 2,833,529 common shares of the Company at a conversion price of $0.17 per share.

  

14.RECLAMATION AND RESTORATION PROVISIONS

 

   Oil         
   Extraction   Site     
   Facility   Restoration   Total 
Balance at August 31, 2017  $364,140   $208,080   $572,220 
Accretion expense   7,200    4,244    11,444 
Balance at August 31, 2018   371,340    212,324    583,664 
Reevaluation of reclamation and restoration provision   119,716    2,255,443    2,375,159 
Accretion expense   7,428    4,246    11,674 
Balance at August 31, 2019  $498,484   $2,472,013   $2,970,497 

  

F-26

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2019 and 2018

Expressed in US dollars

  

14.RECLAMATION AND RESTORATION PROVISIONS (continued)

   

(a)Oil Extraction Plant

  

In accordance with the terms of the lease agreement, the Company is required to dismantle its oil extraction plant at the end of the lease term, which is expected to be in 25 years. During the year ended August 31, 2015, the Company recorded a provision of $350,000 for dismantling the facility.

  

During the year ended August 31, 2019, in accordance with the requirements to provide a surety bond to the Utah Division of Oil Gas and Mining in terms of the amendment to the Notice of Intent to Commence Large Mining Operations at an estimated production of 4,000 barrels per day, the Company estimated that the cost of dismantling the oil extraction plant and related equipment would increase to $498,484. The discount rate used in the calculation is estimated to be 2.32% on operations that are expected to commence in September 2021.

 

Because of the long-term nature of the liability, the greatest uncertainties in estimating this provision are the costs that will be incurred and the timing of the dismantling of the oil extraction facility. In particular, the Company has assumed that the oil extraction facility will be dismantled using technology and equipment currently available and that the plant will continue to be economically viable until the end of the lease term.

  

The discount rate used in the calculation of the provision as at August 31, 2019 and 2018 is 2.0%.

 

(b)Site restoration

  

In accordance with environmental laws in the United States, the Company’s environmental permits and the lease agreements, the Company is required to restore contaminated and disturbed land to its original condition before the end of the lease term, which is expected to be in 25 years. During the year ended August 31, 2015, the Company provided $200,000 for this purpose.

  

The site restoration provision represents rehabilitation and restoration costs related to oil extraction sites. This provision has been created based on the Company’s internal estimates. Significant assumptions in estimating the provision include the technology and equipment currently available, future environmental laws and restoration requirements, and future market prices for the necessary restoration works required.

 

During the year ended August 31, 2019, in accordance with the requirements to provide a surety bond to the Utah Division of Oil Gas and Mining in terms of the amendment to the Notice of Intent to Commence Large Mining Operations at an estimated production of 4,000 barrels per day, the Company estimated that the cost of restoring the site would increase to $2,472,013. The discount rate used in the calculation is estimated to be 2.32% on operations that are expected to commence in September 2021.

  

The discount rate used in the calculation of the provision as at August 31, 2019 and 2018 is 2.0%.

  

F-27

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2019 and 2018

Expressed in US dollars

  

15.COMMON SHARES

  

  Authorized unlimited common shares without par value
  Issued and Outstanding 176,241,746 common shares as at August 31, 2019.

 

(a)Settlement of loans

 

On September 28, 2018, the Company issued 316,223 shares to two private investors in settlement of the remaining portion of their convertible debt of $255,078 (see Note 13(b)).

 

On December 3, 2018, the Company issued 145,788 shares of common stock to private investors in settlement of the remaining portion of their convertible debt of $56,500 including interest thereon of $13,479 (see Note 13(a)).

 

(b)Settlement of liabilities

 

Between September 4, 2018 and August 31, 2019, the Company issued 7,793,557 shares of common stock to several investors in settlement of $3,043,742 of trade debt.

  

(c)Common share subscriptions

  

On September 6, 2018, the Company issued 1,234,567 units to an investor for net proceeds of $1,000,000. Each unit consists of one share of common stock and three quarters of a share purchase warrant for a total warrant exercisable over 925,925 shares of common stock.

  

On October 11, 2018, the Company issued 81,229 shares of common stock to investors for net proceeds of $79,605. In addition, a further 752,040 units were issued to investors for net proceeds of $737,000. Each unit consisting of one share of common stock and a warrant exercisable for a share of common stock at exercise prices ranging from $1.35 to $1.50.

 

On November 7, 2018, the Company issued 320,408 units to investors for net proceeds of $169,000, each unit consisting of one share of common stock and a warrant exercisable for a share of common stock at an exercise price ranging from $0.61 to $0.66 per share.

 

On December 7, 2018, the Company issued a total of 3,868,970 shares of common stock to investors for net proceeds of $2,275,193. Certain of the subscription agreements were unit agreements, whereby warrants exercisable over 3,373,920 shares of common stock were issued to investors at exercise prices ranging from $0.67 to $1.50 per share.

   

On December 7, 2018, the Company issued 1,190,476 units to an investor for net proceeds of $500,000, each unit consisting of one share of common stock and a warrant exercisable for a share of common stock at an exercise price of $0.525 per share.

  

On January 10, 2019, the company issued a total of 1,522,080 shares of common stock to investors for net proceeds of $645,100. Certain of the subscription agreements were unit agreements, whereby warrants exercisable over 1,437,557 shares of common stock were issued to investors at an exercise price ranging from $1.00 to $1.50 per share.

  

On January 11, 2019, the Company issued 307,692 units to an investor for net proceeds of $200,000, each unit consisting of one share of common stock and a warrant exercisable for a share of common stock at an exercise price of $1.50 per share.

  

On January 25, 2019, the Company issued 147,058 units to an investor for net proceeds of $50,000, each unit consisting of one share of common stock and a warrant exercisable for a share of common stock at an exercise price of $0.37 per share.

  

On February 27, 2019, the Company issued a total of 7,242,424 shares of common stock to investors for net proceeds of $2,390,000.

  

On February 27, 2019, the Company issued 135,135 units to an investor for net proceeds of $50,000, each unit consisting of one share of common stock and a warrant exercisable for a share of common stock at an exercise price of $0.37 per share.

  

F-28

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2019 and 2018

Expressed in US dollars

  

15.COMMON SHARES (continued)

 

(c)Common share subscriptions (continued)

 

On February 27, 2019, the CEO of the Company subscribed for 62,500 shares of common stock for net proceeds of $25,000.

 

On March 11, 2019, the Chairman of the Board subscribed for 2,222,222 shares of common stock for net proceeds of $1,000,000.

 

On March 29, 2019 the Company cancelled 18,518 shares previously issued to an investor and returned the subscription proceeds of $10,000.

 

On March 29, 2019, the Company issued 1,481,481 units to an investor for net proceeds of $400,000, each unit consisting of one share of common stock and a warrant exercisable for a share of common stock at an exercise price of $0.465 per share. In addition, the Company issued 248,782 shares of common stock to investors for gross proceeds of $82,000.

  

On May 22, 2019, the Company issued 3,431,828 units to investors for gross proceeds of $886,950, each unit consisting of one share of common stock and one warrant exercisable for a share of common stock at exercise prices ranging from $0.28 to $1.50 per share, in addition, the Company issued a further 35,714 shares to a private investor for gross proceeds of $25,000.

  

On May 22, 2019, the Company issued 308,333 shares of common stock to the Chairman of the Board for gross proceeds of $74,000.

  

On July 3, 2019, the Company cancelled 390,625 shares previously issued to an investor.

 

On July 5, 2019, the Company issued 6,732,402 shares of common stock and warrants exercisable for 4,601,980 shares of common stock at exercise prices ranging from $0.25 to $0.40 per share to investors for gross proceeds of $1,180,796.

    

On August 16, 2019, the Company issued 5,481,349 shares of common stock and warrants exercisable for 4,563,725 shares of common stock at exercise prices ranging from $0.18 to $0.22 per share and further warrants exercisable 120,000 shares of common stock at an exercise price of CAD$0.29 per share, to investors for gross proceeds of $774,584.

 

(d)Share based payments for mineral rights

 

On April 1, 2019, the Company issued 15,000,000 shares valued at $9,000,000 in settlement of the remaining purchase consideration in terms of the acquisition of the BLM leases (Note 8).

 

On July 22, 2019, the Company issued 30,000,000 shares of common stock to Petrollo LP for the purchase of BLM mineral rights at an issue price of $0.40 per share (Note 8).

 

(e)Share based payments for services

 

Between September 1, 2018 and August 21, 2019, the Company issued 1,425,000 shares valued at $1,364,087 as compensation for professional services rendered to the Company, including 1,250,000 shares of common stock issued as fees for the Bay Private Equity convertible debt raise (see Note 13(g)).

 

16.STOCK OPTIONS

  

(a)Stock option plan

  

The Company has a stock option plan which allows the Board of Directors of the Company to grant options to acquire common shares of the Company to directors, officers, key employees and consultants. The option price, term and vesting are determined at the discretion of the Board of Directors, subject to certain restrictions as required by the policies of the TSX Venture Exchange. The stock option plan is a 20% fixed number plan with a maximum of 35,248,349 common shares reserved for issue at August 31, 2019.

  

During the year ended August 31, 2019, the Company did not grant any stock options to directors, officers and consultants of the Company (August 31, 2018 –9,775,000).

  

F-29

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2019 and 2018

Expressed in US dollars

  

16.STOCK OPTIONS (continued)

 

(a)Stock option plan (continued)

 

During the year ended August 31, 2019 the share-based compensation expense of $916,240 (2018 - $5,980,322) relates to the vesting of options granted during the year ended August 31, 2018.

 

(b)Stock options

  

Stock option transactions under the stock option plan were: 

 

    Year ended
August 31,  2019
    Year ended
August 31, 2018
 
    Number of Options     Weighted
average
exercise
price
    Number of options     Weighted
average
exercise
price
 
Balance, beginning of period     9,858,333     CAD$       1.22       113,333     CAD$ 12.57  
Options granted     -       -       9,775,000     CAD$ <   1.19  
Options expired     (50,000 )   CAD$ 4.80       (30,000 )   CAD$ 33.00  
Balance, end of period     9,808,333     CAD$ 1.20       9,858,333     CAD$ 1.22  

  

Stock options outstanding and exercisable as at August 31, 2019 are:

 

Expiry Date  Exercise
Price
   Options
Outstanding
   Options
Exercisable
 
February 1, 2026  CAD$5.85    33,333    33,333 
November 30, 2027  CAD$2.27    1,425,000    1,425,000 
June 5, 2028  CAD$1.00    8,350,000    

5,850,000

 
         9,808,333    7,308,333 
Weighted average remaining contractual life        8.6 years    8.6 years 

  

F-30

 

 

PETROTEQ ENERGY INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended August 31, 2019 and 2018

Expressed in US dollars

  

17.SHARE PURCHASE WARRANTS

 

Share purchase warrants outstanding as at August 31, 2019 are:

 

Expiry Date  Exercise Price   Warrants Outstanding 
September 4, 2019  US$0.87    287,356 
September 17, 2019  US$1.10    750,000 
October 12, 2019  US$0.86    290,500 
October 15, 2019  US$0.86    290,500 
November 5, 2019  CAD$28.35    25,327 
January 25, 2020  US$0.37    147,058 
February 27, 2020  US$0.37    135,135 
March 9, 2020  US$1.50    114,678 
May 22, 2020  US$0.28    678,571 
May 22, 2020  US$0.30    1,554,165 
June 7, 2020  US$0.525    1,190,476 
June 14, 2020  US$1.50    329,080 
July 5, 2020  US$0.35    200,000 
July 5, 2020  US$0.30    200,000 
July 26, 2020