HANK GRACIN†† | PARTNER
LESLIE MARLOW† | PARTNER
PATRICK EGAN† | PARTNER

 

† Admitted in New York only
†† Admitted in New York, Florida &
Colorado

GRACIN & MARLOW, LLP 

 

COUNSELLORS AT LAW
THE CHRYSLER BUILDING
26th FLOOR

405 LEXINGTON AVENUE

NEW YORK, NEW YORK 10174 

 

 

(212) 907-6457
FAX (212) 208-4657

www.gracinmarlow.com

IN BOCA RATON
1825 NW CORPORATE BLVD.
SUITE 110
BOCA RATON, FLORIDA 33431
(561) 237-0804

FAX (561) 237-0803
 

WRITER E-MAIL: lmarlow@gracinmarlow.com

 

November 30, 2018

 

VIA EDGAR

 

Securities and Exchange Commission

Division of Corporation Finance
100 F Street, NE
Washington, D.C. 20549
Attention: Lisa Krestyick

  Staff Attorney

 

Re:Petroteq Energy Inc.

Registration Statement on Form 20-FR

Filed October 11, 2018

File No. 0-55991

 

Dear Ms. Krestynick:

 

Thank you for your November 7, 2018 letter regarding Petroteq Energy, Inc. (“Petroteq” or the “Company”). In order to assist you in your review of the Company’s Registration Statement on Form 20-FR (File No. 0-55991), on behalf of the Company, we hereby submit a letter responding to the comments and Amendment No. 1 to the Form 20-F (File No. 0-55991). For your convenience, we have set forth below the staff’s numbered comments in their entirety followed by our responses thereto.

 

 

 

 

GRACIN & MARLOW, LLP

 

COUNSELLORS AT LAW

 

Securities and Exchange Commission

November 30, 2018

Page 2

 

Registration Statement on Form 20-FR

 

Item 3. Key Information

D. Risk Factors, page 4

 

1.Please tell us what consideration you have given to including a risk factor disclosing any material cybersecurity risks. Refer to Section II.A.2 of the Commission Statement and Guidance on Public Company Cybersecurity Disclosures, Release Nos. 33-10459 and 34- 82746 (Feb. 21, 2018).

 

Response: In preparing the Company’s Registration Statement on Form 20-FR 2011, the Company considered the Commission’s Statement and Guidance on Public Company Cybersecurity Disclosures, Release Nos. 33-10459 and 24-82746, along with other securities law disclosure requirements, and concluded that the risk of cyber incidents was not among the most significant factors that make an investment in the Company speculative or risky, and the costs or other consequences associated with known cyber incidents or the risk of potential cyber incidents did not represent a material event, trend, or uncertainty that was reasonably likely to have a material effect on the Company’s results of operations, liquidity, or financial condition or to cause reported financial information not to be indicative of future operating results or financial condition. The decision not to include a risk factor regarding the risk of cyber incidents was also consistent with the Staff’s guidance that registrants provide disclosure tailored to their particular circumstances, rather than generic “boilerplate” risk factor disclosure.

 

Virtually all businesses today, including the Company, face cybersecurity risks. As in all aspects of risk management, the Company has implemented and maintains systems to protect against cybersecurity breaches. To date, the Company has not experienced any cybersecurity incidents. Costs associated with the Company’s efforts to protect its assets and secure confidential information have not been material.

 

2.Please add a risk factor addressing the risks associated with your authorized share capital of an unlimited number of common shares and preferred shares.

 

Response: We have added a risk factor addressing the risks associated with the Company’s authorized share capital of an unlimited number of common shares and preferred shares.

 

Item 4. Information on the Company

B. Business Overview

Resources and Mining Operations, page 21

 

3.Please define the extension period that applies to the minimum average daily production requirements of your lease. From your Third Amendment to the TMC Mineral lease, filed as Exhibit 10.19, it appears that the period of time between March 1, 2018 and the earlier of (i) March 1, 2019 or (ii) the date on which a written financial commitment is received by the lessor for the construction of your second proposed facility is referred to as the “Extension Period.”

 

Response: Please note that the extension period in the TMC Mineral Lease has been further amended and we have added disclosure defining the extension period as amended and requested.

 

4.We note that your lease will terminate if you do not obtain written financial commitments to fund your proposed second and third production facilities by certain dates. Please disclose the expected costs of each of these facilities. If you do not know the expected costs, please revise to make that clear.

 

Response: We have added disclosure regarding the expected costs of these facilities and risk factor disclosure regarding the fact that the Company does not have any committed sources of funding.

 

 

 

 

GRACIN & MARLOW, LLP

 

COUNSELLORS AT LAW

 

Securities and Exchange Commission

November 30, 2018

Page 3

 

5.Please disclose whether you are in compliance with the provisions of your TMC Mineral lease, as amended, including:

 

the minimum production requirements, particularly the requirement that you were obligated to meet by July 1, 2018 plus the extension period;

 

the requirement to obtain written financial commitments to fund your proposed facilities; and

 

the advance royalty payments.

 

If you are not in compliance with the terms of this lease, please disclose your plans to remedy such noncompliance. In addition, please disclose any prior breaches of the lease here and in your risk factor entitled “Our operations are dependent upon us maintaining. . .. .” at page 7. By way of example only, we note that the Restatement of and Second Amendment to Mining and Mineral Lease Agreement states that the lease automatically terminated on March 1, 2016 as a result of your failure to obtain a written letter from a funding source.

 

Response: We have added disclosure regarding our compliance with the provisions of the TMC Mineral lease and confirmed that the Company is in compliance with the terms of the TMC Mineral lease.

 

6.We note your disclosure that your land holdings include 2,541.73 acres. This amount of acreage appears inconsistent with Exhibit A to the Third Amendment to Mining and Mineral Lease Agreement, which provides that the properties subject to the lease contain 916.15 acres, more or less. Please revise or advise.

 

Response: We have revised the disclosure to reflect the Fourth Amendment to the TMC Lease. Our land holdingsnow consist of 1,229.82 acres leased under the TMC Lease, and an additional 833.03 acres and 478.91 acres located near Asphalt Ridge, Utah, leased under two separate land leases with the State of Utah.

 

7.Expand the disclosure of your leasehold acreage to separately disclose the total gross and total net developed and undeveloped acreage amounts. Refer to the disclosure requirements for developed and undeveloped acreage and the definitions of gross and net acres under Items 1208(a), 1208(b) and 1208(c) of Regulation S-K, respectively.

 

Response: We have expanded the disclosure of our leasehold acreage to separately disclose the total gross and total net developed and undeveloped acreage amounts.

 

 

 

 

GRACIN & MARLOW, LLP

 

COUNSELLORS AT LAW

 

Securities and Exchange Commission

November 30, 2018

Page 4

 

8.To the extent that the 2,541.73 acres currently held include the 1,312 acres acquired at auction in 2018, expand your disclosure to discuss the dates relating to the primary term of the acquired lease(s), any conditions required to maintain your rights to this lease(s), and the duration and conditions regarding any extensions to the primary term of this lease(s), including any advance cash royalty payments and subsequent royalties payable as a percentage of sales revenues. Refer to the disclosure requirements under Item 1208(b) of Regulation S-K.

 

Response: We have added disclosure to discuss the dates relating to the primary term of the acquired leases, any conditions required to maintain our rights to the leases, and the duration and conditions regarding any extensions to the primary term of the leases.

 

9.Expand your disclosure to clarify the extent that all 2,541.73 acres currently held contain potentially economically minable ore, the average thickness of the deposit, and the maximum economic mineable depth of the current and proposed open pits.

 

Response: We have expanded our disclosure to clarify the extent that all 2,541.73 acres currently held contain potentially economically minable ore, the average thickness of the deposit, and the maximum economic mineable depth of the current and proposed open pits.

 

10.Expand the disclosure relating to the 2,541.73 acres currently held to discuss and quantify, if true, the extent that additional royalties, production, severance, and ad valorem taxes are also applicable and due to the state.

 

Response: We have expanded our disclosure to discuss the extent to which additional royalties, production, severance, and ad valorem taxes are also applicable and due to the state.

 

11.Expand your disclosure to clarify the number of gross and net acres covered under your current mining permit with the State of Utah Division of Oil, Gas, and Mining. Additionally, disclose the date upon with this permit and all local permits were granted and the date upon which such permits will expire.

 

Response: We have expanded our disclosure to clarify the number of gross and net acres covered under our current mining permit with the State of Utah Division of Oil, Gas, and Mining and disclose the date the permit and local permits were granted and their expiration terms.

 

12.Your disclosure presents certain information relating to the estimated quantities of bitumen resources, e.g. 87.495 million barrels on page 21 and 7.331 million barrels on page F-45, that appear to conflict with guidance pertaining to disclosure of oil and gas activities pursuant to Items 1201(a) and 1201(c) of Regulation S-K. Specifically, the Instruction to Item 1202 of Regulation S-K, applicable by way of Instruction 2 to Item 4 of Form 20-F, generally prohibits disclosure in any document publicly filed with the Commission of estimates and values of oil and gas resources other than reserves. Therefore, if your estimates do not qualify as reserves under Rule 4-10(a) of Regulation SX, please revise accordingly.

 

Response: We have removed the disclosure relating to the estimated quantities of bitumen resources.

 

 

 

 

GRACIN & MARLOW, LLP

 

COUNSELLORS AT LAW

 

Securities and Exchange Commission

November 30, 2018

Page 5

 

13.Your tabular disclosure of production is provided in “net barrels.” Please expand your disclosure to explain your use of the term and the factors you considered in calculating the “net” monthly production figures presented on page 22. In this regard, Instruction 1 to Item 1204 indicates that net production should generally include only production that is owned by the registrant and produced to its interest, less royalties and production due to others.

 

Response: We have expanded our disclosure to explain our use of the term “net barrels”.

 

14.Expand your disclosure of the monthly produced volumes for fiscal year 2015 to clarify, if true, that the net barrels disclosed represent a blend of extracted bitumen and purchased hydrocarbons, e.g. solvents remaining in the blend and subsequently sold.

 

Response: We have not expanded the disclosure referenced because we do not view PQE’s net barrels as being a blend of extracted bitumen and purchased hydrocarbons and we do not view PQE as being in the business of selling bitumen and solvent. PQE markets crude oil products that it has been able to develop from extracted bitumen using its proprietary process. In that process, depending upon the customer’s request for an API level (the extracted bitumen starts from the ground at an average API gravity of 10 degrees), through the use of a distillation process and a solvent which we develop ourselves from natural gas condensate, ordinary chemicals and recycled solvent (the solvent can be used at least four times), the hydro-carbons in the extracted bitumen are manipulated. The higher the temperature, the higher the resultant API, more hydrocarbons are removed and more solvent is used. The crude oil produced and sold to the customer is not bitumen and not solvent, it is not a “blend” of separate products and does not include diluent. It is a hydro-carbon, a distinct product having its own specifications.

 

As such, in the refining process no diluents or blending agents are used to increase the viscosity of the heavy oil extracted from bitumen saturated ores. Instead, varying amounts of solvent is introduced into a mixing tank with a raw bitumen-saturated stream generated from the initial treatment of mined or extracted oil sands ores and sands (via crushing etc.). The solvent is designed to release crude oil from bitumen-saturated sandstones during processing. This process yields an unfinished crude oil containing the solvent on the one hand, and a second residual consisting of clean sand (containing little to no hydrocarbons).

 

The hydrocarbon stream containing the solvent is then subjected to a distillation process where the solvent is recovered and recycled for reuse in future process streams. However, during the recovery of the solvent through reboiling and distillation, 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 condensate in the solvent (whether it the heavier hydrocarbons such as the C5 pentanes/pentenes or C6 hexanes, or the lighter hydrocarbons such as methane (C1), ethane (C2), propane (C3) and the butanes (C4), 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).

 

 

 

 

GRACIN & MARLOW, LLP

 

COUNSELLORS AT LAW

 

Securities and Exchange Commission

November 30, 2018

Page 6

 

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 causing a release of heavy oil from the bitumen-saturated stream, and (2) a feedstock that, during distillation or reboiling with a second feedstock consisting of the heavy crude oil stream extracted from bitumen, produces a finished crude oil product. The solvent that is not recovered in the refining process effectively acts as a feed stock to create the crude oil.

 

We disagree with a characterization of finished crude oil products generated through distillation and other refining processes using hydrocarbon feedstocks as being a “blend of purchased hydrocarbons”.

 

All hydrocarbon products are generated through basic application of chemistry in refining and processing (e.g. distillation, cracking etc.) utilize one or more hydrocarbon feedstocks (typically a “slate” of crude oils ranging from heavier oils to condensates). In most hydrocarbon refining and processing facilities today, virtually all of the feedstocks are “purchased”. Very few hydrocarbon refining and processing facilities in the world today rely exclusively on feedstocks produced by the facility or in oil and gas fields dedicated to a facility under common ownership.

 

At virtually all hydrocarbon and processing facilities that process, refine and manufacture partially finished and finished hydrocarbon products utilizing a “crude slate” of various crude oils and hydrocarbon feedstocks (including processes that may utilize solvents and catalysts that are mostly recovered and recycled in the specific refining process in which they are used), virtually all such crude oils and hydrocarbons utilized as feedstocks for upgraded crude oils and refined products are “purchased” from the outside. Through refining and processing (whether it be distillation, cracking hydrotreating etc.), the feedstocks used to generate a new hydrocarbon product having its own specifications.

 

To illustrate, if a hydrocarbon or processing facility utilizes Venezuelan crude (heavy), an Arabian Medium crude (middle) and an Australian condensate as feedstocks that, through distillation, cracking etc, produce a low sulfur diesel fuel (middle distillate), we believe it would be erroneous to characterize the finished low-sulfur diesel fuel product as nothing more than a “blend” of “purchased hydrocarbons”, or require a disclosure of each of the feedstocks separately (the slates and formulations of which are usually proprietary) as separate “products”.

 

Rather we believe what is important, at a fundamentally basic level of refinery or processing facility accounting, is to report an average of the sale or market prices generated or received from the sale or disposition of the finished product, with an average of the costs incurred in the supply or procurement of the feedstocks (including raw bitumen or heavy oil generated from oil sands ores and sandstones) to produce a range of (or average) of “gross margins” for the facility’s refining or processing operations (typically in oil industry parlance referred to as “refining or processing margins”).

 

 

 

 

GRACIN & MARLOW, LLP

 

COUNSELLORS AT LAW

 

Securities and Exchange Commission

November 30, 2018

Page 7

 

15.Expand the disclosure throughout your filing to explain the extent that your final sales product will be a blend of extracted bitumen and purchased hydrocarbons, e.g. solvent. Additionally, modify your disclosure of the stated plant production capacity, e.g. the 250 barrels per day and the 1,000 barrels per day, to clarify the extent that these figures may include both extracted bitumen and purchased hydrocarbons, e.g. solvent.

 

Response: We have expanded the disclosure because we do not view PQE as being in the business of selling bitumen and solvent, the finished product is a low sulfur diesel fuel.

 

16.Revise as necessary, the statement on page 20 that “during 2015, the plant produced 10,000 barrels of oil from the local oil sands ore” to clarify the portion of such production that was extracted bitumen. Also modify your disclosure to reconcile the apparent inconsistency with the disclosure of 7,777.33 net barrels produced during 2015 provided elsewhere on page 22.

 

Response: We have not revised the disclosure because the entire portion of such production was extracted bitumen. We have clarified that the 7,777.33 net barrels reflect the number of barrels sold from the 10,000 barrels produced.

 

17.Your disclosure of oil and gas producing activities pursuant to Rule 4-10(a)(16) of Regulation S-X, including your disclosure of production, average sales price and average production cost as required by Items 1204(a), 1204(b)(1) and 1204(b)(2) of Regulation SK, respectively, should not include volumes of purchased hydrocarbons. To the extent that your current disclosure represents blended product consisting of extracted bitumen and purchased hydrocarbons, e.g. solvent, revise your disclosure to separately disclose the net quantities of bitumen produced, the realized price, after appropriate adjustments for quality and gravity, relating exclusively to sale of bitumen, and the production cost per barrel of bitumen extracted. Refer to Instruction 3 to Item 1204 of Regulation S-K regarding the disclosure requirements specific to bitumen.

 

Response: We have not revised the disclosure because we do not view PQE as being in the business of selling bitumen and solvent, the finished product is a low sulfur diesel fuel . In addition, the volume of purchased solvent is insignificant.

 

 

 

 

GRACIN & MARLOW, LLP

 

COUNSELLORS AT LAW

 

Securities and Exchange Commission

November 30, 2018

Page 8

 

18.Expand your disclosure of production costs to separately discuss the nature and types of costs included in the calculation of the production cost per barrel of blended product produced and in the calculation of the production cost per barrel of bitumen extracted. Your explanation should include, but not be limited to, the disclosure of the solvent purchase costs, the number of tons of raw ore processed and related mining costs, and the plant operating costs included in calculating the production cost figures. Furthermore, your disclosure should identify any variables effecting these calculations such as the percent by weight of bitumen in the mined ore, the amount of solvent by volume required to achieve a targeted product API gravity of the blended sales product, etc.

 

Response: We have expanded our disclosure of production costs to separately discuss the nature and types of costs included in the calculation of the production cost per barrel of blended product produced and in the calculation of the production cost per barrel of bitumen extracted.

 

19.Expand your disclosure to explain how the operating costs for the pilot are expected to compare to the cost at higher plant capacities and if such costs are anticipated to materially change as the depth of the open pit increases over time.

 

Response: We have expanded our disclosure to explain how the operating costs for the pilot are expected to compare to the cost at higher plant capacities and if such costs are anticipated to materially change as the depth of the open pit increases over time.

 

20.Expand your disclosure to identify the purchaser of the bitumen extracted during fiscal year 2015 and the extent that you anticipate sales of your future production to this purchaser. As part of your expanded disclosure, discuss the product specifications required by the purchaser, e.g. range of API gravities. Contrast these sales specifications with the API gravity specific to the extracted bitumen prior to blending and clarify the extent for which a purchaser and market exists for the sale of bitumen excluding blending with other hydrocarbons.

 

Response: We have expanded our disclosure regarding the purchaser of the bitumen extracted during fiscal year 2015, the extent that we anticipate sales of your future production to this purchaser and the product specifications required by the purchaser.

 

Extraction Technology, page 22

 

21.We note your disclosure that “[t]he Extraction Technology utilizes no water in the process.” However, it appears from a report available on the investor relations section of your website listed as “Nexant Report - September 2015” and entitled Tar Sands Project Due Diligence Phase 2 - Pilot Plant Testing Program (“Nexant Report”) that the process uses water. By way of example only, we note that page 5 of the Nexant Report states that “[a] unique method developed by MCW provides for a water layer in the [extraction] column, which separates the solids from the HC” and that the operating cost analysis tables at pages 9-10 of the Nexant Report list water as a cost. Please revise or advise as to this apparent inconsistency.

 

Response: We confirm that the Petroteq extraction technology does not use water for the hydrocarbon extraction from the oil sands. The extraction solvent blend consists of straight, branched and cycled low molecular weight saturated hydrocarbon solvents, small percentages of aromatic hydrocarbons and alcohols and esters when applicable. There is no water involved.

 

 

 

 

GRACIN & MARLOW, LLP

 

COUNSELLORS AT LAW

 

Securities and Exchange Commission

November 30, 2018

Page 9

 

At the company’s first pilot plant at Maeser, Utah the Company had used water in two manners. First, a water/steam based reboiler had been supplying hot steam to heat up the reboiler and distillation column to recycle solvents used for the oil production. Second, hot steam had been used to dry out the clean sands tailings leaving small moisture amount in the tailing sands in order to prevent any possible dusting from dried sands. These two former water applications are not a part of the Company’s current process and/or extraction technology. At the Temple Mountain, Vernal, Utah facility both above water applications have been removed. There is an oil heater instead of the steam boiler and there is no steam drying and wetting of the sands tailings with steam.

 

The only use of the water at the new plant is a drinking water for the employees and water for the fire prevention system.

 

With respect to the Nexant Report, please note that Nexant’s four days testing program was a special stress test set up to check the technology at critical conditions and project all possible and impossible production scenarios. One of the test stress assessments, included delivery of water needed to wet the sands preventing dusting at the bottom of the extraction column and then watered sand was delivered to the drier. In this set up water was in contact with the clean sand only and after all oil had been already extracted with the solvent. Water took no part in the extraction process. Overall, this protocol appeared to be not effective and has not been used again.

 

22.We note your disclosure that you expect to “recycle up to 99% of the solvents.” Please disclose whether the 2015 tests of the Extraction Technology discussed at page 20 of your filing included recycling of the solvents. In that regard, we note that page 8 of the Nexant Report states that “[t]he solvent/condensate was not recycled during the test runs as assumed for the Phase 1 due diligence.” If your test runs of the extraction technology to date have not recycled the solvent, please explain the basis for your expectation that you will be able to recycle over 99% of the solvent.

 

Response: We have added additional disclosure regarding the basis for our expectation that we will be able to recycle over 99% of the solvent and that the 2015 tests of the Extraction Technology did not include recycling of the solvent.

 

As stated in our response to staff comment 21 Nexant’s four days testing program was a special stress test set up to check the technology at critical conditions and project/calculate many possible production scenarios. There are two ways to increase the oil concentrations: to recycle the solvent or to use multiple oil sands processing cycles with the same solvent. During the Nexant testing the second option of multiple oil sands extraction with the same solvent batch had been performed to test the speed and efficiency of the extraction process. At the new plant at Temple Mountain the only way production is run is the complete recycling of the solvents.

 

 

 

 

GRACIN & MARLOW, LLP

 

COUNSELLORS AT LAW

 

Securities and Exchange Commission

November 30, 2018

Page 10

 

Petrobloq, LLC, page 24

 

23.We note you disclose an agreement with First Bitcoin Capital Corp. (“FBCC”) to design and develop a blockchain-powered supply chain management platform for the oil and gas industry. Please expand your disclosure to clarify:

 

the stage of development of your distributed ledger technology, including any blockchain technology. For example, please explain if FBCC has begun any activity on the development of your applications or will only once all $500,000 has been paid. Please also explain the activities of the four employees of your wholly owned subsidiary Petrobloq, LLC. We note Petrobloq appears to have more employees than yourself, as you disclose on page 52 only one full time employee in Utah and two contractors;

 

the types of applications you are pursuing;

 

whether your business entails, or will entail, the creation, issuance, or use of digital assets and, if so, how those digital assets will be used; and

 

whether your applications (1) are or will be dependent on another blockchain and, if so, the risks and challenges related to such reliance; or (2) run or will run its own blockchain and, if so, the risks and challenges related to developing and maintaining the blockchain.

 

Finally, please file your agreement with FBCC as an exhibit or tell us why you are not required to file it. Refer to Instruction 4 to Item 19 of Form 20-F.

 

Response: We have expanded our disclosure as requested to clarify the stage of development of our distributed ledger technology, the types of applications we are pursuing, whether the business entails or will entail the creation, use or issue or digital assets and whether the application will be dependent on another blockchain. We have filed our Agreement with FBCC as an exhibit.

 

The Oil Sands Market, page 24

 

24.We note the following statements attributed to the 2007 Report: (i) that the United States has 50 to 70 billion barrels of bitumen and heavy oil in oil sands deposits that are close enough to the surface to economically develop; (ii) that, within the United States, Utah is known to have the richest oil sands resources, with 20 to 30 billion barrels of heavy oil and bitumen estimated by the 2007 Report to be contained within its oil sands deposits; and (iii) there are close to 1 billion barrels of heavy oil and bitumen in the oil sands deposits in Asphalt Ridge, of which most are surface deposits which can be economically processed. However, it appears from Tables 3-5 and 3-6 in Section 3.2.2 of the 2007 Report that these figures are total oil sands resource in-place amounts of, with respect to the Asphalt Ridge, proven, probable, and possible resources, and, with respect to the United States and Utah, proven and speculative resources.

 

 

 

 

GRACIN & MARLOW, LLP

 

COUNSELLORS AT LAW

 

Securities and Exchange Commission

November 30, 2018

Page 11

 

Please disclose the individual estimates for each category of resources as separate estimates and revise to exclude all aggregated totals of resource categories. In addition, please fully explain the difference in certainty for each estimate, including by incorporating cautionary language indicating estimates of speculative, probable, and possible in-place resources are more uncertain than proved in-place resources, but have not been adjusted for risk due to that uncertainty, and therefore they may not be comparable with each other and should not be summed arithmetically with each other or with estimates of proved in-place resources. Refer to Question 105.01 of the Oil and Gas Rules Compliance and Disclosure Interpretations.

 

Response: We have expanded the disclosure as requested.

 

25.Please supplementally provide us with support for the following claims or revise to clarify that the claim is your belief:

 

Certain oil sands deposits in the United States and Asphalt Ridge are respectively “close enough to the surface to economically develop” and “surface deposits which can be economically processed”;

 

“Within Utah, the most developed region for oil sands development, in terms of both supporting infrastructure and existing oil and gas production, is Asphalt Ridge.”; and

 

“[T]he United States also has large oil sands resources that can be developed economically.”

 

Response: We are providing supplementally excerpts from Crysdale and Schenk, Bitumen-Bearing Deposits of the United States, U.S. Geological Survey Bulletin 1784, U.S. Geological Survey, Department of the Interior, page 1 (1988) and Blackett, Tar-Sand Resources of the Uinta Basin, Utah, sponsored by the State of Utah Department of Community and Economic Development and the Permanent Community Impact Board, and prepared by the Utah Geological Survey and the Utah Engineering Experiment Station, University of Utah, p. 25 (May 1996].

 

Please also note that there are four operating refineries surrounding the area of our processing plant at Asphalt Ridge, and there was electricity and roads in the area before we commenced construction of the plant. Having that infra-structure already in place made Asphalt Ridge more attractive than a remote area with no roads or electricity. We are not aware of any other area within Utah that has more supporting infrastructure for oil sands development.

 

26.You disclose that you have tested your extraction technology on oil sands from around the world and have found that the “efficacy and consistency” of your extraction technology is not affected by difference in chemical composition of the bitumen. Please describe your process of testing in more detail, including the number of samples tested, the location from which each sample was sourced, the makeup of each sample, how you tested your extraction technology on such sample, and the results of each test.

 

Response: We have added additional disclosure regarding the process of testing and the results of each test.

 

 

 

 

GRACIN & MARLOW, LLP

 

COUNSELLORS AT LAW

 

Securities and Exchange Commission

November 30, 2018

Page 12

 

Regulation, page 25

 

27.Please expand your disclosure to discuss the material effects of existing or probable governmental regulation of distributed ledger technology, and blockchain technology specifically, on the intended business of Petrobloq, LLC. Refer to Item 4.B.8 of Form 20- F.

 

Response: We have expanded our risk factor regarding the effects of future governmental regulation on our business operations. We are not aware, however, of any existing, probable or proposed governmental regulation of the distributed ledger or blockchain technology that is the subject of Petrobloq, LLC’s research and development efforts.

 

Item 5. Operating and Financial Review and Prospects

B. Liquidity and Capital Resources, page 38

 

28.Please expand your disclosure to discuss the following commitments and how you intend to fund them: (i) the future advance royalty payments due under your lease; (ii) your proposed second and third production facilities; (iii) “the capital needed to complete development of [your] Extraction Technology”; and (iv) the remaining $400,000 due to FBCC under your agreement. Refer to Item 5.B.1 and 3 of Form 20-F. In addition, please clarify the amount of capital expenditures needed to complete your first production plant and your Extraction Technology. In that regard, we note your disclosure at page 21 that you anticipate the total cost of your first production plant, including the expansion of the production capacity of the facility to full capacity, is between $18 million and $19 million.

 

Response: We have added disclosure to the Registration Statement on Form 20-F that the Company intends to pay for the costs associated with (i) the future advance royalty payments due under your lease; (ii) the proposed second and third production facilities; (iii) the capital needed to complete development of [your] Extraction Technology; and (iv) the remaining $400,000 due to FBCC under its agreement with FBCC form cash generated from operations. If cash generated from operations is insufficient to make all required payments, the Company intends to seek financing from either debt or equity private or public offerings.

 

 

 

 

GRACIN & MARLOW, LLP

 

COUNSELLORS AT LAW

 

Securities and Exchange Commission

November 30, 2018

Page 13

 

Item 6. Directors, Senior Management and Employees

C. Board Practices

Corporate Governance Practices, page 48

 

29.Please provide us with a detailed analysis supporting your conclusion that you qualify as a foreign private issuer under Exchange Act Rule 3b-4(c). In that regard, by way of example only, we note your disclosure at page 53 that, as of August 31, 2018, 55.6% of your outstanding common shares were held in the United States by 188 holders of record, that your oil sands extraction facility and mineral lease are in Utah, and that your headquarters are in California.

 

Response: Pursuant to the Securities Exchange Act, the Company must confirm its continued status as a “foreign private issuer” as of the last business day of its second fiscal (most recently February 28, 2018). In order to complete this assessment the Company contacted its transfer agent (Computershare) and Broadridge to prepare reports on both the Canadian and U.S. geographic breakdowns of its shareholders. In calculating the number of shares held by U.S. residents, SEC staff at the International Corporation Finance Division have clarified that only outstanding shares need be counted. That is, it is not necessary to include in the calculation any shares issuable pursuant to stock options, warrants or similar rights to acquire common shares, even if they are exercisable within 60 days. The registered shareholder list included a summary of total U.S. ownership as at February 28, 2018, of 41.9%. The next time the Company will have to confirm its continued status as a “foreign private issuer” will be February 28, 2019. In addition, pursuant to your comment, please note that the August 31, 2018, information was based solely on registered shareholders as of August 31, 2018, it was not intended to be a reflection of an assessment of the Company’s status as a “foreign private issuer”.

 

Item 7. Major Shareholders and Related Party Transactions

Major Shareholders, page 53

 

30.Your disclosure that 188 holders of record in the United States held 47,364,038 shares of your common stock representing 55.6% of your outstanding common shares at August 31, 2018 appears inconsistent with your disclosure at page 57 that there were approximately 146 holders of record of your common shares at August 31, 2018. Please revise or advise.

 

Response: Please note that there was an error in the disclosure on page 57 which has been corrected.

 

Consolidated Financial Statements, page F-1

 

31.Please include the audit report from your independent public accountant in the filing to comply with Item 8.A.3 of Form 20-F.

 

Response: We have added the audit reports of Hay & Watson, the Company’s Independent Registered Chartered Accountants for the past five years.

 

32.If you are able to show that you qualify as a foreign private issuer and do not withdraw the registration statement, it may become effective automatically on December 10, 2018, sixty days after filing, pursuant to section 12(g) of the Exchange Act. However, annual financial statements for your most recently completed fiscal year would be required December 3, 2018, prior to the effective date, to comply with Item 8.A.4 of Form 20-F.

 

Response: We understand.

 

 

 

 

GRACIN & MARLOW, LLP

 

COUNSELLORS AT LAW

 

Securities and Exchange Commission

November 30, 2018

Page 14

 

Note 3 - Significant Accounting Policies

(h) Impairment of assets, page F-11

 

33.We note your disclosure indicating you assess various assets for indications of impairment at the end of each period, including the amounts you have capitalized as mineral lease, and properly, plant and equipment. Given your disclosure on page 6, explaining that there is substantial doubt about your ability to continue as a going concern, also considering that you had no production and no revenues during 2017, nor in the subsequent interim period, and only limited production and minimal revenues during 2016, prior to dismantling your facility, please submit for review the analyses that you performed in applying the guidance in IAS 36, in assessing whether there were indications of impairment for these assets and in estimating the recoverable amounts and any impairment losses to be recognized as of August 31, 2017.

 

Response: We have prepared a quantitative analysis in terms of IAS 36 in assessing whether there was any indication of impairment. Please see Appendix 1 hereto.

 

General

 

34.Please be advised that your registration statement will automatically become effective sixty days after filing pursuant to Section 12(g)(1) of the Securities Exchange Act of 1934. Upon effectiveness, you will become subject to the reporting requirements of the Exchange Act, even if issues identified in our comments remain unresolved at that time. Please consider withdrawing your registration statement and resubmitting a new registration statement which gives effect to all our comments.

 

Response: We understand, thank you.

 

* * *

 

Petroteq acknowledges that the adequacy and accuracy of the disclosure in our filings is our responsibility. Petroteq acknowledges that the staff comments or changes to disclosure do not foreclose the Commission from taking any action with respect to the filings. Petroteq acknowledges that the company may not assert staff comments as a defense in any proceedings initiated by the Commission or any person under the federal securities laws of the United States.

 

If you have any questions or need additional information, please contact the undersigned at (516) 496-2223 or (212) 907-6457.

 

  Sincerely,
   
  /s/ Leslie Marlow
  Leslie Marlow

 

cc:David Sealock

Petroteq Energy Inc.

 

 

 

Appendix 1

 

Petroteq Energy Inc.

Going concern analysis

August 31, 2017

 

Objective To determine if the going concern assumption is appropriate.

 

Procedure1.Determine the minimum cash needs for the company to continue operating for the next 12 months
2.Identify the current cash available for use within the company
3.Identify any additional financing received by the company subsequent to the reporting period
4.Identify possible measures to be taken to cover any cash flow deficiencies

 

Analysis

The company's strategy to mitigate any cash flow deficiencies are as follows:

 

1.Full scale production of oil and sale of the oil to generate revenue to cover production costs and plant overheads; timing uncertain, so more emphasis on additional financing.
2.Continue to look for avenues of financing either from financial institutions or private lenders
3.To explore joint arrangements with other entities to develop new revenue streams from various oil industry related services (JV to provide web-based career services with partners)
4.To license its technology to other entities and receive royalties on the usage of the technologies
5.To explore new source of capital by marketing to potential investors in its oil production segment
6.To reduce exoenses to the minimum to maintain the company in good standung until suffucient financing obtained for completion of larger plant and increase in oil prices.

 

Minimum 2018 cash needs of the company based on the current year obligations and an estimate of bare minimum expenses required to keep the company operating for 2018. Compared to current funding available to cover these costs.

 

Liabilities of the company   

Aug 31, 2017

Balance

   Cash payments required for
2018
   Notes
Accounts Payable   1,121,327    1,121,327  

[1]

Accrued liabilities   1,980,304    462,866   [2]
Payable to director   419,322    -   Payable to Alex (Chair of the Board), not expect payment will be demanded
Deferred income   283,976    -   Deferred income, cash already received and no repayments needed
Decommission costs   572,220    -   Not due until end of plant life, not included
Unearned royalties received   170,000    -   Not a cash payment, not included
Long term debt   1,876,380    1,159,104   [3]
Convertible Debentures   

508,500

    -   [4]
Expenses   N/A    743,890   [5]
Financing obtained   6,932,029    3,487,187    
Private placements   449,704    449,704   Equity issued, no repayments needed
Alex convertible debt   2,000,000    2,000,000   No repayment, expect to be converted to shares
Cash on hand   55,420    55,420    
Deficit (Surplus)   4,426,905    982,063   Insufficient cash on hand for payments, see analysis below
    ^    ^    

 

1

 

 

The current cash available does not meet the projected minimum requires for the 2018 fiscal year. However, , the Company is continuing to actively look for new sources of funding and has no intention to liquidate or wind-up the Company. The company has raised considerable funds through debt and equity during fiscal 2014 to 2017.

 

Sources of funding  2017   2016   2015   2014   From cash flow statement
Private lenders   1,119,631.00    4,993,965.00    3,845,765.00    3,850,000.00    
Convertible debts   -    1,100,000.00    4,500,000.00    2,824,000.00    
Total   1,119,631.00    6,093,965.00    8,345,765.00    6,674,000.00   Based on past experiences, the Company should be
                       able to raise enough through financing to cover the shortfall for 2018

 

Note: The Company has a memorandum of understanding with Deloro for financing up to $10M to be delivered in separate tranches which is contigent on successfully expanding the plant to 1,000bbl/day production by Jan 2018. This new financing will more than cover the cash expenditures expected for 2018

 

Therefore, it appears appropriate to use the going concern assumption. However, there is material uncertainty and this will be disclosed in the financial statements.

 

2

 

 

[1] Accounts Payable  

 

  Balance @ 8/31/17 per F/S   1,121,327    
  No subsequent convertible transactions noted.        
  Expected  AP to be paid in FY18   1,121,327   To above
      ^    

 

[2] Accrued Liabilities       
  Balance @ 8/31/17 per F/S   1,980,304    
  less:        
  Strategic IR accrued interest   (4,963)  Interest included in long term debt estimates above
  Directors fees   (197,392)  Likely will not pay or can deferred, based on past practices
  CEO accrued salary   (372,500)  Likely will not pay or can deferred, based on past practices
  Alex Blyumkin salary   (480,000)  Likely will not pay or can deferred, based on past practices
  Audit fees   (182,000)  Audit fees are expected to be repaid by the GST/HST refund that is recorded in receivable, reasonable
  Express Consulting accrued interest   (617)  Interest included in long term debt estimates above
  Peterson CDN$ Penalty   (25,679)  Loan Penalties
  Cameron CDN$ Penalty   (254,287)  Loan Penalties
  Expected accruals to be paid in FY18   462,866   To above
      ^    

 

[3]

Long term debt

 

  MCW Energy  Principal   Due in 1 year    
  Rocky Romano loan   100,000    100,000    
  BK Petersen   91,895    91,895    
  Donald Cameron   910,010    910,010    
  MCW CA             
 

Express Consulting

   15,750    -  

No repayment obligation in 2017

  Palmira   226,500    -   No repayment obligation in 2017
  MCW Oil             
 

Strategic IR

   33,305       

No repayment obligation in 2017

  Nefco   102,270        No repayment obligation in 2017
  Shennon   56,810    -   No repayment obligation in 2017
  Bev Pacific   177,000    -   No repayment obligation in 2017
  Wells Fargo   28,330    9,535    
  Bank of the West   132,013    47,664    
      1,873,883    1,159,104    
           ^    

 

[4] Convertible   Debentures
  MCW Energy

 

     Principal   Due in 1 year    
  Alpha Capital - tranche 5   508,500        -   $200K converted to shares, likely remainder will also be converted
      508,500    -    
           ^    

 

3

 

 

[5]Expenses The assumption is that the company will be able to eliminate substantially most of its operating costs if cash flow is a concern. Based on current and prior years work, both the CEO and CFO and other senior management compensation has been and can be deferred, therefore assume that only a portion of their fees will be paid if the company if necessary to manage cash outflows. Likely the only expenses that will still be required will be ones that are under contract with third party suppliers such as rent or utilities. Below figures are estimated based on FY17 amounts

 

The majority of the required spending on the mineral properties has been met with the $14 million spent on the plant and no significant spending is expected to be required in 2017, or will be paid using the balance of the available Deloro loan proceeds of up top $10 million.

 

  Professional fees - legal and consulting   100,000   Estimated minimum legal and consulting fees expected if suspending operation
  Audit fees   60,000   Estimated audit fees based on FY16 budgeted fees and discounted for less work expected if minimal operations
  Office rent   -   No office rent being charged at new location, not expected to change in FY17
  Land rental - plant   12,529   Estimated based on 2017 numbers
  Office rental - plant   -   Estimated based on 2017 numbers
  Apartment rental - plant   -   Rent ended and currently not expected to rent another apartment as not needed.
  TSX Fees   77,700   Based on average stock exchange fees for 2016 and 2017 (Acc#60100S2)
  Insurance   137,442   Estimated based on 2017 numbers
  General and utilities   163,719   Estimated based on 2017 number with estimated 50% reduction for suspended operations
  Wages   192,500   Estimated based on CFO, CEO and Legal counsel salary for 2017 and reduced by 50% as likely will be deferred based on past practices
           
  Total   743,890   To above
      ^    

 

4