GFRWF Greenfire Resources Ltd (PK)

PROSPECTUS	Filed Pursuant to Rule 424(b)(3)
	Registration No.: 333-275129

 

GREENFIRE RESOURCES LTD.

 

45,611,549 COMMON SHARES

5,625,456 WARRANTS

5,625,456 COMMON SHARES ISSUABLE UPON EXERCISE OF WARRANTS

 

This prospectus relates to the offer and sale from time to time by the selling securityholders named in this prospectus (the “Selling Securityholders”) of:

 

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up to 4,177,091 common shares (“Common Shares”) of Greenfire Resources Ltd. (“we” or the “Company”) of certain Selling Securityholders who purchased MBSC Class A Common Shares (as defined herein) in a private placement pursuant to the PIPE Financing (as defined herein) consummated in connection with the Business Combination (as defined herein) for a purchase price of $10.10 per share, which shares were converted into Common Shares on a one-for-one basis as part of the Business Combination;

 

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up to 4,250,000 Common Shares issued to the MBSC Sponsor (as defined below) and its transferees in exchange for their MBSC Class B Common Shares (as defined below) on a one-for-one basis (after giving effect to certain forfeitures of MBSC Class B Common Shares) pursuant to the Business Combination, which MBSC Class B Common Shares were originally issued in private placements by MBSC (as defined below) for a purchase price of approximately $0.0033 per share;

  

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37,184,458 Common Shares and 3,098,789 warrants to purchase Common Shares at an exercise price of $11.50 per share (“Company Warrants”) issued to certain former securityholders (the “Greenfire Holders”) of Greenfire Resources Inc. (“Greenfire”) pursuant to the Business Combination in exchange for securities of Greenfire acquired by executives and founders that in most cases were issued for nominal consideration or pursuant to grants to such executives under Greenfire’s equity incentive plans;

 

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2,526,667 Company Warrants issued to the MBSC Sponsor in exchange for its MBSC Private Placement Warrants (as defined below) on a one-for-one basis (after giving effect to certain forfeitures of MBSC Private Placement Warrants) pursuant to the Business Combination, which MBSC Private Placement Warrants were originally purchased in a private placement in connection with the MBSC IPO (as defined below) for a purchase price of $1.50 per warrant; and

 

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up to 5,625,456 Common Shares issuable upon exercise of the Company Warrants of MBSC Sponsor and the Greenfire Holders.

 

Capitalized terms used in this prospectus and not otherwise defined have the meanings set forth under the heading “Certain Defined Terms.”

 

In connection with the Business Combination, holders of 29,244,293 MBSC Class A Common Shares exercised their right to redeem those shares for cash at a price of approximately $10.33 per share, for an aggregate redemption price of approximately $302.3 million. At the closing of the Business Combination, there were 68,642,515 Common Shares issued and outstanding. The total number of Common Shares that may be offered and sold under this prospectus by the Selling Securityholders (“Resale Shares”) represents a substantial percentage of the total outstanding Common Shares as of the date of this prospectus. The total Resale Shares being offered for resale in this prospectus represent approximately 61% of our current total outstanding Common Shares, assuming the exercise of all Company Warrants. Further, certain Selling Securityholders beneficially own a significant percentage of our outstanding Common Shares. As of the date of this prospectus, (i) the Greenfire Holders beneficially owned, in the aggregate 32,577,645 Common Shares (representing approximately 49% of all outstanding Common Shares when including 3,098,789 Common Shares issuable upon exercise of Company Warrants of those holders) and (ii) MBSC Sponsor beneficially owned 3,850,000 Common Shares (representing approximately 9% of all outstanding Common Shares when including 2,526,667 Common Shares issuable upon exercise of Company Warrants of MBSC Sponsor). Almost all of those Common Shares and Company Warrants were subject to transfer restrictions in a Lock-up Agreement (as defined below) that expired on March 18, 2024, and those Common Shares and Company Warrants may now be sold for so long as the registration statement, of which this prospectus forms a part, is available for use. The sale of all securities being offered in this prospectus could result in a significant decline in the public trading price of our Common Shares. Even if the current trading price of the Common Shares is at or significantly below the price at which the MBSC Units were issued in the MBSC IPO, some of the Selling Securityholders may still have an incentive to sell because they could still profit on sales due to the lower purchase price they paid with respect to their securities compared to public securityholders. Public securityholders may not experience a similar rate of return on the securities they purchase due to differences in the purchase prices and the current trading price. See “Risk Factors—Risks Related to Ownership of the Company’s Securities—A significant portion of the Company’s total outstanding securities may be sold into the market in the near future. This could cause the market price of the Common Shares to drop significantly, even if the Company’s business is performing well.”

 

 

The Selling Securityholders may offer, sell or distribute all or a portion of the securities hereby registered publicly or through private transactions at prevailing market prices or at negotiated prices. We will not receive any of the proceeds from such sales of the Common Shares or Company Warrants, except with respect to amounts received by us upon the exercise of the Company Warrants. Whether holders will exercise their Company Warrants, and therefore the amount of cash proceeds we would receive upon exercise, is dependent upon the trading price of the Common Shares. Each Company Warrant is exercisable for one Common Share at an exercise price of $11.50. Therefore, if and when the trading price of the Common Shares is less than $11.50, we expect that holders would not exercise their Company Warrants. The last reported sales price for the Common Shares on the New York Stock Exchange (“NYSE”) on May 8, 2024, was $5.87 per share. Company Warrants may not be in the money during the period they are exercisable and prior to their expiration, and the Company Warrants may not be exercised prior to their maturity, even if they are in the money, and as such, the Company Warrants may expire worthless and we may receive minimal proceeds, if any, from the exercise of Company Warrants. To the extent that any of the Company Warrants are exercised on a “cashless basis,” we will not receive any proceeds upon such exercise. As a result, we do not expect to rely on the cash exercise of Company Warrants to fund our operations. Instead, we intend to rely on other sources of cash discussed elsewhere in this prospectus to continue to fund our operations. See “Risk Factors—Risks Related to Ownership of the Company’s Securities—There is no guarantee that the exercise price of Company Warrants will ever be less than the trading price of our Common Shares on the NYSE, and they may expire worthless. In addition, we may reduce the exercise price of the Company Warrants in accordance with the provisions of the Warrant Agreements, and a reduction in exercise price of the Company Warrants would decrease the maximum amount of cash proceeds we could receive upon the exercise in full of the Company Warrants for cash”.

 

We will bear all costs, expenses and fees in connection with the registration of these securities, including with regard to compliance with state securities or “blue sky” laws. The Selling Securityholders will bear all commissions and discounts, if any, attributable to their sale of Common Shares or Company Warrants. See “Plan of Distribution”.

 

The common shares of the Company are traded on the NYSE and the Toronto Stock Exchange (“TSX”) under the symbol “GFR”. The last reported sales prices of the Common Shares on the NYSE and TSX on May 8, 2024 was $5.87 and CAD$7.97, respectively.

 

We are a “foreign private issuer” as defined in the U.S. Securities Exchange Act of 1934, as amended (the “Exchange Act”), and are exempt from certain rules under the Exchange Act that impose certain disclosure obligations and procedural requirements for proxy solicitations under Section 14 of the Exchange Act. In addition, our officers, directors and principal shareholders are exempt from the reporting and “short-swing” profit recovery provisions under Section 16 of the Exchange Act. Moreover, we are not required to file periodic reports and financial statements with the U.S. Securities and Exchange Commission as frequently or as promptly as U.S. companies whose securities are registered under the Exchange Act. Additionally, the NYSE rules allow foreign private issuers to follow home country practices in lieu of certain of the NYSE’s corporate governance rules. As a result, our shareholders may not have the same protections afforded to shareholders of companies that are subject to all the NYSE corporate governance requirements.

 

Investing in our securities involves a high degree of risk. You should review carefully the risks and uncertainties described under the heading “Risk Factors” beginning on page 6 of this prospectus, and under similar headings in any amendments or supplements to this prospectus.

 

None of the Securities and Exchange Commission, any state securities commission or the securities commission of any Canadian province or territory has approved or disapproved of these securities, or determined if this prospectus is accurate or adequate. Any representation to the contrary is a criminal offense.

 

The date of this prospectus is May 9, 2024.

 

 

TABLE OF CONTENTS

 

		Page
MARKET AND INDUSTRY DATA		ii
TRADEMARKS AND TRADE NAMES		ii
INTRODUCTION		ii
NON-GAAP FINANCIAL MEASURES		iii
DISCLOSURE OF OIL AND GAS PRODUCTION VOLUMES		iii
EXCHANGE RATES		iii
CERTAIN DEFINED TERMS		iv
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS		xi
SUMMARY OF PROSPECTUS		1
THE OFFERING		5
RISK FACTORS		6
USE OF PROCEEDS		34
MARKET PRICE OF OUR SECURITIES AND DIVIDENDS		35
BUSINESS		36
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		62
MANAGEMENT		95
EXECUTIVE COMPENSATION		98
DESCRIPTION OF THE COMPANY’S SECURITIES		102
BENEFICIAL OWNERSHIP OF THE COMPANY’S SECURITIES		108
COMMON SHARES ELIGIBLE FOR FUTURE SALE		110
SELLING SECURITYHOLDERS		111
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS		114
MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS FOR U.S. HOLDERS		115
MATERIAL CANADIAN TAX CONSIDERATIONS		122
PLAN OF DISTRIBUTION		124
EXPENSES RELATED TO THE OFFERING		126
LEGAL MATTERS		127
EXPERTS		127
SERVICE OF PROCESS AND ENFORCEABILITY OF CIVIL LIABILITIES UNDER U.S. SECURITIES LAWS		127
WHERE YOU CAN FIND MORE INFORMATION		128
INDEX TO CONSOLIDATED FINANCIAL INFORMATION		F-1

 

No one has been authorized to provide you with information that is different from that contained in this prospectus or any free writing prospectus filed by us. This prospectus is dated as of the date set forth on the cover hereof. You should not assume that the information contained in this prospectus is accurate as of any date other than that date.

 

Except as otherwise set forth in this prospectus, we have not taken any action to permit a public offering of these securities outside the United States or to permit the possession or distribution of this prospectus outside the United States. Persons outside the United States who come into possession of this prospectus must inform themselves about and observe any restrictions relating to the offering of these securities and the distribution of this prospectus outside the United States.

 

 

MARKET AND INDUSTRY DATA

 

This prospectus contains estimates, projections, and other information concerning the Company’s industry and business, as well as data regarding market research, estimates, forecasts and projections prepared by the Company’s management. Information that is based on market research, estimates, forecasts, projections, or similar methodologies is subject to uncertainties, and actual events or circumstances may differ materially from events and circumstances that are assumed in this information. The industry in which the Company operates is subject to a high degree of uncertainty and risk due to a variety of factors, including those described in the section titled “Risk Factors.” Unless otherwise expressly stated, the Company obtained industry, business, market, and other data from reports, research surveys, studies, and similar data prepared by market research firms and other third parties, industry and general publications, government data, and similar sources. In some cases, the Company does not expressly refer to the sources from which this data is derived. In that regard, when the Company refers to one or more sources of this type of data in any paragraph, you should assume that other data of this type appearing in the same paragraph is derived from sources that the Company paid for, sponsored, or conducted, unless otherwise expressly stated or the context otherwise requires. While the Company has compiled, extracted, and reproduced industry data from these sources, the Company has not independently verified the data. Forecasts and other forward-looking information with respect to industry, business, market, and other data are subject to the same qualifications and additional uncertainties regarding the other forward-looking statements in this prospectus. See Cautionary Note Regarding Forward-Looking Statements.

 

TRADEMARKS AND TRADE NAMES

 

The Company owns or has rights to various trademarks, service marks and trade names that we use in connection with the operation of our business. This prospectus also contains trademarks, service marks and trade names of third parties, which are the property of their respective owners. The use or display of third parties’ trademarks, service marks, trade names or products in this prospectus is not intended to create, and does not imply, a relationship with the Company or an endorsement or sponsorship by or of the Company. Solely for convenience, the trademarks, service marks and trade names referred to in this prospectus may appear without the ®, TM or SM symbols, but such references are not intended to indicate, in any way, that the Company will not assert, to the fullest extent under applicable law, their rights or the right of the applicable licensor to these trademarks, service marks and trade names.

 

INTRODUCTION

 

Except as otherwise indicated or required by context, references in this prospectus to (i) “we,” “us,” “our,” or the “Company” refer to Greenfire Resources Ltd., an Alberta corporation, and its subsidiaries, (ii) “Greenfire” refers to Greenfire Resources Inc., an Alberta corporation that became a wholly-owned subsidiary of the Company upon the closing of the Business Combination (effective as of January 1, 2024, Greenfire Resources Operating Corporation and Greenfire amalgamated, with the surviving corporation continuing as “Greenfire Resources Operation Corporation”, a wholly-owned subsidiary of the Company), and (iii) CAD$ refers to Canadian dollars. Certain amounts that appear in this prospectus may not sum due to rounding.

 

This prospectus contains:

 

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the Company’s audited consolidated financial statements as at December 31, 2023 and 2022 and for each of the three years in the period ended December 31, 2023 and related notes;

 

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the audited consolidated financial statements of Japan Canada Oil Sands Limited (“JACOS”), the predecessor to Greenfire, for the period from January 1, 2021 to September 17, 2021 and for the year ended December 31, 2020 and related notes (collectively, the “Annual Financial Statements”)

 

Unless indicated otherwise, financial data presented in this prospectus has been taken from the audited financial statements of the Company and JACOS included in this prospectus. Unless otherwise indicated the financial information in respect of the Company and JACOS has been prepared in accordance with International Financial Reporting Standards, as issued by the International Accounting Standards Board (“IFRS”). IFRS differs from the United States generally accepted accounting principles, or U.S. GAAP, in certain material respects and thus may not be comparable to financial information presented by U.S. companies.

 

The consolidated financial statements of the Company and JACOS are presented in Canadian dollars. In this prospectus, unless otherwise specified, all monetary amounts are in U.S. dollars, all references to “$,” “US$,” “USD” and “dollars” mean U.S. dollars and all references to “CAD$”, “C$” and “CAD” mean Canadian dollars.

 

 

NON-GAAP FINANCIAL MEASURES

 

The Company reports certain financial information using meaningful measures commonly used in the oil and natural gas industry that are not defined under IFRS, and are referred to as non-GAAP measures. The Company believes that these measures provide information that is useful to investors in understanding the performance of the Company and facilitate a comparison of the Company’s results from period to period. Non-GAAP financial measures and ratios used in the Company’s financial information include, adjusted EBITDA, adjusted EBITDA per barrel ($/bbl), operating netback, operating netback per barrel ($/bbl), adjusted funds flow, adjusted free cash flow, adjusted working capital, and net debt. These measures should not be considered in isolation or as a substitute for measures prepared in accordance with IFRS, and should be read in conjunction with the audited annual consolidated financial statements and unaudited interim consolidated financial statements of Greenfire. Readers are cautioned that these non-GAAP financial measures and ratios are not standardized measures under IFRS, and may not be comparable to similar financial measures disclosed by other entities.

 

For more information on the non-GAAP financial measures used in this prospectus, please see the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Non-GAAP Measures.”

 

DISCLOSURE OF OIL AND GAS PRODUCTION VOLUMES

 

The Company owns interests in two steam-assisted gravity drainage (“SAGD”) facilities, the Demo Asset and the Expansion Asset. The Company owns a 100% working interest in the Demo Asset and a 75% working interest in the Expansion Asset. The Company reports its bitumen production volumes from its Expansion Asset as “gross” and “net” where “gross” refers to the total aggregate production volumes from the Expansion Asset, including the portion of such production that is not attributable to the Company’s working interest in the Expansion Asset, and “net” refers to the Company’s percentage of such total aggregate production volumes from the Expansion Asset attributable to the Company’s working interest in the Expansion Asset. In reporting production from the Demo Asset, as the Company owns a 100% working interest in the Demo Asset, the gross and net production are equal. Unless otherwise indicated, the production volumes reported herein, whether referred to as “gross,” “net” or otherwise, are reported before any deduction for royalties.

 

EXCHANGE RATES

 

The Company’s reporting currency is the Canadian dollar. The determination of the functional and reporting currency of each group company is based on the primary currency in which the group company operates. The functional currency of the Company’s subsidiaries is generally the local currency.

 

 

CERTAIN DEFINED TERMS

 

Unless the context otherwise requires, references in this prospectus to:

 

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“2025 Notes” are to Greenfire’s 12.000% Senior Secured Notes due 2025 issued pursuant to the Greenfire Indenture.

 

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“2028 Notes” are to the Company’s 12.0% Senior Secured Notes due 2028 which were issued by the Company concurrently with the Business Combination.

 

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“ABCA” are to the Business Corporations Act (Alberta).

 

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“Affiliate” are to, with respect to any Person, any other Person who directly or indirectly, through one or more intermediaries, controls, is controlled by, or is under common control with, such Person.

 

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“Amalgamation” are to the amalgamation of Greenfire and Canadian Merger Sub.

 

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“Ancillary Documents” are to the Lock-Up Agreement, the Investor Rights Agreement, the Sponsor Support Agreement, the Subscription Agreements, the Greenfire Shareholder Support Agreement, MBSC Warrant Agreement Amendment and each other agreement, document, instrument and/or certificate executed, or contemplated by the Business Combination Agreement to be executed, in connection with the Transactions.

 

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“APEGA” are to the Association of Professional Engineers and Geoscientists of Alberta.

 

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“Arrangement” are to an arrangement under section 193 of the ABCA on the terms and subject to the conditions set forth in the Plan of Arrangement.

 

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“Arrangement Effective Date” are to the date on which the Articles of Arrangement were filed with the Registrar.

 

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“Arrangement Effective Time” are to the time at which the Articles of Arrangement were filed with the Registrar on the Arrangement Effective Date.

 

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“Articles of Arrangement” are to the articles of arrangement in respect of the Arrangement.

 

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“bbl” are to barrel.

 

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“bbls/d” are to barrels per day.

 

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“bitumen” are to a naturally occurring solid or semi-solid hydrocarbon (a) consisting mainly of heavier hydrocarbons, with a viscosity greater than 10,000 millipascal-seconds (mPa●s) or 10,000 centipoise (cP) measured at the hydrocarbon’s original temperature in the reservoir and at atmospheric pressure on a gas-free basis, and (b) that is not primarily recoverable at economic rates through a well without the implementation of enhanced recovery methods.

 

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“Brigade” are to Brigade Capital Management, LP, a Delaware limited partnership.

 

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“Business Combination” are to the transactions contemplated by the Business Combination Agreement.

 

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“Business Combination Agreement” are to that certain Business Combination Agreement, dated December 14, 2022, as amended on April 21, 2023, June 15, 2023, and September 5, 2023, by and between MBSC, Greenfire, the Company, DE Merger Sub and Canadian Merger Sub, as amended.

 

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“C$,” “CAD$” and “CAD” are to Canadian dollars.

 

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“Canadian Merger Sub” are to 2476276 Alberta ULC, an Alberta unlimited liability corporation and a direct, wholly-owned subsidiary of the Company.

 

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“Cantor” are to Cantor Fitzgerald & Co.

 

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“Cash Consideration” are to $75,000,000.

 

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“Closing” are to the closing of the Transactions.

 

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“Closing Date” are to the date of Closing.

 

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“Code” are to the U.S. Internal Revenue Code of 1986, as amended.

 

 

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“Company” are to Greenfire Resources Ltd., an Alberta corporation.

 

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“Company Articles” are to the articles of incorporation of the Company, as may be amended and/or restated from time to time.

 

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“Company Awards” are to, collectively, the Company Options, the Company Share Units and the Company DSUs granted pursuant to the terms of the Company Incentive Plan.

 

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“Company Board” are to the board of directors of the Company.

 

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“Company Bylaws” are to the bylaws of the Company, as may be amended and/or restated from time to time.

 

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“Company Debt Financing” are to the subscription by certain investors for $50,000,000 aggregate principal amount of convertible notes of the Company pursuant to subscription agreements entered into with MBSC and the Company concurrently with the execution of the Business Combination Agreement.

 

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“Common Shares” are to the common shares in the capital of the Company.

 

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“Company Incentive Plan” are to the omnibus share incentive plan of the Company providing for the grant of the Company Awards for certain qualified directors, executive officers, employees or consultants of the Company.

 

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“Company Options” means options to purchase the Common Shares granted pursuant to the terms of the Company Incentive Plan.

 

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“Company Performance Warrant Plan” are to the amended and restated performance warrant plan of the Company, which amends and restates the Greenfire Equity Plan.

 

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“Company Performance Warrants” are to warrants to purchase Common Shares with each such warrant entitling the holder to purchase one the Company Common Share subject to the terms and conditions of the Company Performance Warrant Plan.

 

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“Company Securities” are to the Common Shares and Company Warrants, collectively.

 

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“Company Shareholders” are to the holders of the Common Shares.

 

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“Company Warrants” are to warrants to purchase Common Shares issued to MBSC Sponsor and former securityholders of Greenfire at Closing with each such warrant entitling the holder to purchase one Common Share at an exercise price of $11.50 per Common Share.

 

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“Credit Agreement” refers to a credit agreement, dated as of September 20, 2023, with Bank of Montreal, as agent, and a syndicate of certain other financial institutions as lenders to provide for senior secured extendible revolving credit facilities.

 

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“Consideration” are to, collectively, the Cash Consideration and the Share Consideration.

 

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“Court” are to the Alberta Court of King’s Bench.

 

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“CRA” are to the Canada Revenue Agency.

 

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“Crown” are to His Majesty the King in right of Canada or His Majesty the King in right of the Province of Alberta, as the context may require.

 

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“Demo GP” are to Hangingstone Demo (GP) Inc.

 

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“Demo LP” are to Hangingstone Demo Limited Partnership.

 

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“DE Merger Sub” are to DE Greenfire Merger Sub Inc., a Delaware corporation and a direct, wholly-owned subsidiary of the Company.

 

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“Demo Asset” are to the Hangingstone Demonstration Facility, a SAGD thermal oil sands production facility in the Athabasca region of Alberta.

 

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“diluent” are to lighter viscosity petroleum products that are used to dilute bitumen for transportation in pipelines.

 

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“Directors” are to the directors of the Company.

 

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“ESG” are to environmental, social and governance.

 

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“Exchange Act” are to the U.S. Securities Exchange Act of 1934, as amended.

 

 

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“Excluded MBSC Class A Common Share” are to each MBSC Class A Common Share held in MBSC’s treasury or owned by Greenfire or any other wholly-owned subsidiary of Greenfire or MBSC immediately prior to the Merger Effective Time.

 

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“Expansion Asset” are to the Hangingstone Expansion Facility, a SAGD thermal oil sands production facility in the Athabasca region of Alberta.

 

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“Expansion GP” are to Hangingstone Expansion (GP) Inc.

 

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“Expansion LP” are to Hangingstone Expansion Limited Partnership.

 

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“Forward Purchase Agreement” are to that agreement entered into by MBSC and M3-Brigade III FPA LP, an affiliate of the MBSC Sponsor, dated October 21, 2021, which provides for the purchase of up to $40,000,000 of shares of Class A common stock, for a purchase price of $10.00 per share.

 

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“GAC” are to Greenfire Acquisition Corporation.

 

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“GAC HoldCo” are to GAC HoldCo Inc.

 

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“GHOPCO” are to Greenfire Hangingstone Operating Corporation.

 

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“Governing Documents” are to the legal document(s) by which any Person (other than an individual) establishes its legal existence or which govern its internal affairs. For example, the “Governing Documents” of a U.S. corporation are its certificate or articles of incorporation and bylaws and the “Governing Documents” of an Alberta corporation are its certificate and articles of incorporation, bylaws and any unanimous shareholders agreement that may be in force.

 

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“Governmental Entity” means any United States, Canadian, international or other (a) federal, state, provincial, local, municipal or other government entity, (b) governmental or quasi-governmental entity of any nature (including any governmental agency, branch, department, official, bureau, ministry or entity and any court or other tribunal), or (c) body exercising or entitled to exercise any administrative, executive, judicial, legislative, police, regulatory, or taxing authority or power of any nature, including any arbitrator or arbitral tribunal (public or private).

 

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“Greenfire” are to Greenfire Resources Inc., an Alberta corporation.

 

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“Greenfire Board” are to the board of directors of Greenfire.

 

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“Greenfire Bond Warrant” are to, as of any determination time, each warrant to purchase Greenfire Common Shares that is outstanding, unexercised and issued pursuant to the Greenfire Warrant Agreement.

 

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“Greenfire Common Shares” are to the common shares in the authorized share capital of Greenfire.

 

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“Greenfire Enterprise Value” are to $950,000,000.

 

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“Greenfire Equity Plan” are to the Greenfire Resources Inc. Performance Warrant Plan, dated February 2, 2022, as amended from time to time, and the Greenfire Employee Trust established by trust agreement between Greenfire and Greenfire Resources Employment Corporation dated March 7, 2022, as amended from time to time.

 

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“Greenfire Employee Shareholders” are to all holders of Greenfire Common Shares other than the Greenfire Founders.

 

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“Greenfire Founders” are to Annapurna Limited, Spicelo Limited, Modro Holdings LLC and Allard Services Limited.

 

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“Greenfire Holders” are to certain former securityholders of Greenfire who are Selling Securityholders under this prospectus.

 

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“Greenfire Indenture” are to the Indenture, dated as of August 12, 2021, by and among Greenfire (formerly GAC HoldCo Inc.), the guarantors party thereto from time to time, The Bank of New York Mellon, as trustee, BNY Trust Company of Canada, as Canadian co-trustee, and BNY Trust Company of Canada, as collateral agent, and any and all successors thereto, as amended, restated, supplemented or otherwise modified.

 

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“Greenfire Net Indebtedness” are to $170,000,000.

 

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“Greenfire Performance Warrant” are to, as of any determination time, each warrant to purchase Greenfire Common Shares issued pursuant to the Greenfire Equity Plan that is outstanding and unexercised, whether vested or unvested.

 

 

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“Greenfire Performance Warrantholders” are to the holders of the Greenfire Performance Warrants.

 

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“Greenfire Pre-Money Equity Value” are to the (A) the Greenfire Enterprise Value minus (B) Greenfire Net Indebtedness.

 

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“Greenfire Shareholders” are to the holders of Greenfire Common Shares as of any determination time prior to the Merger Effective Time or the Arrangement Effective Time, as applicable.

 

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“Greenfire Supplemental Warrant Agreement” are to the First Supplemental Warrant Agreement, dated December 14, 2022, between Greenfire and The Bank of New York Mellon, as warrant agent amending the Greenfire Warrant Agreement.

 

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“Greenfire Warrant Agreement” are to that certain Warrant Agreement dated as of August 12, 2021 between GAC Holdco Inc. (n/k/a Greenfire Resources Inc.), as issuer and The Bank of New York Mellon, as warrant agent providing for the issuance of Greenfire Bond Warrants.

 

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“Hangingstone Facilities” are to, collectively, the Demo Asset and the Expansion Asset.

 

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“HEAC” are to HE Acquisition Corporation.

 

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“Holder” are to a person who is a beneficial owner of the Company Securities immediately following the Business Combination.

 

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“Hydrocarbons” are to crude oil, natural gas, condensate, drip gas and natural gas liquids, coalbed gas, ethane, propane, iso-butane, nor-butane, gasoline, scrubber liquids and other liquids or gaseous hydrocarbons or other substances (including minerals or gases) or any combination thereof, produced or associated therewith.

 

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“IFRS” are to the International Financial Reporting Standards, as issued by the International Accounting Standards Board.

 

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“in situ” are to “in place” and, when referring to oil sands, means a process for recovering bitumen from oil sands by means other than surface mining, such as SAGD.

 

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“Investor Rights Agreement” are to the investor rights agreement into at the Closing by and among the Company, the MBSC Sponsor, the other holders of the MBSC Class B Common Shares, the PIPE Investors and certain former Greenfire Shareholders.

 

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“IRS” are to the U.S. Internal Revenue Service.

 

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“ITA” are to the Income Tax Act (Canada) and the regulations made thereunder as amended from time to time.

 

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“JACOS” are to Japan Oil Sands Limited.

 

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“JACOS Acquisition” are to the acquisition of all of the issued and outstanding shares in the capital of JACOS from Canada Oil Sands Co. Ltd., for a purchase price of approximately CAD$347 million on September 17, 2021 by Greenfire through its subsidiary predecessor entities.

 

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“JOBS Act” are to the Jumpstart Our Business Startups Act of 2012.

 

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“Law” are to, to the extent applicable, any federal, state, local, provincial, municipal, foreign, national or supranational statute, law (including statutory, common, civil or otherwise), act, statute, ordinance, treaty, rule, code, regulation, judgment, award, order, decree or other binding directive or guidance issued, promulgated or enforced by a Governmental Entity having jurisdiction over a given matter.

 

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“Listing Rules” are to the exchange listing rules of the NYSE.

 

 

●

“Lock-Up Agreement” are to the lock-up agreement by and among the Company, the MBSC Sponsor, and certain former Greenfire Shareholders entered into at the Closing.

 

●

“MBSC” are to M3-Brigade Acquisition III Corp., a Delaware corporation.

 

●

“MBSC Articles” are to the amended and restated certificate of incorporation of MBSC, adopted on October 21, 2021, as may be amended and/or restated from time to time.

 

●

“MBSC Bylaws” are to the bylaws of MBSC, as may be amended and/or restated from time to time.

 

●

“MBSC Board” are to the board of directors of MBSC.

 

●

“MBSC Class A Common Shares” are to MBSC’s Class A common shares, par value $0.0001 per share, which are subject to possible redemption.

 

●

“MBSC Class B Common Shares” are to MBSC’s Class B common shares, par value $0.0001 per share.

 

●

“MBSC Class B Common Share Amount” are to an amount equal to the number of MBSC Class B Common Shares outstanding at the Merger Effective Time (other than any Excluded MBSC Class A Common Shares, and, for the avoidance of doubt, after giving effect to any certain forfeitures pursuant to Section 4.6(a) and Section 4.6(b) of the Business Combination Agreement), multiplied by $10.10.

 

●

“MBSC Common Shares” are to the MBSC Class A Common Shares and the MBSC Class B Common Shares.

 

●

“MBSC Extension Amount” means, as of any measurement time, the aggregate amount deposited by the MBSC Sponsor, or its affiliates or designees to the Trust Account to extend the period of time MBSC shall have to consummate an Initial Business Combination (as defined in the MBSC Articles) pursuant to Section 9.1(c) of the MBSC Articles.

 

●

“MBSC Founder Shares” are to the outstanding MBSC Class B Common Shares.

 

●

“MBSC Initial Stockholders” are to the MBSC Sponsor, MBSC’s current executive officers and current independent directors, as well as MBSC’s officers, other current directors and other special advisors.

 

●

“MBSC IPO” are to MBSC’s initial public offering of MBSC Units, which closed on October 26, 2021.

 

●

“MBSC Private Placement Warrants” are to the warrants issued to the MBSC Sponsor and to Cantor in a private placement simultaneously with the closing of the MBSC IPO.

 

●

“MBSC Private Warrant Agreement” are to the Private Warrant Agreement, dated October 21, 2021, between MBSC and Continental Stock Transfer and Trust Company, as warrant agent.

 

●

“MBSC Public Shares” are to MBSC Class A Common Shares sold as part of the MBSC Units in the MBSC IPO (whether they were purchased in the MBSC IPO or thereafter in the open market).

 

●

“MBSC Public Stockholders” are to the holders of MBSC Public Shares.

 

●

“MBSC Public Warrants” are to the MBSC Warrants held by any Persons other than the MBSC Sponsor and Cantor.

 

●

“MBSC Sponsor” are to M3-Brigade Sponsor III LP, a Delaware limited partnership.

 

●

“MBSC Sponsor Class B Share Forfeitures” are to, immediately prior to the Merger, (i) the forfeiture and cancellation for no consideration of 750,000 MBSC Class B Common Shares held by the MBSC Sponsor and (ii) the forfeiture and cancellation for no consideration of 2,500,000 MBSC Class B Common Shares held by the MBSC Sponsor.

 

●

“MBSC Sponsor Warrant Forfeiture” are to, immediately prior to the Merger, the forfeiture and cancellation of 3,260,000 MBSC Private Placement Warrants held by the MBSC Sponsor for no consideration.

 

●

“MBSC Stockholder Redemption” are to the right of the holders of MBSC Class A Common Shares to redeem all or a portion of their MBSC Class A Common Shares as set forth in MBSC’s Governing Documents.

 

●

“MBSC Stockholders” are to, collectively, the MBSC Initial Stockholders and the MBSC Public Stockholders.

 

●

“MBSC Stockholders’ Meeting” are to the special meeting of MBSC Stockholders that is the subject of this prospectus and any adjournments thereof.

 

 

●

“MBSC Units” are to the units of MBSC sold in the MBSC IPO, each of which consists of one MBSC Class A Common Share and one-third of one MBSC Public Warrant.

 

●

“MBSC Warrant Agreements” are to the MBSC Private Warrant Agreement and the MBSC Public Warrant Agreement.

 

●

“MBSC Warrants” are to each warrant to purchase one MBSC Class A Common Share at an exercise price of $11.50 per share, subject to adjustment, on the terms and subject to the conditions set forth in the MBSC Warrant Agreements.

 

	●	“MBSC Working Capital” are to the unrestricted cash on the balance sheet of MBSC at Closing.
	●	“McDaniel” are to McDaniel & Associates Consultants Ltd.

 

●

“Merger” are to the merger of DE Merger Sub with and into MBSC pursuant to the Business Combination Agreement.

 

●

“Merger Effective Time” are to the effective time of the Merger.

 

●

“MMBOE” are to one million barrels of oil equivalent.

 

●

“NI 51-101” are to the National Instrument 51-101 — Standards of Disclosure for Oil and Gas Activities.

 

●

“NOI Proceedings” are to the proceedings commenced on October 8, 2020, by each of GHOPCO and its parent company, Greenfire Oil and Gas Ltd., filing a Notice of Intention to Make A Proposal pursuant to the provisions of the Bankruptcy and Insolvency Act (Canada).

 

●

“NOI Transaction” are to the asset purchase agreement between GHOPCO and GAC entered into around December 1, 2020, pursuant to which GAC agreed to acquire the Demo Asset from GHOPCO.

 

●

“Non-Canadian Holder” are as defined in the section entitled “Material Canadian Federal Income Tax Considerations.”

 

●

“Notes” are to, collectively, the Greenfire Bonds and the Company Convertible Notes.

 

●

“NYSE” are to the New York Stock Exchange.

 

●

“PCAOB” are to the Public Company Accounting Oversight Board (United States).

 

●

“Person” are to an individual, partnership, corporation, limited partnership, limited liability company, joint stock company, unincorporated organization or association, trust, joint venture or other similar entity, whether or not a legal entity.

 

●

“Petroleum Marketer” are to Trafigura Canada General Partnership and Trafigura Canada Limited, collectively.

 

●

“PIPE Financing” are to the subscription by certain investors for an aggregate of 4,950,496 MBSC Class A Common Shares for an aggregate purchase price of $50,000,000 pursuant to subscription agreements entered into with MBSC concurrently with the execution of the Business Combination Agreement.

 

●

“PIPE Investors” are to the investors participating in the PIPE Financing.

 

●

“Plan of Arrangement” are to the Plan of Arrangement made in accordance with the Business Combination Agreement and the Plan of Arrangement or made at the direction of the Court with the prior written consent of MBSC and Greenfire (such agreement not to be unreasonably withheld, conditioned or delayed by either MBSC or Greenfire, as applicable).

 

●

“Proposed Amendments” are as defined in the section entitled “Material Canadian Federal Income Tax Considerations.”

 

●

“Registrar” are to the Registrar of Corporations for the Province of Alberta or the Deputy Registrar of Corporations appointed under subsection 263(1) of the ABCA.

 

 

●

“Resale Registration Statement” are to the registration statement of which this prospectus forms a part, registering the resale of certain securities held by or issuable to certain former shareholders of MBSC and Greenfire and the PIPE Investors, filed by the Company pursuant to the Investor Rights Agreement.

 

●

“Reservoir” are to a subsurface body of rock having sufficient porosity and permeability to store and transmit fluids.

 

●

“SAGD” are to steam-assisted gravity drainage, an in-situ thermal oil production extraction technique.

 

●

“Sarbanes-Oxley Act” are to the U.S. Sarbanes-Oxley Act of 2002.

 

●

“SEC” are to the U.S. Securities and Exchange Commission.

 

●

“Securities Act” are to the U.S. Securities Act of 1933, as amended.

 

●

“ServiceCo” are to 2373525 Alberta Ltd.

 

●

“Share Consideration” are to the aggregate number of Company Consideration Shares equal to the quotient of: (a) the difference of (i) the Greenfire Pre-Money Equity Value, minus (ii) the Cash Consideration, minus (iii) Unpaid Expenses, minus (iv) the MBSC Class B Common Share Amount, divided by (b) $10.10.

 

●

“Sponsor Support Agreement” are to the sponsor agreement dated December 14, 2022, by and among the MBSC Sponsor, MBSC, the Company and Greenfire.

 

●

“SubCo” are to 2373436 Alberta Ltd.

 

●

“Subscription Agreements” are to those certain subscription agreements dated December 14, 2022 entered into by MBSC and the PIPE Investors.

 

●

“Surviving Greenfire” are to Greenfire as the surviving corporate entity following the Amalgamation.

 

●

“Surviving MBSC” are to MBSC as the survivor corporate entity following the Merger.

 

●

“Transactions” are to the transactions contemplated by the Business Combination Agreement, the Plan of Arrangement and the Ancillary Documents.

 

●

“Transfer Agent” are to Continental Stock Transfer & Trust Company, as transfer agent of MBSC.

 

●

“Treasury Regulations” means the United States Department of the Treasury regulations issued pursuant to the Code.

 

●

“Trust Account” are to the trust account that holds proceeds from the MBSC IPO and the concurrent private placement of the MBSC Private Placement Warrants, established by MBSC for the benefit of the MBSC Public Stockholders maintained at J.P. Morgan Chase Bank, N.A.

 

●

“U.S. GAAP” are to generally accepted accounting principles in the United States.

 

●

“Unpaid Expenses” are to Unpaid Greenfire Expenses and Unpaid MBSC Expenses, in each case to the extent limited pursuant to Section 2.3(b) of the Business Combination Agreement.

 

●

“Unpaid Greenfire Expenses” are to, as of any determination time, the Greenfire Expenses that are unpaid as of immediately prior to the Closing.

 

●

“Unpaid MBSC Expenses” are to MBSC Expenses that are unpaid as of immediately prior to the Closing.

 

●

“Warrant Agreements” are to the Warrant Agreement and Amended and Restated Warrant Agreement, each dated as of September 20, 2023, by and between Greenfire Resources Ltd., Computershare Inc. and Computershare Trust Company, N.A., governing the Greenfire Warrants.

 

●

“WCS” are to Western Canadian Select, which is the broadly used benchmark that reflects heavy oil prices at Hardisty, Alberta and “WCS differentials” are to the difference between WCS and WTI.

 

●

“WDB” are to Western Canada Dilbit Blend, a blended stream comprised of Sunrise Dilbit Blend, Hangingstone Dilbit Blend and Leismer Corner Blend.

 

●

“WTI” are to West Texas Intermediate, which is the current benchmark for mid-continent North American crude oil prices at Cushing, Oklahoma.

 

 

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

 

Some of the statements contained in this prospectus constitute forward-looking statements within the meaning of the federal securities laws. Forward-looking statements relate to expectations, beliefs, projections, future plans and strategies, anticipated events or trends and similar expressions concerning matters that are not historical facts. Forward-looking statements reflect the Company’s current views, as applicable, with respect to, among other things, their respective capital resources, performance and results of operations. Likewise, all of the Company’s statements regarding anticipated growth in operations, anticipated market conditions, demographics, reserves and results of operations are forward-looking statements. In some cases, you can identify these forward-looking statements by the use of terminology such as “outlook,” “believes,” “expects,” “potential,” “continues,” “may,” “will,” “should,” “could,” “seeks,” “approximately,” “predicts,” “intends,” “plans,” “scheduled,” “forecasts,” “estimates,” “anticipates” or the negative version of these words or other comparable words or phrases.

 

The forward-looking statements in this prospectus reflect the Company’s current views, as applicable, about future events that are subject to numerous known and unknown risks, uncertainties, assumptions and changes in circumstances that may cause actual results to differ significantly from those expressed in any forward-looking statement. The transactions and events described in this prospectus may not happen as described (or they may not happen at all). The following factors, among others, could cause actual results and future events to differ materially from those set forth or contemplated in the forward-looking statements:

 

●

general economic uncertainty;

 

●

the Company’s ability to maintain the listing of the Common Shares on the NYSE, the TSX or any other national stock exchange;

 

●

potential disruption in the Company’s employee retention as a result of the Business Combination;

 

●

potential litigation, governmental or regulatory proceedings, investigations or inquiries involving the Company, including in relation to the Business Combination;

 

●

international, national or local economic, social or political conditions that could adversely affect the companies and their business;

 

●

the effectiveness of the Company’s internal controls and its corporate policies and procedures;

 

●

changes in personnel and availability of qualified personnel;

 

●

environmental uncertainties and risks related to adverse weather conditions and natural disasters;

 

●

potential write-downs, write-offs, restructuring and impairment or other charges required to be taken by the Company due to the Business Combination;

 

●

the limited experience of certain members of the Company’s management team in operating a public company in the United States;

 

●

the volatility of the market price and liquidity of the Common Shares;

 

●

the volatility of the prices of crude oil, diluted bitumen, non-diluted bitumen and the differentials among various crude oil prices, natural gas and power;

 

●

risks associated with the Company’s SAGD operations, including reservoir performance, operating cost increases and various other factors, could adversely affect the Company’s operating results;

 

●

risks associated with the recovery of bitumen using SAGD processes, including uncertainty as to whether bitumen will be recovered in the expected volumes and at the expected economics;

 

●

the Company’s reliance on the Petroleum Marketer;

 

 

●

the risk that the Company’s capital expenditures relating to debottlenecking its production from the Demo Asset and Expansion Asset do not perform as anticipated;

 

●

risks associated with estimating quantities of reserves and future net revenues to be derived therefrom;

 

●

a failure to achieve anticipated benefits of acquisitions or the need to dispose of non-core assets for less than their carrying value on the financial statements as a result of weak market conditions;

 

●

global political events that affect commodity prices;

 

●

the risk that the Company’s properties may be subject to actions and opposition by non-governmental agencies;

 

●

the risk that the COVID-19 pandemic continues to cause disruptions in economic activity internationally and impact demand for crude oil and bitumen;

 

●

risks associated with the Company’s groundwater licenses;

 

●

costs associated with abandonment and reclamation that the Company may have to pay;

 

●

a failure by the Company to obtain the regulatory approvals it needs for general operating activities or compliance for decommissioning;

 

●

the geographical concentration of the Company’s assets;

 

●

lack of capacity and/or regulatory constraints on gathering and processing facilities, pipeline systems, trucking and railway lines;

 

●

competition with other oil and natural gas companies;

 

●

changes to the demand for oil and natural gas products and the rise of petroleum alternatives;

 

●

changes to current, or implementation of additional, regulations applicable to the Company’s operations;

 

●

changes to royalty regimes;

 

●

a failure to secure the services and equipment necessary for the Company’s operations for the expected price, on the expected timeline, or at all;

 

●

seasonal weather conditions that may cause operational delays;

 

●

changes to applicable tax laws or government incentive programs;

 

●

the Company’s ability to obtain financing to fund the acquisition, exploration and development of properties on a timely fashion and on acceptable terms;

 

●

defects in the title or rights to produce the Company’s properties;

 

●

the risk that the Company will be required to surrender lands to the Province of Alberta if annual lease payments are not made;

 

 

●

risk management activities that expose the Company to the risk of financial loss and counter-party risk;

 

●

the occurrence of an uninsurable event;

 

●

opposition by First Nations groups to the conduct of the Company’s operations, development or exploratory activities;

 

●

an inability to recruit and retain a skilled workforce and key personnel;

 

●

the impact of climate change and other environmental concerns on demand for the Company’s products and securities;

 

●

the potential physical effects of climate change on the Company’s production and costs;

 

●

the direct and indirect costs of various GHG and other environmental regulations, existing and proposed;

 

●

any breaches of the Company’s cyber-security and loss of, or unauthorized access to, data;

 

●

changes to applicable tax laws and regulations or exposure to additional tax liabilities;

 

●

the significant increased expenses and administrative burdens that the Company incurs as a public company;

 

●

internal control weaknesses and any misstatements of financial statements or the Company’s inability to meet periodic reporting obligations;

 

●

foreign currency and interest rate fluctuations; and

 

●

failure to comply with anticorruption, economic sanctions, and anti-money laundering laws.

 

Additionally, statements relating to “reserves” are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and can be profitably produced in the future. Forward-looking statements are inherently uncertain. Estimates such as expected revenue, production, operating expenses, transportation and marketing expenses, adjusted EBITDA, general and administrative expenses, interest and financing expense, taxes, capital expenditures, adjusted funds flow, net debt, reserves and other measures are preliminary in nature. There can be no assurance that the forward-looking statements will prove to be accurate and reliance should not be placed on these estimates in making your investment decision with respect to our securities.

 

The forward-looking statements contained herein are subject to risks, uncertainties and other factors, which could cause actual results to differ materially from future results expressed, projected or implied by the forward-looking statements. For a further discussion of the risks and other factors that could cause the Company’s future results, performance or transactions to differ significantly from those expressed in any forward-looking statements, please see the section entitled “Risk Factors.” There may be additional risks that the Company does not presently know or that the Company currently believes are immaterial, that could also cause actual results to differ from those contained in the forward-looking statements. Should one or more of these risks or uncertainties materialize, or should any of the assumptions made in making these forward-looking statements prove incorrect, actual results may vary materially from those projected in these forward-looking statements. While such forward-looking statements reflect the Company’s good faith beliefs, they are not guarantees of future performance. The Company disclaims any obligation to publicly update or revise any forward-looking statement to reflect changes in underlying assumptions or factors, new information, data or methods, future events or other changes after the date of this prospectus, except as required by applicable law. You should not place undue reliance on any forward-looking statements, which are based only on information currently available to the Company.

 

 

 

 

 

 

 

RISK FACTORS

 

You should carefully review and consider the following risk factors and the other information contained in this prospectus, including the financial statements and notes to the financial statements included herein before making a decision to invest in our Securities. The occurrence of one or more of the events or circumstances described in these risk factors, alone or in combination with other events or circumstances, may have a material adverse effect on the business, cash flows, financial condition and results of operations of the Company. This could cause the trading price of the Common Shares or the Company Warrants to decline, perhaps significantly, and you therefore may lose all or part of your investment. You should carefully consider the following risk factors in conjunction with the other information included in this prospectus, including matters addressed in the section entitled “Cautionary Note Regarding Forward-Looking Statements,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the financial statements of Greenfire, and notes to the financial statements included herein. The risks discussed below are not exhaustive and are based on certain assumptions made by the Company which later may prove to be incorrect or incomplete. Investors are encouraged to perform their own investigation with respect to the business, financial condition and prospects of the Company. The Company may face additional risks and uncertainties that are not presently known to it, or that are currently deemed immaterial, which may also impair its business or financial condition.

 

Risks Related to the Company’s Operations and the Oil and Gas Industry

 

The prices of crude oil, diluted bitumen, non-diluted bitumen and the differentials among various crude oil prices, natural gas and power are volatile and outside of the Company’s control and affect its revenues, profitability, cash flows and future rate of growth.

 

The Company’s revenues, profitability, cash flows and future rate of growth are highly dependent on commodity prices, including with respect to crude oil, diluted bitumen, non-diluted bitumen and the differentials among various crude oil prices, natural gas and power. Commodity prices may fluctuate widely in response to relatively minor changes in the supply of, and demand for, crude oil, diluted bitumen and non-diluted bitumen, natural gas, power, market uncertainty and a variety of additional factors that are beyond the Company’s control, such as:

 

●

domestic and global supply of, and demand for, crude oil, diluted bitumen, non-diluted bitumen and natural gas, as impacted by economic factors that affect gross domestic product growth rates of countries around the world, including impacts from international trade, pandemics and related concerns;

 

●

market expectations with respect to the future supply of, and demand for, crude oil, Natural Gas Liquids (“NGLs”) and natural gas and price changes;

 

●

global crude oil, diluted bitumen, non-diluted bitumen and natural gas inventory levels;

 

●

volatility and trading patterns in the commodity-futures markets;

 

●

the proximity, capacity, cost and availability of pipelines and other transportation facilities;

 

●

the capacity of refiners to utilize available supplies of crude oil and condensate;

 

●

weather conditions affecting supply and demand;

 

●

overall domestic and global political and economic conditions;

 

●

actions of Organization of Petroleum Exporting Countries (“OPEC”), its members and other state-controlled oil companies relating to oil price and production controls;

 

●

fluctuations in the value of the U.S. dollar relative to the Canadian dollar;

 

●

the price and quantity of crude oil, diluent and LNG imports to and exports from the U.S. and other countries;

 

●

the development of new hydrocarbon exploration, production and transportation methods or technological advancements in existing methods, including hydraulic fracturing and SAGD;

 

●

capital investments by oil and gas companies relating to the exploration, development and production of hydrocarbons;

 

●

social attitudes or policies affecting energy consumption and energy supply;

 

●

domestic and foreign governmental regulations, including environmental regulations, climate change regulations and applicable tax regulations;

 

 

●

shareholder activism or activities by non-governmental organizations to limit certain sources of capital for the energy sector or restrict the exploration, development and production of crude oil and natural gas; and

 

●

the effect of energy conservation efforts and the price, availability and acceptance of alternative energies, including renewable energy.

 

The Company makes price assumptions regarding commodity prices that are used for planning purposes, and a significant portion of its cash outlays, including capital, operating and transportation commitments, are largely fixed in nature. Accordingly, if commodity prices are below the expectations on which these commitments were based, the Company’s financial results are likely to be adversely affected because these cash outlays are not variable in the short term and cannot be quickly reduced to respond to unanticipated decreases in commodity prices. The Company’s risk management arrangements will not fully mitigate the effects of unexpected price fluctuations.

 

Significant or extended price declines could also materially and adversely affect the amount of diluted and non-diluted bitumen that the Company can economically produce, require the Company to make significant downward adjustments to its reserve estimates or result in the deferral or cancellation of the Company’s growth projects. A reduction in production could also result in a shortfall in expected cash flows and require the Company to reduce capital spending or borrow funds or access the capital markets to cover any such shortfall. Any of these factors could negatively affect the Company’s ability to replace its production and its future rate of growth.

 

The Company’s financial condition is substantially dependent on, and highly sensitive to, the prevailing prices of crude oil and the differentials among various crude oil prices and natural gas. Low prices for crude oil produced by the Company could have a material adverse effect on the Company’s operations, financial condition and the value and amount of the Company’s reserves.

 

Prices for crude oil and natural gas fluctuate in response to changes in the supply of, and demand for, crude oil and natural gas, market uncertainty and a variety of additional factors beyond the Company’s control. Crude oil prices are primarily determined by international supply and demand. Factors which affect crude oil prices include the actions of OPEC, the condition of the Canadian, United States, European and Asian economies, government regulation, political stability in the Middle East and elsewhere, the supply of crude oil in North America and internationally, the ability to secure adequate transportation for products, the availability of alternate fuel sources and weather conditions. Natural gas prices, which represent an energy input cost to the Company, are affected primarily in North America by supply and demand, weather conditions, industrial demand, prices of alternate sources of energy and developments related to the market for liquefied natural gas. All of these factors are beyond the Company’s control and can result in a high degree of price volatility. Fluctuations in currency exchange rates further compound this volatility when commodity prices, which are generally set in U.S. dollars, are stated in Canadian dollars.

 

The Company’s financial performance also depends on revenues from the sale of commodities which differ in quality and location from underlying commodity prices quoted on financial exchanges. The market prices for heavy oil (which includes bitumen blends) are lower than the established market prices for light and medium grades of oil, principally due to the cost of diluent and the higher transportation and refining costs associated with heavy oil. In addition, there is limited pipeline egress capacity for Canadian crude oil to access the American refinery complex or tidewater to access world markets, relative to production rates in Western Canada, and the availability of additional transport capacity via rail is more expensive and variable; therefore, the price for Canadian crude oil is very sensitive to pipeline and refinery outages, which contributes to this volatility. The market for heavy oil is also more limited than for light and medium grades of oil making it further susceptible to supply and demand fluctuations. These factors all contribute to price differentials. Future price differentials are uncertain and any widening in heavy oil differentials specifically could have an adverse effect on the Company’s results of operations, financial condition and prospects.

 

Decreases to or prolonged periods of low commodity prices, particularly for oil, may negatively impact the Company’s ability to meet guidance targets, maintain our business and meet all of the Company’s financial obligations as they come due. It could also result in the shut-in of currently producing wells without an equivalent decrease in expenses due to fixed costs, a delay or cancellation of existing or future drilling, development or construction programs, unutilized long-term transportation commitments and a reduction in the value and amount of the Company’s reserves.

 

The Company conducts assessments of the carrying value of the Company’s assets in accordance with IFRS. If crude oil and natural gas forecast prices decline, the carrying value of the Company’s assets could be subject to downward revisions and the Company’s net earnings could be adversely affected.

 

Risks associated with the marketability of oil affecting net production revenue, production volumes and development and exploration activities.

 

The Company’s ability to market its oil may depend upon its ability to acquire capacity in pipelines that deliver oil to commercial markets or contract for the delivery of oil by rail or truck. Numerous factors beyond the Company’s control do, and will continue to, affect the marketability and price of oil acquired, produced, or discovered by the Company, including:

 

●

deliverability uncertainties related to the distance the Company’s reserves are from pipelines, railway lines and processing and storage facilities;

 

 

●

operational problems affecting pipelines, railway lines and processing and storage facilities; and

 

●

government regulation relating to prices, taxes, royalties, land tenure, allowable production and the export of oil.

 

Prices for oil and natural gas are subject to large fluctuations in response to relatively minor changes in the supply of, and demand for, oil and natural gas, market uncertainty and a variety of additional factors beyond the control of the Company. These factors include the current state of the world economies, political conditions in the United States, Canada, Europe, China and emerging markets, the actions of OPEC, sanctions imposed on certain oil-producing nations by other countries, governmental regulation, political stability and conflict in the Middle East, Ukraine and elsewhere, the foreign supply and demand of oil and natural gas, risks of supply disruption, the price of foreign imports and the availability of alternative fuel sources. Prices for oil and natural gas are also subject to the availability of foreign markets and the Company’s ability to access such markets. Oil prices are expected to remain volatile as a result of a wide variety of factors, including but not limited to the actions and decisions of OPEC and other factors mentioned herein. A material decline in prices could result in a reduction of the Company’s net production revenue. The economics of producing from bitumen resources may change because of lower prices, which could result in reduced production of diluted and non-diluted bitumen, resulting in a reduction in the Company’s net production revenue and the value of the Company’s reserves. The Company might also elect not to produce from certain wells at lower prices.

 

All these factors could result in a material decrease in the Company’s net production revenue and a reduction in its production, development and exploration activities. Any substantial and extended decline in the price of oil would have an adverse effect on the Company’s carrying value of its reserves, borrowing capacity, revenues, profitability and cash flows from operations and may have a material adverse effect on the Company’s business, financial condition, results of operations and prospects.

 

Volatile oil and natural gas prices make it difficult to estimate the value of producing properties for acquisitions and often cause disruption in the market for oil and natural gas-producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for, and project the return on, acquisitions and development and exploitation projects.

 

Risks associated with SAGD operations could adversely affect the Company’s operating results.

 

The Company’s operating results and the value of its reserves and resources depend, in part, on the price received for diluted bitumen and non-diluted bitumen, as well as the operating costs of the Demo Asset and the Expansion Asset, all of which may significantly vary from the prices and costs that the Company currently anticipates. If such operating costs increase, or if the Company does not achieve its expected production volumes or revenue, the Company’s earnings and cash flow will be reduced, and its business and financial condition may be materially adversely affected. In addition to the other factors and variables discussed herein, principal factors which could affect the Company’s operating results include (without limitation):

 

●

increases in the price applied to carbon emissions;

 

●

lower than expected reservoir performance, including, but not limited to, lower oil production rates and/or higher steam oil ratio;

 

●

the reliability and maintenance of the Company’s facilities, including timely and cost-effective execution of turnaround activities;

 

●

the safety and reliability of pipelines, tankage, trucks, railways and railcars and barges that transport the Company’s products;

 

●

the need to replace significant portions of existing wells, referred to as “workovers”, or the need to drill additional wells;

 

●

the cost to transport bitumen, diluent and bitumen blend, and the cost to dispose of certain by-products;

 

●

reliance on the Petroleum Marketer as our sole third-party commodity marketer to market bitumen blend sales, procure diluent supply and perform logistics management for the Demo Asset and Expansion Asset;

 

●

reliance on the Petroleum Marketer as our sole third-party commodity marketer for timely payment of bitumen blend marketed on behalf of the Company;

 

●

labor disputes or disruptions, declines in labor productivity or the unavailability of, or increased cost of, skilled labor;

 

●

increases in the cost of materials, including in the current inflationary environment;

 

●

the availability of water supplies;

 

●

effects of inclement and severe weather events, including fire, drought and flooding;

 

●

the ability to obtain further approvals and permits for future potential projects;

 

●

engineering and/or procurement performance falling below expected levels of output or efficiency;

 

 

●

refining markets for the Company’s bitumen blend; and

 

●

the cost of chemicals used in the Company’s operations, including, but not limited to, in connection with water and/or oil treatment facilities.

 

The recovery of bitumen using SAGD processes is subject to uncertainty.

 

Current SAGD technologies for in situ extraction of bitumen or for reservoir injection require significant consumption of natural gas or other inputs to produce steam for use in the recovery process. There can be no assurance that the Company’s operations will produce bitumen at the expected levels or on schedule. The quality and performance of a bitumen reservoir can also impact the steam oil ratio and the timing and levels of production. In addition, the geological characteristics and integrity of bitumen reservoirs are inherently uncertain. The injection of steam into reservoirs under significant pressure may cause fluid containment issues and unforeseen damage to reservoirs, resulting in large steam losses in parts of the reservoir where caprock is compromised. Should these adverse reservoir conditions occur, they would have a negative impact on the Company’s ability to recover bitumen.

 

The Company’s future performance may be affected by the financial, operational, environmental and safety risks associated with the exploration, development and production of oil and natural gas.

 

Oil and natural gas operations involve many risks. The long-term commercial success of the Company depends on its ability to find, acquire, develop and commercially produce oil reserves. Without the continual addition of new reserves, the Company’s existing reserves, and the production from them, will decline over time as the Company produces from such reserves. A future increase in the Company’s reserves will depend on both the ability of the Company to explore and develop its existing properties and its ability to select and acquire suitable producing properties or prospects. the Company may not be able to continue to find satisfactory properties to acquire or participate in. Moreover, management of the Company may determine that current markets, terms of acquisitions, participation or pricing conditions make potential acquisitions or participation uneconomic. The Company may not discover or acquire further commercial quantities of oil and natural gas.

 

Future oil and natural gas exploration may involve unprofitable efforts from dry wells or wells that are productive but do not produce sufficient petroleum substances to return a profit after drilling, completing, operating and other costs. The completion of a well does not ensure a profit on the investment or recovery of drilling, completion and operating costs.

 

Drilling hazards, environmental damage and various field operating conditions could greatly increase the cost of operations and adversely affect the production from successful wells. Field operating conditions include, but are not limited to, delays in obtaining governmental approvals or consents, shut-ins of wells resulting from extreme weather conditions, insufficient storage or transportation capacity or geological and mechanical conditions. It is difficult to eliminate production delays and declines from normal field operating conditions, which can negatively affect revenue and cash flow levels to varying degrees.

 

Oil and natural gas exploration, development and production operations are subject to all the risks and hazards typically associated with such operations, including blowouts, craterings, explosions, uncontrollable flows of natural gas, NGLs or well fluids, fires, pipe, casing or cement failures, abnormal pressure, pipeline leaks, ruptures or spills, vandalism, pollution, releases of toxic gases, adverse weather conditions or natural disasters and other environmental hazards and risks. These typical risks and hazards could result in substantial damage to oil and natural gas wells, production facilities, other property and the environment and cause personal injury or threaten wildlife, all of which could result in liability to the Company.

 

Oil and natural gas production operations are also subject to geological and seismic risks, including encountering unexpected formations, pressures, reservoir thief zones such as bottom water and top gas and/or water, caprock integrity, premature decline of reservoirs and the invasion of water into producing formations. Losses resulting from the occurrence of any of these risks may have a material adverse effect on the Company’s business, financial condition, results of operations and prospects.

 

Shortages and volatility of pricing on commodity inputs could negatively impact the Company’s operating results.

 

The nature of the Company’s operations results in exposure to fluctuations in diluent, natural gas and electricity prices. Natural gas is a significant component of the Company’s cost structure, as it is used to generate steam for the SAGD process. Diluent, such as condensate, is also one of the Company’s significant commodity inputs and is used to decrease the viscosity of bitumen to allow it to be transported. Electricity is required to power facilities and wells. Historically, the markets for bitumen, diluent, natural gas and electricity have been volatile, and they are likely to continue to be volatile. Shortages of, and increased costs for, these inputs could increase the Company’s marketing and operating costs.

 

 

The Company is heavily reliant on the Petroleum Marketer as its sole third-party commodity marketer and a failure of the Petroleum Marketer to fulfill its obligations to the Company could have a significant negative impact on the Company’s operations, costs and cashflow.

 

The Company has contracted with the Petroleum Marketer as its sole third-party petroleum marketer and as a result faces concentrated counterparty risk if the Petroleum Marketer cannot, or refuses to, fulfill its contractual obligations. The Petroleum Marketer markets all of the Company’s product to buyers and thus is the sole source of all of the Company’s revenue. The Petroleum Marketer also sources and pays for diluent for the Company’s operations, provides security for key pipeline assignments, schedules and executes delivery of blend and diluent by pipeline and is responsible for transport of the Company’s bitumen when product is transported by truck. A failure of the Petroleum Marketer to provide any of those contracted services could have a significant negative impact on the Company’s operations, costs and cashflow.

 

There are numerous uncertainties inherent in estimating quantities of proved and probable reserves, quantities of contingent resources and future net revenues to be derived therefrom, including many factors beyond the Company’s control.

 

The reserves and estimated financial information with respect to certain of the Company’s oil sands leases have been independently evaluated by an independent reserve evaluation firm. These evaluations include several factors and assumptions made as of the date on which the evaluation is made, including but not limited to:

 

●

geological and engineering estimates, which have inherent uncertainties;

 

●

the effects of regulation by governmental agencies;

 

●

initial production rates;

 

●

production decline rates;

 

●

ultimate recovery of reserves;

 

●

timing and amount of capital expenditures;

 

●

marketability of production;

 

●

current and forecast prices of diluted and non-diluted bitumen, crude oil, condensate, power and natural gas;

 

●

the Company’s ability to transport its product to various markets;

 

●

operating costs;

 

●

abandonment and salvage values; and

 

●

royalties and other government levies that may be imposed over the producing life of the reserves.

 

Many of these assumptions that are valid at the time of the evaluation may change significantly when new information becomes available and may prove to be inaccurate. Furthermore, different reserve engineers may make different estimates of reserves based on the same data. The Company’s actual production, revenues and expenditures with respect to the Company’s oil sands leases will vary from these evaluations, and those variations may be material.

 

Reserves and estimates may require revision based on actual production experience. Such figures have been determined based on assumed commodity prices and operating costs. Market price fluctuations of bitumen, diluent and natural gas prices may render the recovery of certain grades of bitumen uneconomic. The present value of the Company’s estimated future net revenue in this report should not be construed as the fair market value of the Company’s reserves.

 

There is uncertainty associated with non-producing or undeveloped reserves.

 

The Company’s reserves may not ultimately be developed or produced in their entirety, either because it may not be commercially viable to do so or for other reasons. Furthermore, not all of the Company’s undeveloped or developed non-producing reserves may be ultimately produced on the Company’s projected timelines, at the costs the Company has budgeted, or at all. A shortfall in production below could have an adverse effect on the Company’s business, financial condition, results of operations and prospects.

 

 

The anticipated benefits of acquisitions may not be achieved and the Company may dispose of non-core assets for less than their carrying value on the financial statements as a result of weak market conditions.

 

The Company evaluates and, where appropriate, pursues acquisitions of additional mineral leases or oil and gas assets in the ordinary course of business. Acquisitions of mineral leases, as well as the exploration and development of land subject to such leases, may require substantial capital or the incurrence of substantial additional indebtedness. Furthermore, the acquisition of any additional mineral leases may not ultimately increase the Company’s reserves and contingent resources or result in any additional production of bitumen. If the Company consummates any future acquisitions of mineral leases, it may need to change its anticipated capital expenditure programs and the use of the Company’s capital resources. Management continually assesses the value and contribution of services provided by third parties and the resources required to provide such services. In this regard, non-core assets may be periodically disposed of so the Company can focus its efforts and resources more efficiently. Depending on the market conditions for such non-core assets, certain non-core assets of the Company may realize less on disposition than their carrying value on the financial statements of the Company.

 

Global political events may adversely affect commodity prices, which in turn affect the Company’s cash flow.

 

Political events throughout the world that cause disruptions in the supply of oil continuously affect the marketability and price of oil and natural gas acquired or discovered by the Company. Conflicts, or conversely peaceful developments, arising outside of Canada, including changes in political regimes or the parties in power, have a significant impact on the price of oil and natural gas. Any particular event could result in a material decline in prices and result in a reduction of the Company’s net production revenue.

 

The Company’s properties may be subject to actions and opposition by non-governmental agencies.

 

In addition to the risks outlined above related to geopolitical developments, the Company’s oil and natural gas properties, wells and facilities could be subject to physical sabotage or public opposition. Such public opposition could expose the Company to the risk of higher costs, delays or even project cancellations due to increased pressure on governments and regulators by special interest groups including First Nations groups, landowners, environmental interest groups (including those opposed to oil and natural gas production operations) and other non-governmental organizations, blockades, legal or regulatory actions or challenges, increased regulatory oversight, reduced support from the federal, provincial or municipal governments, delays in, challenges to, or the revocation of regulatory approvals, permits and/or licenses, and direct legal challenges, including the possibility of climate-related litigation. The Company may not be able to satisfy the concerns of special interest groups and non-governmental organizations and attempting to address such concerns may require the Company to incur significant and unanticipated capital and operating expenditures. If any of the Company’s properties, wells or facilities are the subject of physical sabotage or public opposition, it may have a material adverse effect on the Company’s business, financial condition, results of operations and prospects. The Company does not have insurance to protect against such risks.

 

Disruptions caused by the COVID-19 pandemic continue to affect economic activity in Canada and internationally and impact demand for oil, natural gas liquids and natural gas.

 

The COVID-19 pandemic, and actions taken in response, resulted in a significant contraction in the global economy. This caused a period of unprecedented disruption in the oil and gas industry and negatively impacted the demand for, and pricing of, energy products, including diluted bitumen and non-diluted bitumen produced by the Company. A consequence of this disruption is that the oil and gas industry experienced a period of market contraction. Furthermore, the oil and gas industry experienced increased counterparty risk. Although the pricing of energy products has begun to trend back towards historical norms, volatility originally resulting from the pandemic persists and disruptions to the oil and gas industry could continue.

 

Throughout and following the COVID-19 pandemic, inflation has been driven by many factors, including disruptions to local and global supply chains and transportation services. Inflation in Canada has significantly increased labor and capital costs for drilling, construction and equipment. Additionally, increased demand for experienced technical and manual labor in Northern Alberta and delays in procurement of equipment such as steel, tanks, machinery and electrical components can increase the time required to complete projects. Inflation and disruptions to supply chain and transportation services have the potential to disrupt the Company’s operations, projects and financial condition.

 

There may be further disruption in the demand for certain commodities, which may have a prolonged adverse effect on the Company’s financial condition, operations, income, results from operations and cash flows. Additionally, the effect on local and global economic conditions stemming from the pandemic could also aggravate the other risk factors identified herein, the extent of which is not yet known.

 

 

 

The successful operation of a portion of the Company’s properties is dependent on third parties.

 

The Company’s projects will depend on the availability and successful operation of certain infrastructure owned and operated by third parties or joint ventures with third parties, including (without limitation):

 

●

pipelines for the transport of natural gas, diluent and diluted bitumen;

 

●

refinery operators;

 

●

power transmission grids supplying and exporting electricity; and

 

●

other third-party transportation infrastructure such as roads, rail, airstrips, terminals and vessels.

 

The unavailability or decreased capacity of any or all of the infrastructure described above could negatively impact the operation of the Company’s projects, which, in turn, may have a material adverse effect on the Company’s results of operations, financial condition and prospects.

 

In addition, if any of the Company’s various counterparties experience financial difficulty, it could impact their ability to fund and pursue capital expenditures, carry out their operations in a safe and effective manner and satisfy regulatory requirements with respect to abandonment and reclamation obligations. If such companies fail to satisfy regulatory requirements with respect to abandonment and reclamation obligations, the Company may be required to satisfy such obligations and seek reimbursement from such companies. To the extent that any of such companies go bankrupt, become insolvent or make a proposal or institute any proceedings relating to bankruptcy or insolvency, it could result in such assets being shut-in, the Company potentially becoming subject to additional liabilities relating to such assets and the Company having difficulty collecting revenue due from such operators or recovering amounts owing to the Company from such operators for their share of abandonment and reclamation obligations. Any of these factors could have a material adverse effect on the Company’s financial and operational results.

 

Firm transportation and storage agreements require the Company to pay demand charges for firm transportation and storage capacities that it does not use.

 

The Company pays fixed charges for storage and transportation of operating inputs such as natural gas, diluent and electricity, regardless of whether bitumen and blend are being produced. If the Company fails to use its firm transportation and storage capacities due to production shortfalls or otherwise, margins, results of operations and financial performance could be adversely affected.

 

The Company may be unable to retain existing suppliers.

 

The Company may be unable to retain existing suppliers, contractors or employees, unless it provides letters of credit or other financial assurances, the quantum of which may eventually prove to be higher than the Company’s current estimates. The Company may have restricted access to capital and increased borrowing costs. Failure to obtain financing on a timely basis could impair the Company’s ability to retain such suppliers, contractors or employees, which could have a material adverse effect on its operations.

 

The Company relies on groundwater licenses, which, if rescinded or the conditions of which are amended, could disrupt its business and have a material adverse effect on its business, financial condition, results of operations and prospects.

 

The Company relies on access to groundwater, which is obtained under government licenses, to provide the substantial quantities of water required for certain of its operations. The licenses to withdraw water may be rescinded or additional conditions may be added to these licenses. Further, the Company may have to pay increased fees for the use of water in the future, and any such fees may be uneconomic. Finally, new projects or the expansion of existing projects may be dependent on securing licenses for additional water withdrawal, and these licenses may be granted on terms not favorable to the Company, or at all, and such additional water may not be available to divert under such licenses. Any prolonged droughts in the Fort McMurray area could result in the Company’s groundwater licenses being subject to additional conditions or rescission. The Company’s inability to secure groundwater licenses in the future and any amendment to or rescission of, its current licenses may disrupt its business and have a material adverse effect on the Company’s business, financial condition, results of operations and prospects.

 

The Company may have to pay certain costs associated with abandonment and reclamation in excess of amounts currently estimated in its consolidated financial statements.

 

The Company will need to comply with the terms and conditions of environmental and regulatory approvals and all legislation regarding the abandonment of its projects and reclamation of the project lands at the end of their economic life, which may result in substantial abandonment and reclamation costs. Any failure to comply with the terms and conditions of the Company’s approvals and legislation may result in the imposition of fines and penalties, which may be material. Generally, abandonment and reclamation costs are substantial and, while the Company accrues a reserve in its financial statements for such costs in accordance with IFRS, such accruals may be insufficient.

 

 

In the future, the Company may determine it prudent or be required by applicable Laws, regulations or regulatory approvals to establish and fund one or more reclamation funds to provide for payment of future abandonment and reclamation costs. If the Company establishes a reclamation fund, its liquidity and cash flow may be adversely affected.

 

Alberta has developed a liability management framework designed to prevent the Government of Alberta from incurring costs associated with suspension, abandonment, remediation and reclamation of wells, facilities and pipelines if a licensee or permit holder is unable to satisfy its regulatory obligations. The implementation of or changes to the requirements of the liability management framework may result in significant increases to the security that must be posted by licensees, increased and more frequent financial disclosure obligations or may result in the denial of license or permit transfers, which could impact the availability of capital to be spent by such licensees which could in turn materially adversely affect the Company’s business and financial condition. In addition, this liability management framework may prevent or interfere with a licensee’s ability to acquire or dispose of assets, as both the vendor and the purchaser of oil and natural gas assets must be in compliance with the liability management framework for the applicable regulatory agency to allow for the transfer of such assets.

 

The Company may not be able to obtain the regulatory approvals it needs for general operating activities or compliance for decommissioning.

 

The construction, operation and eventual decommissioning of the Demo Asset and the Expansion Asset and other potential future projects are and will be conditional upon various environmental and regulatory approvals, permits, leases and licenses issued by governmental authorities, including but not limited to the approval of the Alberta Energy Regulator and the Alberta Ministry of Environment and Protected Areas. There can be no assurance that such approvals, permits, leases and licenses will be granted or, once granted, that they will subsequently be renewed or will not be cancelled or contain terms and conditions which make the Company’s projects uneconomic, or cause the Company to significantly alter its projects. Further, the construction, operation and decommissioning of the Demo Asset and Expansion Asset projects and other potential future projects will be subject to regulatory approvals and statutes and regulations relating to environmental protection and operational safety. There can be no assurance that third parties will not object to the development of such projects during applicable regulatory processes.

 

Due to the geographical concentration of the Company’s assets, the Company may be disproportionately impacted by delays or interruptions in the region in which it operates.

 

The Company’s properties and production are focused in the Southern Athabasca region of Northeastern Alberta. As a result, the Company may be disproportionately exposed to the impact of delays or interruptions of production caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, water shortages, significant governmental regulation, natural disasters, fires, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of oil or natural gas produced from the wells in these areas.

 

In addition, the effect of fluctuations on supply and demand may become more pronounced within the specific geographic oil and gas-producing areas in which the Company’s properties are located, which may cause these conditions to occur with greater frequency or magnify the effect of these conditions on the Company. Due to the concentrated nature of the Company’s portfolio of properties, a number of the Company’s properties could experience one or more of the same conditions at the same time, resulting in a relatively greater impact on the Company’s results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on the operating results and financial condition of the Company.

 

Entrance into new industry-related activities or geographical areas could adversely affect the Company’s future operational and financial conditions.

 

In the future, the Company may acquire or move into new industry-related activities or new geographical areas or acquire different energy-related assets, and as a result, may face unexpected risks or alternatively, significantly increase its exposure to one or more existing risk factors, which may in turn result in the Company’s future operational and financial conditions being adversely affected.

 

The Company’s operations may be negatively impacted by factors outside of its control, resulting in operational delays and cost overruns.

 

Project interruptions may delay expected revenues from operations. Significant project cost overruns could make a project uneconomic. The Company’s ability to execute projects and to market bitumen depends upon numerous factors beyond the Company’s control, including:

 

●

availability of processing capacity;

 

●

availability and proximity of pipeline capacity;

 

●

availability of trucking sources;

 

●

availability of storage capacity;

 

●

availability and cost of diluent, natural gas and power;

 

●

changes in production or regulation of sulfur and/or sulfur dioxide;

 

 

●

availability of, and the ability to acquire, water supplies needed for drilling and SAGD operations or the Company’s ability to dispose of water used or removed from strata at a reasonable cost and in accordance with applicable environmental regulations;

 

●

effects of inclement and severe weather events, including forest fires, drought and flooding;

 

●

availability of drilling and related equipment;

 

●

loss of wellbore integrity or failure of pressure equipment;

 

●

unexpected cost increases;

 

●

accidental events;

 

●

currency fluctuations;

 

●

regulatory changes;

 

●

availability and productivity of skilled labor; and

 

●

regulation of the oil and natural gas industry by various levels of government and governmental agencies.

 

A portion of the Company’s production costs are fixed regardless of current operating levels. As noted, the Company’s operating levels are subject to factors beyond its control that can delay deliveries or increase the cost of operation at particular sites for varying lengths of time. These factors include weather conditions (e.g., extreme winter weather, tornadoes, floods, and the lack of availability of process water due to drought), fires and other natural and man-made disasters, unanticipated geological conditions, including variations in the amount and type of rock and soil overlying the oil or natural gas deposits, variations in rock and other natural materials and variations in geologic conditions.

 

Fire in the Athabasca region has been a recurring issue and in 2016 resulted in the suspension of operations at the Demo Asset and suspension of construction at the Expansion Asset, as well as suspension of operations at surrounding SAGD facilities due to safety concerns.

 

The processes that take place in the Company’s facilities and those facilities owned by third parties through which the Company’s production is transported and processed depend on critical pieces of equipment. This equipment may, on occasion, be out of service because of unanticipated failures. In addition, some of these facilities have been in operation for several decades, and the equipment is aged. In the future, the Company may experience additional material shutdowns or periods of reduced production because of equipment failures. Further, remediation of any interruption in production capability may require the Company to make large capital expenditures that could have a negative effect on profitability and cash flows. The Company’s business interruption insurance may not cover all or any of the lost revenues associated with equipment failures. Longer-term business disruptions could result in a loss of customers, which adversely could affect future sales levels and profitability.

 

Lack of capacity and/or regulatory constraints on gathering and processing facilities, pipeline systems, trucking and railway lines may have a negative impact on the Company’s ability to produce and sell its oil and natural gas.

 

The Company delivers its products through gathering and processing facilities, pipeline systems and may in certain circumstances, deliver by truck and rail. The amount of bitumen that the Company can produce and sell is subject to the accessibility, availability, proximity and capacity of these gathering and processing facilities, pipeline systems, trucking and railway lines. The lack of availability of capacity in any of the gathering and processing facilities, pipeline systems, trucking and railway lines could result in the Company’s inability to realize the full economic potential of its production or in a reduction of the price offered for the Company’s production. The lack of firm pipeline capacity continues to affect the oil and natural gas industry and limit the ability to transport produced oil and gas to market. In addition, the pro-rationing of capacity on inter-provincial pipeline systems continues to affect the ability to export oil and natural gas. Unexpected shutdowns or curtailment of the capacity of pipelines for maintenance or integrity work or because of actions taken by regulators could also affect the Company’s production, operations and financial results.

 

A portion of the Company’s production may, from time to time, be processed through facilities owned by third parties and over which the Company does not have control. From time to time, these facilities may discontinue or decrease operations as a result of normal servicing requirements or unexpected events. A discontinuation or decrease of operations could have a material adverse effect on the Company’s ability to process its production and deliver the same to market. Midstream and pipeline companies may take actions to maximize their return on investment, which may in turn adversely affect producers and shippers, especially when combined with a regulatory framework that may not always align with the interests of particular shippers.

 

 

The Company competes with other oil and natural gas companies, many of which have greater financial and operational resources.

 

The Canadian and international petroleum industry is highly competitive in all aspects, including the exploration for, and the development of, new sources of supply, the acquisition of oil production leases and the distribution and marketing of petroleum products. the Company competes with producers of bitumen, synthetic crude oil blends and conventional crude oil. Some of the conventional producers have lower operating costs than the Company, and many of them have greater resources to source, attract and retain the personnel, materials and services that the Company requires to conduct its operations. Other producers may also have substantially greater financial resources, staff and facilities than the Company. Some of these companies not only explore for, develop and produce oil and natural gas, but also carry on refining operations and market oil and natural gas on an international basis. As a result of these complementary activities, some of these competitors may have greater and more diverse competitive resources to draw on than the Company. The Company’s ability to increase its reserves in the future will depend not only on its ability to explore and develop its present properties, but also on its ability to select and acquire other suitable producing properties or prospects for exploratory drilling.

 

The petroleum industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies that may increase the viability of reserves or reduce production costs. Other companies may have greater financial, technical and personnel resources that allow them to implement and benefit from such technological advantages. The Company may not be able to respond to such competitive pressures and implement such technologies on a timely basis, or at an acceptable cost. If the Company does implement such technologies, it may not do so successfully. One or more of the technologies currently used by the Company or implemented in the future may become obsolete. If the Company is unable to use the most advanced commercially available technology, or is unsuccessful in implementing certain technologies, its business, financial condition and results of operations could also be adversely affected in a material way.

 

The Company also faces competition from companies that supply alternative resources of energy, such as wind and solar power.

 

Other factors that could affect competition in the marketplace include additional discoveries of hydrocarbon reserves by the Company’s competitors, changes in the cost of production, political and economic factors and other factors outside Greenfire’s control.

 

Changes to the demand for oil and natural gas products and the rise of petroleum alternatives may negatively affect the Company’s financial condition, results of operations and cash flow.

 

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas and technological advances in fuel economy and renewable energy generation systems could reduce the demand for oil, natural gas and liquid hydrocarbons. Recently, certain jurisdictions have implemented policies or incentives to decrease the use of hydrocarbons and encourage the use of renewable fuel alternatives, which may lessen the demand for petroleum products and result in downward pressure on commodity prices. Advancements in energy-efficient products have a similar effect on the demand for oil and natural gas products. The Company cannot predict the impact of changing demand for oil and natural gas products, and any major changes may have a material adverse effect on the Company’s business, financial condition, results of operations and cash flow by decreasing the Company’s profitability, increasing its costs, limiting its access to capital and decreasing the value of its assets.

 

Modification to current, or implementation of additional, regulations may reduce the demand for oil and natural gas and/or increase the Company’s costs and/or delay planned operations.

 

The oil and gas industry in Canada is a regulated industry. Various levels of government impose extensive controls and regulations on oil sands and other oil and natural gas operations (including exploration, development, production, pricing, marketing and transportation). Governments may regulate or intervene with respect to exploration and production activities, prices, taxes, royalties and the exportation of bitumen, oil and natural gas. Amendments to these controls and regulations may occur from time to time in response to economic or political conditions. The implementation of new regulations or the modification of existing regulations affecting the oil sands and the oil and natural gas industry could generally reduce demand for bitumen, oil and natural gas and increase the Company’s costs, either of which may have a material adverse effect on the Company’s business, financial condition, results of operations and prospects. Further, the ongoing third-party challenges to regulatory decisions or orders have reduced the efficiency of the regulatory regime, as the implementation of the decisions and orders has been delayed, resulting in uncertainty and interruption to the business of the oil sands and the oil and natural gas industry.

 

To conduct its operations, the Company will require regulatory permits, licenses, registrations, approvals and authorizations from various governmental authorities at the municipal, provincial and federal levels. The Company may not be able to obtain all permits, licenses, registrations, approvals and authorizations that may be required to conduct operations that it may wish to undertake. In addition, certain federal legislation such as the Competition Act (Canada) and the Investment Canada Act could negatively affect the Company’s business, financial condition and the market value of its securities or its assets, particularly when undertaking, or attempting to undertake, acquisition or disposition activity.

 

 

There has also been increased activism relating to climate change and public opposition to fossil fuels. The federal government and certain provincial governments in Canada have responded to these shifting societal attitudes by adopting ambitious emissions reduction targets and supporting legislation, including measures relating to carbon pricing, clean energy, field and emission standards, and alternative energy incentives and mandates. See “Climate change concerns could result in increased operating expenses and reduced demand for the Company’s products and securities, while the potential physical effects of climate change could disrupt the Company’s production and cause it to incur significant costs in preparing for or responding to those effects” and “Compliance with environmental regulations requires the dedication of a portion of the Company’s financial and operational resources” for additional information. Concerns over climate change, fossil fuel extraction, greenhouse gas (“GHG”) emissions, and water and land-use practices could lead governments to enact additional or more stringent laws and regulations applicable to the Company and other companies in the energy industry in general.

 

Changes to royalty regimes could adversely affect the profitability of the Company’s operations.

 

The Province of Alberta receives royalties on the production of natural resources from lands in which it owns the mineral rights that are linked to price and production levels and that apply to both new and existing thermal oil production projects. There can be no assurances that the Government of Alberta will not adopt new royalty regimes or alter existing royalty regimes, which may render the Company’s projects uneconomical or otherwise adversely affect its results of operations, financial condition or prospects.

 

A failure to secure the services and equipment necessary to the Company’s operations for the expected price, on the expected timeline, or at all, may have an adverse effect on the Company’s financial performance and cash flows.

 

The Company’s operating costs could escalate and become uncompetitive due to supply chain disruptions, inflationary cost pressures, equipment limitations, escalating supply costs, commodity prices, and additional government intervention through stimulus spending or additional regulations. The Company’s inability to manage costs may impact project returns and future development decisions, which could have a material adverse effect on its financial performance and cash flows.

 

The cost or availability of oil and gas field equipment may adversely affect the Company’s ability to undertake exploration, development and construction projects. The oil and gas industry is cyclical in nature and is prone to shortages of supply of equipment and services including drilling rigs, geological and geophysical services, engineering and construction services, major equipment items for infrastructure projects and construction materials generally. These materials and services may not be available when required at reasonable prices. A failure to secure the services and equipment necessary for the Company’s operations for the expected price, on the expected timeline, or at all, may have an adverse effect on the Company’s financial performance and cash flows.

 

Oil and natural gas operations are subject to seasonal weather conditions, and the Company may experience significant operational delays or costs as a result.

 

The level of activity in the Canadian oil and natural gas industry is influenced by seasonal weather patterns. Wet weather and spring thaw may make the ground unstable. Consequently, municipalities and provincial transportation departments enforce road bans that restrict the movement of rigs and other heavy equipment, thereby reducing activity levels. Certain oil and natural gas producing areas are located in areas that are inaccessible other than during the winter months because the ground surrounding the sites in these areas consists of swampy terrain. Extreme cold weather, heavy snowfall and heavy rainfall may restrict the Company’s ability to access its properties and cause operational difficulties. In addition, low temperatures increase the viscosity of diluent and bitumen. With higher viscosities, more diluent is required to blend bitumen for pipeline transportation, and bitumen becomes thicker and more difficult to transport by truck, in each case, resulting in increased operating costs. Higher than normal temperatures can negatively affect the operation of equipment used for processing and cooling of product and for inputs, such as natural gas delivery from third parties. Seasonal factors and unexpected weather patterns may lead to declines in exploration and production activity and increased operating costs, which may have an adverse effect on the Company’s business, financial condition and results of operations.

 

The Company’s access to capital may be limited or restricted as a result of factors related and unrelated to it, impacting its ability to conduct future operations and acquire and develop reserves.

 

The Company anticipates making substantial capital expenditures for the acquisition, exploration, development and production of bitumen, oil and natural gas reserves in the future. As future capital expenditures will be financed out of cash generated from operations, borrowings and possible future equity sales, the Company’s ability to do so is dependent on, among other factors:

 

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the overall state of the capital markets;

 

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the Company’s credit rating (if applicable);

 

 

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commodity prices;

 

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production rates;

 

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interest rates;

 

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royalty rates;

 

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tax burden due to currently applicable tax laws and potential changes in tax laws; and

 

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investor appetite for investment in the energy industry and the Common Shares in particular.

 

Further, if the Company’s revenues or reserves decline, it may not have access to the capital necessary to undertake or complete future drilling programs. The current conditions in the oil and gas industry have negatively impacted the ability of oil and gas companies to access financing. Debt or equity financing or cash generated by operations may not be available or sufficient to meet these requirements or for other corporate purposes or, if debt or equity financing is available, it may not be on terms acceptable to the Company. The Company may be required to seek additional equity financing on terms that are highly dilutive to existing securityholders. The inability of the Company to access sufficient capital for its operations could have a material adverse effect on the Company’s business, financial condition, results of operations and prospects.

 

Changes to applicable tax laws or government incentive programs may affect the Company’s operations, financial condition or prospects.

 

Income tax laws or government incentive programs relating to the oil and gas industry and in particular, the oil sands sector, may in the future be changed or interpreted in a manner that adversely affects the Company’s result of operations, financial condition or prospects. In addition, corporate tax pools may be adjusted due to changes with respect to changes of tax law interpretation or audit.

 

The Company may require additional financing, from time to time, to fund the acquisition, exploration and development of properties, and its ability to obtain such financing in a timely fashion and on acceptable terms may be negatively impacted by the current economic and global market volatility.

 

The Company’s cash flow from operations may not be sufficient to fund its ongoing activities at all times and, from time to time, the Company may require additional financing in order to carry out its acquisition, exploration and development activities. Failure to obtain financing on a timely basis could cause the Company to forfeit its interest in certain properties, miss certain acquisition opportunities and reduce its operations. Due to the conditions in the oil and natural gas industry and/or global economic and political volatility, the Company may, from time to time, have restricted access to capital and increased borrowing costs. The current conditions in the oil and natural gas industry have negatively impacted the ability of oil and natural gas companies to access, or the cost of, additional financing.

 

As a result of global economic and political conditions and the domestic lending landscape, the Company may, from time to time, have restricted access to capital and increased borrowing costs. If the Company’s cash flow from operations decreases as a result of lower commodity prices or otherwise, it will affect the Company’s ability to expend the necessary capital to replace its reserves or to maintain its production. To the extent that external sources of capital become limited, unavailable or available on onerous terms, the Company’s ability to make capital investments and maintain existing assets may be impaired, and its assets, liabilities, business, financial condition and results of operations may be affected materially and adversely. In addition, the future development of the Company’s properties may require additional financing, and such financing may not be available or, if available, may not be available upon acceptable terms. Alternatively, any available financing may be highly dilutive to existing securityholders. Failure to obtain any financing necessary for the Company’s capital expenditure plans may result in a delay in development or production on the Company’s properties.

 

Defects in the title or rights to produce the Company’s properties may result in a financial loss.

 

The Company’s actual title to and interest in its properties, and its right to produce and sell the products therefrom, may vary from the Company’s records. In addition, there may be valid legal challenges or legislative changes, or prior unregistered agreements, interests or claims of which the Company is currently unaware, that affect the Company’s title to and right to produce petroleum from its properties, which could impair the Company’s activities and result in a reduction of the revenue received by the Company.

 

If a defect exists in the chain of title or in the Company’s right to produce, or a legal challenge or legislative change arises, it is possible that the Company may lose all, or a portion of, the properties to which the title defect relates and/or its right to produce from such properties. This may have a material adverse effect on the Company’s business, financial condition, results of operations and prospects.

 

The Company may be required to surrender lands to the Province of Alberta if annual lease payments are not made.

 

The Company has two project regions in the Athabasca region of Alberta consisting of oil sands leases, either acquired from the Government of Alberta or from third parties. All of the Company’s leases require annual lease payments to the Alberta provincial government. If the Company does not maintain the annual lease payments, it will lose its ability to explore and develop the properties, and the Company will not retain any kind of interest in the properties.

 

 

Risk management activities expose the Company to the risk of financial loss and counter-party risk.

 

The Company has and continues to use physical and financial instruments to hedge a portion of its exposure to fluctuations in commodity prices (potentially including, but not limited to, hedging the index price that approximates the Company’s realized price for its bitumen and benchmark pricing that approximates the price the Company pays for diluent, natural gas and power) and may also use such instruments in respect of exchange and interest rates. If bitumen, diluent, natural gas, power prices, exchange or interest rates increase above or decrease below levels contracted for in any hedging agreements, such hedging arrangements may prevent the Company from realizing the full benefit of such increases or decreases. In addition, the Company’s risk management arrangements may expose it to the risk of financial loss or otherwise have a negative impact on the Company’s results of operations or prospects in certain circumstances, including instances in which:

 

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production falls short of the contracted volumes or prices fall significantly lower than projected;

 

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there is a widening of price-basis differentials between delivery points for production and the delivery point assumed in the arrangement;

 

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the Company is required to pay a margin call on a derivative instrument based on a market or reference price that is higher than the hedged price;

 

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counterparties to the arrangements or other price risk management contracts become insolvent or otherwise fail to perform under those arrangements; or

 

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a sudden or unexpected event materially impacts market prices for bitumen, diluent, natural gas, power or exchange or interest rates.

 

It is an obligation under the indenture governing the 2028 Notes to execute a continuously rolling 12-month commodity price hedging program for at least 50% of its proved developed producing reserve forecast, subject to adjustment in certain circumstances, from its most recent reserve report, which is completed by an independent reserve evaluator. Although the Company has been successful in executing its hedging strategy to meet this obligation in the past, there can be no guarantee that it will continue to be successful in meeting this obligation in the future. Should the Company fail to meet its obligations under the indenture, an event of default may occur and negatively impact the Company’s financial and operating performance.

 

Not all risks of conducting oil and natural gas opportunities are insurable and the occurrence of an uninsurable event may have a material adverse effect on the Company.

 

The operation of the Company’s SAGD production properties and projects have experienced and will continue to be subject to the customary hazards of recovering, transporting and processing hydrocarbons, such as fires, explosions, gaseous leaks, migration of harmful substances, equipment failures, blowouts, spills and other accidents.

 

In addition, the geological characteristics and integrity of the bitumen reservoirs are inherently uncertain. The injection of steam into reservoirs under significant pressure may result in unforeseen damage to reservoirs that could result in steam blowouts or oil or gaseous leaks. A casualty occurrence might result in the loss of equipment or life, as well as injury, environmental or property damage or the interruption of the Company’s operations.

 

Although the Company maintains insurance in accordance with industry standards to address certain of these risks, such insurance has limitations on liability and may not be sufficient to cover the full extent of such liabilities. In addition, certain risks are not, in all circumstances, insurable or, in certain circumstances, the Company may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or other reasons. The payment of any uninsured liabilities would reduce the funds available to the Company. The occurrence of a significant event that the Company is not fully insured against, or the insolvency of the insurer of such event, may have a material adverse effect on the Company’s business, financial condition, results of operations and prospects.

 

The Company’s insurance policies are generally renewed on an annual basis and, depending on factors such as market conditions, the premiums, policy limits and/or deductibles for certain insurance policies can vary substantially. In some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. Significantly increased costs could lead the Company to decide to reduce or possibly eliminate coverage. In addition, insurance is purchased from a number of third-party insurers, often in layered insurance arrangements, some of whom may discontinue providing insurance coverage for their own policy or strategic reasons. Should any of these insurers refuse to continue to provide insurance coverage, the Company’s overall risk exposure could be increased and the Company could incur significant costs.

 

 

The Company relies on its reputation to continue its operations and to attract and retain investors and employees.

 

Oil sands development receives significant political, media and activist commentary regarding GHG emissions, pipeline transportation, water usage, harm to First Nations communities and potential for environmental damage. Public concerns regarding such issues may directly or indirectly harm the Company’s operations and profitability in a number of ways, including by: (i) creating significant regulatory uncertainty that could challenge the economic modelling of future development; (ii) motivating extraordinary environmental regulation by governmental authorities that could result in changes to facility design and operating requirements, thereby increasing the cost of construction, operation and abandonment; (iii) imposing restrictions on production from oil sands operations that could reduce the amount of bitumen, crude oil and natural gas that the Company is ultimately able to produce from its reserves; and (iv) resulting in proposed pipelines not being able to receive the necessary permits and approvals, which, in turn, may limit the market for the Company’s crude oil and natural gas and reduce its price. Concerns over these issues may also harm the Company’s corporate reputation and limit its ability to access land and joint venture opportunities.

 

The Company’s business, operations or financial condition may be negatively impacted as a result of any negative public opinion towards the Company or as a result of any negative sentiment toward, or in respect of, the Company’s reputation with stakeholders, special interest groups, political leadership, the media or other entities. Public opinion may be influenced by certain media and special interest groups’ negative portrayal of the industry in which the Company operates as well as their opposition to certain oil sands and other oil and natural gas projects. Potential impacts of negative public opinion or reputational issues may include delays or interruptions in operations, legal or regulatory actions or challenges, blockades, increased regulatory oversight, reduced support for, delays in, challenges to, or the revocation of regulatory approvals, permits and/or licenses and increased costs and/or cost overruns. The Company’s reputation and public opinion could also be impacted by the actions and activities of other companies operating in the oil and natural gas industry, particularly other producers, over which the Company has no control. Similarly, the Company’s reputation could be impacted by negative publicity related to loss of life, injury or damage to property and environmental damage caused by the Company’s operations. In addition, if the Company develops a reputation of having an unsafe work site, it may impact the ability of the Company to attract and retain the necessary skilled employees and consultants to operate its business. Opposition from special interest groups opposed to oil and natural gas development and the possibility of climate-related litigation against governments and hydrocarbon companies may impact the Company’s reputation.

 

Reputational risk cannot be managed in isolation from other forms of risk. Credit, market, operational, insurance, regulatory and legal risks, among others, must all be managed effectively to safeguard the Company’s reputation. Damage to the Company’s reputation could result in negative investor sentiment towards the Company, which may result in limiting the Company’s access to capital, increasing the cost of capital, and decreasing the price and liquidity of the Common Shares.

 

Opposition by First Nations groups to the conduct of the Company’s operations, development or exploratory activities may negatively impact the Company.

 

Opposition by First Nations groups to the conduct of the Company’s operations, development or exploratory activities may negatively impact it in terms of public perception, diversion of management’s time and resources, and legal and other advisory expenses, and could adversely impact the Company’s progress and ability to explore and develop properties.

 

Some First Nations groups have established or asserted treaty, Aboriginal title and Aboriginal rights to a substantial portion of Western Canada. Certain First Nations peoples have filed a claim against the Government of Canada, the Province of Alberta, certain Governmental Entities and the Regional Municipality of Wood Buffalo (which includes the City of Fort McMurray, Alberta) claiming, among other things, Aboriginal title to large areas of lands surrounding Fort McMurray, including lands on which the Company’s assets are located. Such claims, and other similar claims that may be initiated, if successful, could have a material adverse effect on the Company’s assets.

 

The Canadian federal and provincial governments have a duty to consult with First Nations people when contemplating actions that may adversely affect the asserted or proven Aboriginal or treaty rights and, in certain circumstances, accommodate their concerns. The scope of the duty to consult by federal and provincial governments varies with the circumstances and is often the subject of ongoing litigation. The fulfillment of the duty to consult First Nations people and any associated accommodations may adversely affect the Company’s ability to, or increase the timeline to, obtain or renew, permits, leases, licenses and other approvals, or to meet the terms and conditions of those approvals.

 

In addition, the Canadian federal government has introduced legislation to implement the United Nations Declaration on the Rights of Indigenous Peoples (“UNDRIP”). Other Canadian jurisdictions have also introduced or passed similar legislation, or begun considering the principles and objectives of UNDRIP, or may do so in the future. The means and timelines associated with UNDRIP’s implementation by the government are uncertain; additional processes may be created, or legislation amended or introduced associated with project development and operations, further increasing uncertainty with respect to project regulatory approval timelines and requirements.

 

An inability to recruit and retain a skilled workforce and key personnel may negatively impact the Company.

 

The operations and management of the Company require the recruitment and retention of a skilled workforce, including engineers, technical personnel and other professionals. The loss of key members of such workforce, or a substantial portion of the workforce as a whole, could result in the failure to implement the Company’s business plans which could have a material adverse effect on the Company’s business, financial condition, results of operations and prospects.

 

 

The labor force in Alberta, and in the surrounding area, is limited and there can be no assurance that all the required employees with the necessary expertise will be available. Competition for qualified personnel in the oil and natural gas industry is high and the Company may not be able to continue to attract and retain all personnel necessary for the development and operation of its business. The Company does not have any key personnel insurance in effect. Contributions of the existing management team to the immediate and near-term operations of the Company are likely to be of central importance. In addition, certain of the Company’s current employees may have significant institutional knowledge that must be transferred to other employees prior to their departure from the workforce. If the Company is unable to: (i) retain current employees; (ii) successfully complete effective knowledge transfers; and/or (iii) recruit new employees with the requisite knowledge and experience, the Company could be negatively impacted. In addition, the Company could experience increased costs to retain and recruit these professionals.

 

Restrictions on operational activities intended to protect certain species of wildlife may adversely affect the Company’s ability to conduct drilling and other operational activities in some of the areas where it operates.

 

Operations in the Company’s operating areas can be adversely affected by seasonal or permanent restrictions on construction, drilling and well completions activities designed to protect various wildlife. Seasonal restrictions may limit the Company’s ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling and completion activities are allowed. These constraints and the resulting shortages or high costs could delay the Company’s operations and materially increase the Company’s operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit development in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species as threatened or endangered in areas where the Company operates could cause the Company to incur increased costs arising from species protection measures or could result in limitations on the Company’s exploration and production activities that could have an adverse impact on the Company’s ability to develop and produce its reserves.

 

Risks Related to Climate Change and Related Regulation

 

Compliance with environmental regulations requires the dedication of a portion of the Company’s financial and operational resources.

 

Compliance with environmental legislation may require significant expenditures, some of which may be material. Environmental compliance requirements may result in a curtailment of production or a material increase in the costs of production, development or exploration activities or otherwise have a material adverse effect on the Company’s business, financial condition, results of operations and prospects.

 

The direct and indirect costs of the various GHG regulations, current and emerging in both Canada and the United States, including any limits on oil sands emissions through the Canadian federal government’s implementation of the Paris Agreement through the Greenhouse Gas Pollution Pricing Act, the Clean Fuel Standard, the Alberta Technology Innovation and Emissions Reduction Regulation and any other federal or provincial carbon emission pricing system, may adversely affect the Company’s business, operations and financial results.

 

Environmental regulation of GHG emissions in the United States could result in increased costs and/or reduced revenue for oil sands companies such as the Company. At the federal level, the U.S. Environmental Protection Agency (the “EPA”) is currently responsible for regulating GHG emissions, pursuant to the Clean Air Act. The EPA has issued regulations restricting GHG emissions from automobiles and trucks, and administers the Renewable Fuel Standard, which requires specified “renewable fuels” to be blended into U.S. transportation fuel, with increasing volumes coming from lower GHG-emitting fuels over time. While the future regulatory environment in the United States is uncertain, it is possible that fuel suppliers’ GHG emissions will eventually be regulated in the United States. The Company’s operations may be impacted by such regulation, which could impose increased costs on direct and indirect users of the Company’s products, which could result in reduced demand therefore.

 

Climate change concerns could result in increased operating costs and reduced demand for the Company’s products and securities, while the potential physical effects of climate change could disrupt the Company’s production and cause it to incur significant costs in preparing for or responding to those effects.

 

Global climate issues continue to attract public and scientific attention. Numerous reports, including reports from the Intergovernmental Panel on Climate Change, have engendered concern about the impacts of human activity, especially hydrocarbon combustion, on the global climate. In turn, increasing public, government, and investor attention is being paid to global climate issues and to emissions of GHGs, including emissions of carbon dioxide and methane from the production and use of bitumen, oil, liquids and natural gas. Most countries across the globe, including Canada, have agreed to reduce their carbon emissions in accordance with the Paris Agreement. In addition, during the 2021 United Nations Climate Change Conference in Glasgow, Scotland, Canada’s Prime Minister, Justin Trudeau, made several pledges aimed at reducing Canada’s GHG emissions and environmental impact. Greenfire faces both transition risks and physical risks associated with climate change policy and regulations.

 

 

Foreign and domestic governments continue to evaluate and implement policy, legislation, and regulations focused on restricting GHG emissions and promoting adaptation to climate change and the transition to a low-carbon economy. It is not possible to predict what measures foreign and domestic governments may implement in this regard, nor is it possible to predict the requirements that such measures may impose or when such measures may be implemented. However, international multilateral agreements, the obligations adopted thereunder and legal challenges concerning the adequacy of climate-related policy brought against foreign and domestic governments may accelerate the implementation of these measures. Given the evolving nature of climate change policy and the control of GHG emissions and resulting requirements, including carbon taxes and carbon pricing schemes implemented by varying levels of government, it is expected that current and future climate change regulations will have the effect of increasing the Company’s operating costs, and, in the long-term, potentially reducing the demand for oil, liquids, natural gas and related products, resulting in a decrease in the Company’s profitability and a reduction in the value of its assets.

 

Concerns about climate change have resulted in environmental activists and members of the public opposing the continued extraction and development of fossil fuels, which has influenced investors’ willingness to invest in the oil and natural gas industry. Historically, political and legal opposition to the fossil fuel industry focused on public opinion and the regulatory process. More recently, however, there has been a movement to more directly hold governments and oil and natural gas companies responsible for climate change through climate litigation. Claims have been made against certain energy companies alleging that GHG emissions from oil and natural gas operations constitute a public nuisance under certain laws or that such energy companies provided misleading disclosure to the public and investors of current or future risks associated with climate change. As a result, individuals, government authorities, or other organizations may make claims against oil and natural gas companies, including the Company, for alleged personal injury, property damage, or other potential liabilities. While the Company is not currently a party to any such litigation or proceedings, it could be named in actions making similar allegations. An unfavorable ruling in any such case could reduce the demand for the Company’s products and price of securities, impact its operations and have an adverse impact on its financial condition.

 

Given the perceived elevated long-term risks associated with policy development, regulatory changes, public and private legal challenges, or other market developments related to climate change, there have also been efforts in recent years affecting the investment community, including investment advisors, sovereign wealth funds, banks, public pension funds, universities and other institutional investors, promoting direct engagement and dialogue with companies in their portfolios on climate change action (including exercising their voting rights on matters relating to climate change) and increased capital allocation to investments in low-carbon assets and businesses while decreasing the carbon intensity of their portfolios through, among other measures, divestments of companies with high exposure to GHG-intensive operations and products. Certain stakeholders have also pressured insurance providers and commercial and investment banks to reduce or stop financing and providing insurance coverage to oil and natural gas and related infrastructure businesses and projects. The impact of such efforts requires the Company’s management to dedicate significant time and resources to these climate change-related concerns and may adversely affect the Company’s operations, the demand for and price of the Common Shares and products and may negatively impact the Company’s cost of capital and access to the capital markets.

 

Emissions, carbon and other regulations impacting climate and climate-related matters are constantly evolving. With respect to ESG and climate reporting, the International Sustainability Standards Board has issued an IFRS Sustainability Disclosure Standard with the aim to develop sustainability disclosure standards that are globally consistent, comparable and reliable. If the Company is not able to meet future sustainability reporting requirements of regulators or current and future expectations of investors, insurance providers, or other stakeholders, its business and ability to attract and retain skilled employees, obtain regulatory permits, licenses, registrations, approvals, and authorizations from various governmental authorities, and raise capital may be adversely affected.

 

The direct and indirect costs of various GHG regulations, existing and proposed, may adversely affect the Company’s business, operations and financial results, including demand for the Company’s products.

 

The Company’s exploration and production facilities and other operations and activities emit GHGs, which require the Company to comply with federal and/or provincial GHG emissions legislation in Canada. Climate change policy is evolving at regional, national and international levels, and political and economic events may significantly affect the scope and timing of climate change measures that are ultimately put in place to prevent climate change or mitigate its effects. The direct or indirect costs of compliance with GHG-related regulations may have a material adverse effect on the Company’s business, financial condition, results of operations and prospects. The Company’s facilities may ultimately be subject to future regional, provincial and/or federal climate change regulations to manage GHG emissions.

 

Further, while reporting on most ESG information is currently voluntary, in March 2022, the SEC issued a proposed rule that would require public companies to disclose certain climate-related information, including climate-related risks, impacts, oversight and management, financial statement metrics and emissions, targets, goals and plans. While the proposed rule is not yet effective and is expected to be subject to a lengthy comment process, compliance with the proposed rule as drafted could result in increased legal, accounting and financial compliance costs, make some activities more difficult, time-consuming and costly, and place strain on our personnel, systems and resources.

 

Although it is not possible at this time to predict how new laws or regulations in the United States and Canada would impact the Company’s business, any such future laws, regulations or legal requirements imposing reporting or permitting obligations on, or limiting emissions of GHGs from, the Company’s equipment and operations could require the Company to incur costs to reduce emissions of GHGs associated with its operations or to purchase emission credits or offsets as well as delays or restrictions in its ability to permit GHG emissions from new or modified sources. The direct or indirect costs of compliance with these regulations may have a material adverse effect on the business, financial condition, results of operations and prospects of the Company. Any such regulations could also increase the cost of consumption, and thereby reduce demand for the bitumen the Company produces. Given the evolving nature of the discourse related to climate change and the control of GHGs and resulting regulatory requirements, it is not possible to predict with certainty the impact on the Company and its operations and financial condition.

 

 

The Company faces physical risks associated with climate change.

 

Based on the Company’s current understanding, the potential physical risks resulting from climate change are long-term in nature and the timing, scope, and severity of potential impacts are uncertain. Many experts believe global climate change could increase extreme variability in weather patterns, such as increased frequency of severe weather, rising mean temperature and sea levels and long-term changes in precipitation patterns. Extreme hot and cold weather, heavy snowfall, heavy rainfall and wildfires may restrict the Company’s ability to access its properties and cause operational difficulties, including damage to equipment and infrastructure. Extreme weather also increases the risk of personnel injury as a result of dangerous working conditions. Recent wildfires in Western Canada caused electrical instability of third-party owned infrastructure that resulted in unplanned downtime and contributed to lower production volumes at our facilities. Certain of the Company’s assets are located in locations that are near forests and rivers and a flood or another wildfire may lead to additional and significant downtime and/or damage to the Company’s assets or cause disruptions to the production and transport of its products or the delivery of goods and services in its supply chain, any of which may negatively impact our results of operations and financial condition.

 

Risks Related to Political and other Legal Matters and Regulations

 

The Company’s business may be adversely affected by political and social events and decisions made in Canada.

 

The Company’s results can be adversely impacted by political, legal, or regulatory developments in Canada that affect local operations and local and international markets. Changes in government, government policy or regulations, changes in law or interpretation of settled law, third-party opposition to industrial activity generally or projects specifically, and duration of regulatory reviews could impact the Company’s existing operations and planned projects. This includes actions by regulators or political actors to delay or deny necessary licenses and permits for the Company’s activities or restrict the operation of third-party infrastructure that the Company relies on. Additionally, changes in environmental regulations, assessment processes or other laws, and increasing and expanding stakeholder consultation (including First Nations stakeholders), may increase the cost of compliance or reduce or delay available business opportunities and adversely impact the Company’s results.

 

Other government and political factors that could adversely affect the Company’s financial results include increases in taxes or government royalty rates (including retroactive claims) and changes in trade policies and agreements. Further, the adoption of regulations mandating efficiency standards, and the use of alternative fuels or uncompetitive fuel components could affect the Company’s operations. Many governments are providing tax advantages and other subsidies to support alternative energy sources or are mandating the use of specific fuels or technologies. Governments and others are also promoting research into new technologies to reduce the cost and increase the scalability of alternative energy sources, and the success of these initiatives may decrease demand for the Company’s products.

 

A change in federal, provincial or municipal governments in Canada may have an impact on the directions taken by such governments on matters that may impact the oil and natural gas industry, including the balance between economic development and environmental policy. The oil and natural gas industry has become an increasingly politically polarizing topic in Canada, which has resulted in a rise in civil disobedience surrounding oil and natural gas development — particularly with respect to infrastructure projects. Protests, blockades and demonstrations have the potential to delay and disrupt the Company’s activities.

 

The handling of secure information for destruction exposes the Company to potential data security risks that could result in monetary damages against the Company and could otherwise damage its reputation, and adversely affect its business, financial condition and results of operations.

 

The protection of customer, employee, and company data is critical to the Company’s business. The regulatory environment in Canada surrounding information security and privacy is increasingly demanding, with the frequent imposition of new and constantly changing requirements. Certain legislation, including the Personal Information Protection and Electronic Documents Act in Canada, require documents to be securely destroyed to avoid identity theft and inadvertent disclosure of confidential and sensitive information. A significant breach of customer, employee, or company data could attract a substantial amount of media attention, damage the Company’s customer relationships and reputation, and result in lost sales, fines, or lawsuits. In addition, an increasing number of countries have introduced and/or increased enforcement of comprehensive privacy laws or are expected to do so. The continued emphasis on information security as well as increasing concerns about government surveillance may lead customers to request the Company to take additional measures to enhance security and/or assume higher liability under its contracts. As a result of legislative initiatives and customer demands, the Company may have to modify its operations to further improve data security. Any such modifications may result in increased expenses and operational complexity, and adversely affect its reputation, business, financial condition and results of operations.

 

 

Failure to comply with anti-corruption, economic sanctions, and anti-money laundering laws — including the U.S. Foreign Corrupt Practices Act of 1977, as amended, the UK Bribery Act 2010, the Canadian Corruption of Foreign Public Officials Act, Criminal Code, Special Economic Measures Act, Justice for Victims of Corrupt Foreign Officials Act, United Nations Act and Freezing Assets of Corrupt Foreign Officials Act, and similar laws associated with activities outside the United States or Canada — could subject the Company to penalties and other adverse consequences.

 

The Company is subject to governmental export and import control laws and regulations, as well as laws and regulations relating to foreign ownership and economic sanctions. The Company’s failure to comply with these laws and regulations and other anti-corruption laws that prohibit companies, their officers, directors, employees and third-party intermediaries from directly or indirectly promising, authorizing, offering, or providing improper payments or benefits to any person or entity, including any government officials, political parties, and private-sector recipients, for the purpose of obtaining or retaining business, directing business to any person, or securing any advantage could have an adverse effect on the Company’s business, prospects, financial condition and results of operations. Changes to trade policy, economic sanctions, tariffs, and import/export regulations may have a material adverse effect on the Company’s business, financial condition and results of operations. The Company will likely be subject to, and will be required to remain in compliance with, numerous laws and governmental regulations concerning the production, use, and distribution of its products and services. Potential future customers may also require that Greenfire complies with their own unique requirements relating to these matters, including provision of data and related assurance for ESG-related standards or goals. Existing and future environmental, health and safety laws and regulations could result in increased compliance costs or additional operating costs or construction costs and restrictions. Failure to comply with such laws and regulations may result in internal and/or government investigations, substantial fines, or other limitations that may adversely impact the Company’s financial results or results of operation. The Company’s business may also be adversely affected by changes in the regulation of the global energy industry.

 

Foreign markets may impose import restrictions and penalties on high carbon fuels which may impact the price the Company receives for its products.

 

Some foreign jurisdictions, including the State of California, have attempted to introduce carbon fuel standards that require a reduction in life cycle GHG emissions from vehicle fuels. Some standards propose a system to calculate the life cycle of GHG emissions of fuels to permit the identification and use of lower-emitting fuels. Any foreign import restrictions or financial penalties imposed on the use of bitumen or bitumen blend products may restrict the markets in which the Company may sell its bitumen and bitumen blend products and/or result in the Company receiving a lower price for such products.

 

Failure to comply with laws relating to labor and employment could subject the Company to penalties and other adverse consequences.

 

The Company is subject to various employment-related laws in the jurisdictions in which its employees are based. It faces risks if it fails to comply with applicable Canadian federal or provincial wage law or applicable Canadian federal or provincial labor and employment laws, or wage, labor or employment laws applicable to any employees outside of Canada. Any violation of applicable wage laws or other labor or employment-related laws could result in complaints by current or former employees, adverse media coverage, investigations, and damages or penalties which could have a material adverse effect on the Company’s reputation, business, operating results, and prospects. In addition, responding to any such proceeding may result in a significant diversion of management’s attention and resources, significant defense costs, and other professional fees.

 

Risks Relating to the Company’s Technology, Intellectual Property and Infrastructure

 

Unauthorized use of intellectual property may cause the Company to engage in, or be the subject of, litigation.

 

Due to the rapid development of oil and natural gas technology, including with respect to recovering in situ oil sands resources, in the normal course of the Company’s operations, the Company may become involved in, named as a party to, or be the subject of, various legal proceedings in which it is alleged that the Company has infringed, misappropriated or otherwise violated the intellectual property or proprietary rights of others. The Company may also initiate similar claims against third parties if it believes that such parties are infringing, misappropriating or otherwise violating its intellectual property or proprietary rights. The Company’s involvement in any intellectual property litigation or legal proceedings could (i) result in significant expense, (ii) adversely affect the development of its assets or intellectual property, or (iii) otherwise divert the efforts of its technical and management personnel, whether or not such litigation or proceedings are resolved in the Company’s favor. In the event of an adverse outcome in any such litigation or proceeding, the Company may, among other things, be required to:

 

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pay substantial damages and/or cease the development, use, sale or importation of processes that infringe or violate upon the intellectual property rights of a third party;

 

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expend significant resources to develop or acquire the non-infringing intellectual property;

 

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discontinue processes incorporating the infringing technology; or

 

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obtain licenses to the non-infringing intellectual property.

 

However, the Company may not be successful in such development or acquisition of the applicable non-infringing intellectual property, or such licenses may not be available on reasonable terms. In the event of a successful claim of infringement, misappropriation or violation of third-party intellectual property rights against the Company and its failure or inability to obtain a license to continue to use such technology on reasonable terms, the Company’s business, prospects, operating results and financial condition could be materially adversely affected.

 

 

Breaches of the Company’s cyber-security and loss of, or unauthorized access to, data may adversely impact the Company’s operations and financial position.

 

The Company is increasingly dependent upon the availability, capacity, reliability and security of the Company’s information technology infrastructure, and the Company’s ability to expand and continually update this infrastructure, to conduct daily operations. the Company depends on various information technology systems to estimate reserve quantities, process and record financial data, manage the Company’s land base, manage financial resources, analyze seismic information, administer contracts with operators and lessees and communicate with employees and third-party partners. The Company currently uses, and may use in the future, outsourced service providers to help provide certain information technology services, and any such service providers may face similar security and system disruption risks. Moreover, following the COVID-19 pandemic, an increased number of the Company’s employees and service providers have been working from home and connecting to its networks remotely on less secure systems, which may further increase the risk of, and vulnerability to, a cyber-security attack or security breach to the Company’s network. In addition, the Company’s ability to monitor its outsourced service providers’ security measures is limited and third parties may be able to circumvent those security measures, resulting in the unauthorized access to, misuse, acquisition, disclosure, loss, alteration, or destruction of the Company’s personal, confidential, or other data, including data relating to individuals.

 

Further, the Company is subject to a variety of information technology and system risks as a part of its operations including potential breakdowns, invasions, viruses, cyber-attacks, cyber-fraud, security breaches, and destruction or interruption of the Company’s information technology systems by third parties or employees. Unauthorized access to these systems by employees or third parties could lead to corruption or exposure of confidential, fiduciary or proprietary information, interruption to communications or operations or disruption to business activities or the Company’s competitive position. In addition, cyber phishing attempts have become more widespread and sophisticated in recent years. If the Company becomes a victim to a cyber phishing attack, it could result in a loss or theft of the Company’s financial resources or critical data and information, or could result in a loss of control of the Company’s technological infrastructure or financial resources. The Company’s employees are often the targets of such cyber phishing attacks by third parties using fraudulent “spoof” emails to misappropriate information or to introduce viruses or other malware through “Trojan horse” programs to the Company’s computers.

 

Increasingly, social media is used as a vehicle to carry out cyber phishing attacks by nefarious actors. Information posted on social media sites, for business or personal purposes, may be used by attackers to gain entry into the Company’s systems and obtain confidential information. There are significant risks that the Company may not be able to properly regulate social media use by its employees and preserve adequate records of business activities and client communications conducted through the use of social media platforms.

 

The Company maintains policies and procedures that address and implement employee protocols with respect to electronic communications and electronic devices and conducts annual cyber-security risk assessments. The Company also employs encryption protection of its confidential information, and all computers and other electronic devices. Despite the Company’s efforts to mitigate such cyber phishing attacks through employee education and training, cyber phishing activities may result in unauthorized access, data theft and damage to its information technology infrastructure. The Company applies technical and process controls in line with industry-accepted standards to protect its information, assets and systems. However, these controls may not adequately prevent cyber-security breaches or attacks. As such, the Company may need to continuously develop, modify, upgrade or enhance its information technology infrastructure and cyber-security measures to secure its business, which can lead to increased cyber-security protection costs. Such costs may include making organizational changes, deploying additional personnel and protection technologies, training employees, and engaging third party experts and consultants. These efforts may come at the potential cost of revenues and human resources that could be used to continue to enhance the Company’s business, and such increased costs and diversion of resources may adversely affect operating margins. Disruption of critical information technology services, or breaches of information security, could have a negative effect on the Company’s performance and earnings, as well as its reputation, and any damages sustained may not be adequately covered by the Company’s current insurance coverage, or at all. The impact of any such cyber-security event could have a material adverse effect on the Company’s business, financial condition and results of operations.

 

The Company is subject to laws, rules, regulations and policies regarding data privacy and security. Many of these laws and regulations are subject to change and reinterpretation, and could result in claims, changes to its business practices, monetary penalties, increased cost of operations or other harm to its business.

 

The Company is subject to certain laws, regulations, standards, and other actual and potential obligations relating to privacy, data hosting and transparency of data, data protection, and data security. Such laws are evolving rapidly, and the Company expects to potentially be subject to new laws and regulations, or new interpretations of laws and regulations, in the future in various jurisdictions. These laws, regulations, and other obligations, and changes in their interpretation, could require the Company to modify its operations and practices, restrict its activities, and increase its costs. Further, these laws, regulations, and other obligations are complex and evolving rapidly, and despite the Company’s reasonable efforts to monitor its potential obligations, the Company may face claims, allegations, or other proceedings related to its obligations under applicable privacy, data protection, or data security laws and regulations. The interpretation and implementation of these laws, regulations, and other obligations are uncertain for the foreseeable future and could be inconsistent with one another, which may complicate and increase the costs for compliance. As a result, the Company anticipates needing to dedicate substantial resources to comply with such laws, regulations, and other obligations relating to privacy and cyber-security. Despite the Company’s reasonable efforts to comply, any failure or alleged or perceived failure to comply with any applicable Laws, regulations, or other obligations relating to privacy, data protection, or data security could also result in regulatory investigations and proceedings, and misuse of or failure to secure data relating to individuals could also result in claims and proceedings against the Company by Governmental Entities or other third parties, penalties, fines and other liabilities, and may potentially damage the Company’s reputation and credibility, which could adversely affect the Company’s business, operating results, financial condition and prospects.

 

 

General Risk Factors Related to the Company

 

The Company is exposed to exchange and interest rate risks.

 

The Company is exposed to exchange rate risks from its U.S dollar-denominated debts. The Company’s revenues are based on the U.S. dollar, since revenue received from the sale of diluted bitumen and non-diluted bitumen is referenced to a price denominated in U.S. dollars, and the Company incurs most of its operating and other costs in Canadian dollars. As a result, the Company is impacted by exchange rate fluctuations between the U.S. dollar and the Canadian dollar, and any strengthening of the Canadian dollar relative to the U.S. dollar could negatively impact the Company’s operating margins and cash flows.

 

From time to time, the Company may enter into agreements to fix the exchange rate of Canadian to U.S. dollars or other currencies to offset the risk of revenue losses if the Canadian dollar increases in value compared to other currencies. However, if the Canadian dollar declines in value compared to such fixed currencies, the Company would not benefit from the fluctuating exchange rate.

 

Default under any of the Company’s debt instruments could result in the Company being required to repay amounts outstanding thereunder.

 

The Company is required to comply with covenants under the 2028 Notes, the Credit Agreement and EDC Facility and in the event it does not comply with these covenants, the Company’s access to capital could be restricted or repayment could be required. Events beyond the Company’s control may contribute to its failure to comply with such covenants. The acceleration of indebtedness under one agreement may permit acceleration of indebtedness under other agreements that contain cross default or cross-acceleration provisions. In addition, the 2028 Notes may impose operating and financial restrictions on the Company that could include restrictions on the payment of dividends, repurchase or making of other distributions with respect to the Common Shares, incurring of additional indebtedness, the provision of guarantees, the assumption of loans, making of capital expenditures, entering into of amalgamations, mergers, takeover bids or dispositions of assets, among others.

 

If repayment of all or a portion of the amounts outstanding under the 2028 Notes, the Credit Agreement or EDC Facility is required for any reason, including for a default of a covenant, there is no certainty that the Company would be in a position to make such repayment. Even if the Company is able to obtain new financing in order to make any required repayment under the 2028 Notes, the Credit Agreement or EDC Facility, it may not be on commercially reasonable terms, or terms that are acceptable to the Company. If the Company is unable to repay amounts owing under the 2028 Notes, the Credit Agreement or EDC Facility, the noteholders or lenders, as applicable under such facility could proceed to foreclose or otherwise realize upon the collateral granted to them to secure the indebtedness.

 

The Company’s substantial indebtedness could adversely affect the Company’s financial health.

 

As of December 31, 2023, the Company had approximately CAD$396.8 million (US$300 million) of debt outstanding, consisting of the principal amount of the 2028 Notes, and CAD$50 million of availability under the facilities pursuant to the Credit Agreement, with no amounts drawn.

 

The Company’s substantial indebtedness could have important consequences for the Company’s securityholders and a significant effect on the Company’s business. For example, it could:

 

●

make it more difficult for the Company to satisfy its financial obligations;

 

●

increase the Company vulnerability to general adverse economic, industry and competitive conditions;

 

●

reduce the availability of the Company’s cash flow to fund working capital, capital expenditures and other general corporate purposes because the Company will be required to dedicate a substantial portion of the Company’s cash flow from operations to the payment of principal and interest on the Company’s indebtedness;

 

●

limit the Company flexibility in planning for, or reacting to, changes in our business and the industry in which the Company operate;

 

 

●

result in dilution to the Company’s shareholders in the event we issue equity to fund the Company’s debt obligations;

 

●

place the Company at a competitive disadvantage compared to the Company’s competitors that are less highly leveraged and that, therefore, may be able to take advantage of opportunities that the Company leverage prevents the Company from exploiting; and

 

●

limit the Company’s ability to borrow additional funds.

 

To the extent the Company is unable to repay the Company’s debt as it becomes due with cash on hand or from other sources, the Company will need to refinance the Company’s debt, sell assets or repay the debt with the proceeds from equity offerings in order to continue in business. Additional indebtedness or equity financing may not be available to the Company in the future for the refinancing or repayment of existing debt, or if available, such additional debt or equity financing may not be available on a timely basis, or on terms acceptable to the Company and within the limitations specified in the Company’s then existing debt instruments. If the Company is unable to make payments on the 2028 Notes or repay amounts owing under the Credit Agreement, the holders of the 2028 Notes or lenders under the Credit Agreement could proceed to foreclose or otherwise realize upon the collateral granted to them to secure that indebtedness.

 

In addition, the indenture governing the 2028 Notes includes restrictive covenants which restrict the Company’s ability to, among other things:

 

●

incur, assume or guarantee additional indebtedness; or

 

●

repurchase capital stock and make other restricted payments, including paying dividends and making investments;

 

●

create liens;

 

●

sell or otherwise dispose of assets, including capital stock of subsidiaries;

 

●

pay dividends and enter into agreements that restrict dividends from subsidiaries; and

 

●

enter into transactions with affiliates.

 

Those restrictive covenants could restrict the Company’s ability to carry on its business and operations or raise additional capital. Interference with the business and operations of the Company or the Company’s ability to raise additional capital could have a material adverse effect on the Company’s business, prospects and its financial and operational condition.

 

Increased debt levels may impair the Company’s ability to borrow additional capital on a timely basis to fund opportunities as they arise.

 

From time to time, the Company may enter into transactions to acquire assets or shares of other entities. These transactions may be financed in whole, or in part, with debt, which may increase the Company’s debt levels above industry standards for oil and natural gas companies of similar size. Depending on future exploration and development plans, the Company may require additional debt financing that may not be available or, if available, may not be available on favorable terms. The Company’s constating documents do not limit the amount of indebtedness that the Company may incur. The level of the Company’s indebtedness from time to time could impair the Company’s ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise.

 

Investor confidence and share value may be adversely impacted if the Company concludes that our internal control over financial reporting is not effective.

 

Effective internal controls are necessary for the Company to provide reliable financial reports and to help prevent fraud. Although the Company undertakes a number of procedures in order to help ensure the reliability of its financial reports, including those imposed on it under U.S. and Canadian securities laws, the Company cannot be certain that such measures will ensure that it will maintain adequate control over financial processes and reporting. Failure to implement required new or improved controls, or difficulties encountered in their implementation, could harm the Company’s results of operations or cause it to fail to meet its reporting obligations. If the Company discovers a material weakness, the disclosure of that fact, even if quickly remedied, could reduce investor confidence in its consolidated financial statements and effectiveness of our internal controls, which ultimately could negatively impact the market price of our common shares.

 

 

The Company is a “foreign private issuer” under U.S. securities laws and therefore will be exempt from certain requirements applicable to U.S. domestic registrants listed on the NYSE.

 

Although the Company is subject to the periodic reporting requirement of the Exchange Act, the periodic disclosure required of foreign private issuers under the Exchange Act is different from periodic disclosure required of U.S. domestic registrants. Therefore, there may be less publicly available information about the Company than is regularly published by or about other companies in the United States. The Company is exempt from certain other sections of the Exchange Act to which U.S. domestic issuers are subject, including the requirement to provide its shareholders with information statements or proxy statements that comply with the Exchange Act. In addition, insiders and large shareholders of the Company are not obligated to file reports under Section 16 of the Exchange Act.

 

The Company is permitted to follow certain home country corporate governance practices instead of those otherwise required by the NYSE for domestic issuers. A foreign private issuer must disclose in its annual reports filed with the SEC or on its website each NYSE requirement with which it does not comply, followed by a description of its applicable home country practice. The Company has the option to rely on available exemptions under the rules of the NYSE that allow it to follow its home country practice, including, among other things, the ability to opt out of (i) the requirement that the Board be comprised of a majority independent directors, (ii) the requirement that the Company’s independent directors meet regularly in executive sessions and (iii) the requirement that the Company obtain shareholder approval prior to the issuance of securities in connection with certain acquisitions, private placements of securities, or the establishment or amendment of certain share option, purchase or other compensation plans. The Company may elect to follow certain other home country corporate governance practices in lieu of the requirements for U.S. companies listed on the NYSE , as permitted by the rules of the NYSE, in which case the protection that is afforded to our shareholders would be different from that accorded to investors of U.S. domestic issuers.

 

The Company could lose its status as a “foreign private issuer” under current SEC rules and regulations if more than 50% of the Company’s outstanding voting securities become directly or indirectly held of record by U.S. holders and any one of the following is true: (i) the majority of the Company’s directors or executive officers are U.S. citizens or residents; (ii) more than 50% of the Company’s assets are located in the United States; or (iii) the Company’s business is administered principally in the United States. If the Company loses its status as a foreign private issuer in the future, it will no longer be exempt from the rules described above and, among other things, will be required to file periodic reports and annual and quarterly financial statements as if it were a company incorporated in the United States. If this were to happen, the Company would likely incur substantial costs in fulfilling these additional regulatory requirements and members of the Company’s management would likely have to divert time and resources from other responsibilities to ensuring these additional regulatory requirements are fulfilled.

 

The Company is an “emerging growth company” and the reduced disclosure requirements applicable to emerging growth companies may make the Common Shares less attractive to investors.

 

The Company is an “emerging growth company” (“EGC”), as defined in the JOBS Act, and is eligible for certain exemptions from various requirements that are applicable to other public companies that are not “emerging growth companies”, including, but not limited to, including: (i) the exemption from the auditor attestation requirements with respect to internal control over financial reporting under Section 404 of SOX; (ii) the exemptions from say-on-pay, say-on-frequency and say-on-golden parachute voting requirements; and (iii) reduced disclosure obligations regarding executive compensation in the Company’s periodic reports and proxy statements. As a result, the Company Shareholders may not have access to certain information they deem important. The Company will remain an “emerging growth company” until the earliest of (a) the last day of the first fiscal year in which the Company’s annual gross revenues exceed $1.235 billion, (b) the date that the Company becomes a “large accelerated filer” as defined in Rule 12b-2 under the U.S. Exchange Act, which would occur if the market value of the Common Shares that are held by non-affiliates exceeds $700 million as of the last business day of the Company’s most recently completed second fiscal quarter, (c) the date on which the Company has issued more than $1.0 billion in nonconvertible debt during the preceding three-year period or (d) the last day of the Company’s fiscal year containing the fifth anniversary of the date of the Company’s first public offering of securities.  The Company may choose to rely upon some or all of the available exemptions. When the Company is no longer deemed to be an emerging growth company, the Company will not be entitled to the exemptions provided in the JOBS Act discussed above. The Company cannot predict if investors will find the Common Shares less attractive as a result of the Company’s reliance on exemptions under the JOBS Act. If investors find the Common Shares less attractive as a result, there may be a less active trading market for the Common Shares and the Company share price may be more volatile.

 

Canadian and U.S. investors may find it difficult or impossible to effect service of process and enforce judgments against the Company, the Company directors and executive officers.

 

Certain directors of the Company reside outside of Canada. Consequently, it may not be possible for Canadian investors to enforce judgments obtained in Canada against any person who resides outside of Canada, even if the party has appointed an agent for service of process. Furthermore, it may be difficult to realize upon or enforce in Canada any judgment of a court of Canada against the directors of Greenfire who reside outside of Canada since a substantial portion of the assets of such person may be located outside of Canada.

 

Similarly, the Company is incorporated under the laws of Alberta, Canada, and most of its officers and directors are not residents of the United States, and substantially all of the assets of the Company are located outside the United States. As a result, it may be difficult for U.S. investors to: (i) effect service of process within the United States upon the Company or those directors and officers who are not residents of the United States; or (ii) realize in the United States upon judgments of courts of the United States predicated upon the civil liability provisions of the United States federal securities laws.

 

 

The Company incurs significant increased expenses and administrative burdens as a public company in the United States and as a “reporting issuer” in Canada, which could have an adverse effect on its business, financial condition and results of operations.

 

The Company faces, and will continue to face, increased legal, accounting, administrative and other costs and expenses as a public company in the United States that the Company did not incur as a private company. The Sarbanes-Oxley Act, including the requirements of Section 404 thereof, as well as rules and regulations subsequently implemented by the SEC, the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 and the rules and regulations promulgated and to be promulgated thereunder, PCAOB and the securities exchanges, impose additional reporting and other obligations on public companies. Compliance with public company requirements have and will increase costs and make certain activities more time-consuming. A number of those requirements require the Company to carry out activities the Company has not done previously. In addition, expenses associated with SEC reporting requirements are and will be incurred. Furthermore, if any issues in complying with those requirements are identified (for example, if the auditors identify a significant deficiency or material weaknesses in the internal control over financial reporting), the Company could incur additional costs to rectify those issues, and the existence of those issues could adversely affect its reputation or investor perceptions. In addition, the Company has purchased director and officer liability insurance, which has substantial additional premiums. The additional reporting and other obligations imposed by these rules and regulations increase legal and financial compliance costs and the costs of related legal, accounting and administrative activities. Advocacy efforts by shareholders and third parties may also prompt additional changes in governance and reporting requirements, which could further increase costs.

 

The Company additionally faces, increased legal, accounting, administrative and other costs and expenses as a “reporting issuer” in Canada in connection with its compliance with applicable Canadian securities laws. The additional reporting and other obligations imposed by such Canadian securities laws have increased legal and financial compliance costs and the costs of related legal, accounting and administrative activities.

 

Management estimates are subject to uncertainty.

 

In preparing consolidated financial statements in conformity with IFRS, estimates and assumptions are used by management in determining the reported amounts of assets and liabilities, revenues and expenses recognized during the periods presented and disclosures of contingent assets and liabilities known to exist as of the date of the financial statements. These estimates and assumptions must be made because certain information that is used in the preparation of such financial statements is dependent on future events, cannot be calculated with a high degree of precision from data available, or is not capable of being readily calculated based on generally accepted methodologies. In some cases, these estimates are particularly difficult to determine and the Company must exercise significant judgment. Estimates may be used in management’s assessment of items such as fair values, income taxes, stock-based compensation and asset retirement obligations. Actual results for all estimates could differ materially from the estimates and assumptions used by the Company, which could have a material adverse effect on the Company’s business, financial condition, results of operations, cash flows and future prospects.

 

The Company has a limited operating history, which may not be sufficient to evaluate its business and prospects.

 

Greenfire commenced operations in April of 2021, when a predecessor entity of Greenfire acquired the Demo Asset, and a predecessor entity of Greenfire acquired the Expansion Asset in September of 2021. The Company had no material operations prior to the Business Combination and has continued the business of Greenfire since the Closing of the Business Combination. As a result, there is a limited operating history on which to base any estimates of future operating costs related to any future development of the Company’s properties, there can be no assurance that the Company’s actual capital and operating costs for any future development activities will not be higher than anticipated and Greenfire’s historical financial statements may not be a reliable basis for evaluating the Company’s business prospects or the value of Common Shares. We cannot give you any assurance that the Company’s strategy will be successful or that the Company will be able to implement that strategy on a timely basis.

 

Risks Related to Ownership of the Company’s Securities

 

Concentration of ownership among the Company’s existing executive officers, directors and their affiliates may prevent new investors from influencing significant corporate decisions.

 

As of April 29, 2024, the Company’s executive officers, directors and their affiliates, beneficially held approximately 48.8% (including 4,608,131 Common Shares issuable upon exercise of Company Warrants, and Company Performance Warrants) of the outstanding Common Shares. As a result, these shareholders are able to exercise a significant level of control over all matters requiring shareholder approval, including the election of directors, any amendment of the Company Articles and the Company Bylaws and approval of significant corporate transactions. This control could have the effect of delaying or preventing a change of control or changes in management and will make the approval of certain transactions difficult or impossible without the support of these shareholders. 

 

A significant portion of the Company’s total outstanding securities may be sold into the market in the near future. This could cause the market price of the Common Shares to drop significantly, even if the Company’s business is performing well.

 

Sales of a substantial number of Common Shares in the public market could occur at any time. These sales, or the perception in the market that the holders of a large number of shares intend to sell shares, could reduce the market price of Common Shares and could impair our ability to raise capital through the sale of additional equity securities. We are unable to predict the effect that such sales may have on the prevailing market price of our Common Shares.

 

 

As of the Closing of the Business Combination, (i) MBSC Sponsor beneficially owned 6,376,666 Common Shares, representing approximately 9% of the Common Shares (including 2,526,667 Common Shares issuable upon exercise of the Company Warrants); and (ii) the certain other holders of Common Shares party to the Lock-Up Agreement beneficially owned, in the aggregate, 44,522,795 Common Shares, representing approximately 59% of all outstanding Common Shares (including 3,393,751 Common Shares issuable upon exercise of the Company Warrants). The sale of substantial amounts of such Common Shares in the public market by such Company shareholders or the MBSC Sponsor, or the perception that such sales could occur, could harm the prevailing market price of the Common Shares. These sales, or the possibility that these sales may occur, also might make it more difficult for the Company to sell Common Shares in the future at a time and at a price that it deems appropriate. The restrictions of the Lock-up Agreement applicable to MBSC Sponsor and the Company shareholders party thereto applied through March 18, 2024, when those restrictions expired. Following the expiration of the restrictions in the Lock-Up Agreement, MBSC Sponsor and the other Company shareholders party thereto, can sell, or indicate an intention to sell, any or all of their Common Shares in the public market. As a result, the trading price of the Common Shares could decline. In addition, the perception in the market that these sales may occur could also cause the trading price of the Common Shares to decline.

 

Given the relatively lower purchase prices that certain securityholders paid to acquire Common Shares, those certain securityholders in some instances would earn a positive rate of return on their investment, which may be a significant positive rate of return, depending on the market price of the Common Shares at the time that such certain securityholders choose to sell their Common Shares, at prices where other of our securityholders may not experience a positive rate of return if they were to sell at the same prices. For example, (a) the MBSC Sponsor received its 3,850,000 Common Shares in exchange for MBSC Class B Common Shares, which were originally purchased for a purchase price equivalent to approximately $0.0033 per share and (b) certain former Greenfire Shareholders party to the Lock-Up Agreement received their Common Shares in exchange for securities of Greenfire for little consideration.

 

The last reported sales prices of the Common Shares on the NYSE and TSX on May 8, 2024 was 5.87 and CAD$7.97, respectively. Even though the trading price of the Common Shares is currently significantly below the last reported sales price on the NYSE of $9.37 on the Closing Date of the Business Combination, all of such certain securityholders may have an incentive to sell their Common Shares because they acquired them in exchange for securities acquired for prices lower, and in some cases significantly lower, than the current trading price of the Common Shares and may profit, in some cases significantly so, even under circumstances in which our public shareholders would experience losses in connection with their investment. Based on the current trading price of the Common Shares, MBSC Sponsor and the Greenfire Holders could earn up to approximately $5.8667 and $5.87, respectively, in potential profit per share if they were to sell those Common Shares at the current trading price. Certain Greenfire Holders also hold, in the aggregate, 1,907,854 Company Performance Warrants, with exercise prices that range from CAD$2.14 to CAD$2.84 (US$1.56 to US$2.07, using an exchange rate of 1.00 USD to 1.37 CAD as of May 9, 2024) and could earn up to approximately US$4.31 in profit per share if they were to sell the Common Shares issuable upon exercise of those Company Performance Warrants at the current trading price. The PIPE Investors purchased their Common Shares at US$10.10 per share and would not earn a profit if they were to sell those shares at the current trading price.

 

Investors who have purchased or who will purchase the Common Shares on the NYSE following the Business Combination are unlikely to experience a similar rate of return on the Common Shares they purchase due to differences in the purchase prices and the current trading price.

 

In addition, sales by such securityholders may cause the trading prices of our securities to experience a decline, which decline may be significant. As a result, the sale by certain securityholders may effect sales of Common Shares at prices significantly below the current market price, which could cause market prices to decline further.

 

In addition, certain of our significant shareholders have pledged or entered agreements to pledge their Common Shares and Company Warrants to pledgees, including banks and financial institutions, to secure obligations of those shareholders for their borrowings. The Company has been informed that Common Shares of significant shareholders that represent, in the aggregate, approximately 27% of all outstanding Common Shares (including Common Shares issuable upon exercise of Company Warrants), are subject to such pledges or agreements to enter into pledges.

 

 

In the event of enforcement of any pledgee’s rights with respect to any pledged Common Shares or Company Warrants for any reason (including any default under the terms and conditions of the agreements pursuant to which such pledges have been created), such pledged Common Shares or Company Warrants may be required to be transferred to third parties in whose favor the pledges were created. This could result in a decline in the trading price of our Common Shares if the third party sells the shares it obtained or could otherwise adversely affect our ability to carry out our business operations and thereby adversely affect our business, financial condition, results of operations as well as the trading price of our Common Shares.

 

If securities or industry analysts do not publish or cease publishing research or reports about the Company, its business or its market, or if they change their recommendations regarding the Common Shares adversely, the price and trading volume of the Common Shares could decline.

 

The trading market for the Common Shares will be influenced by the research and reports that industry or securities analysts may publish about the Company, its business, its market or its competitors. If any of the analysts who cover the Company change their recommendation regarding the Common Shares adversely, or provide more favorable relative recommendations about the Company’s competitors, the price of the Common Shares would likely decline. If any analyst who covers the Company were to cease their coverage or fail to regularly publish reports on the Company, the Company could lose visibility in the financial markets, which could cause its share price or trading volume to decline.

 

The Company’s sole material asset is its direct equity interest in its subsidiaries, and the Company is accordingly dependent upon distributions from its subsidiaries to pay taxes and cover its corporate and other overhead expenses and pay dividends, if any, on Common Shares.

 

The Company has no material assets other than its direct equity interest in its subsidiaries. The Company has no independent means of generating revenue. To the extent the Company’s subsidiaries have available cash, the Company will cause such subsidiaries to make distributions of cash to the Company to pay taxes, cover the Company’s corporate and other overhead expenses and pay dividends, if any, on Common Shares. To the extent that the Company needs funds and the Company’s subsidiaries fail to generate sufficient cash flow to distribute funds to the Company or is restricted from making such distributions or payments under applicable law or regulation or under the terms of its financing arrangements, or is otherwise unable to provide such funds, the Company’s liquidity and financial condition could be materially adversely affected.

 

The price at which the Common Shares are quoted on the NYSE and the TSX may increase or decrease due to a number of factors, which may negatively affect the price of the Common Shares.

 

The price at which the Common Shares are quoted on the NYSE may increase or decrease due to a number of factors. The price of the Common Shares may not increase, even if the Company’s operations and financial performance improves. Some of the factors which may affect the price of the Common Shares include:

 

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fluctuations in domestic and international markets for listed securities;

 

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general economic conditions, including interest rates, inflation rates, exchange rates and commodity and oil prices;

 

●

changes to government fiscal, monetary or regulatory policies, legislation or regulation;

 

●

inclusion in or removal from market indices;

 

●

strategic decisions by the Company or the Company’s competitors, such as acquisitions, divestments, spin-offs, joint ventures, strategic investments or changes in business or growth strategies;

 

●

securities issuances by the Company, or share resales by shareholders, or the perception that such issuances or resales may occur;

 

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pandemic risk;

 

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the nature of the markets in which the Company operates; and

 

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general operational and business risks.

 

Other factors which may negatively affect investor sentiment and influence the Company, specifically or the securities markets more generally include acts of terrorism, an outbreak of international hostilities or tensions, fires, floods, earthquakes, labor strikes, civil wars, natural disasters, outbreaks of disease or other man-made or natural events. The Company will have a limited ability to insure against the risks mentioned above.

 

 

In the future, the Company may need to raise additional funds which may result in the dilution of shareholders, and such funds may not be available on favorable terms or at all.

 

The Company may need to raise additional capital in the future and may elect to issue shares or engage in fundraising activities for a variety of reasons, including funding acquisitions or growth initiatives. Shareholders may be diluted as a result of such fundraisings.

 

Additionally, the Company may raise additional funds through the issuance of debt securities or through obtaining credit from government or financial institutions. The Company cannot be certain that additional funds will be available on favorable terms when required, or at all. If the Company cannot raise additional funds when needed, its financial condition, results of operations, business and prospects could be materially and adversely affected. If the Company raises funds through the issuance of debt securities or through loan arrangements, the terms of such securities or loans could require significant interest payments, contain covenants that restrict the Company’s business, or other unfavorable terms.

 

The Company may not pay dividends or make other distributions in the future.

 

Historically, except pursuant to the Plan of Arrangement, neither the Company nor its predecessors, has paid any dividends. The Company’s ability to pay dividends or make other distributions in the future is contingent on profits and certain other factors, including the capital and operational expenditure requirements of the Company’s business. In addition, the payment of dividends is subject to the approval of the Board and even if the Company is generating profit it may choose to utilize such profit for other purposes, such as paying down debt, capital expenditures or acquisitions, instead of paying dividends. Under the ABCA, a dividend may not be declared or paid by the Company if there are reasonable grounds for believing that the Company is, or would after the payment be, unable to pay its liabilities as they become due, or the realizable value of the Company’s assets would thereby be less than the aggregate of its liabilities and stated capital of all classes. Therefore, dividends may not be paid. See the section entitled “Material Canadian Tax Considerations” for more information regarding the Canadian tax consequences of future Company dividends. Furthermore, please see the subsection entitled “Material U.S. Federal Income Tax Considerations for U.S. Holders-Tax Characterization of Distributions with Respect to Common Shares” for a more detailed discussion with respect to the U.S. federal income tax treatment of the Company’s payment of distributions of cash or other property to U.S. Holders of Common Shares.

 

An active trading market may not develop or be sustained for the Common Shares and there is not expected to be an active market for the Company Warrants.

 

Although the Common Shares are currently listed on the NYSE and the TSX, an active trading market for Common Shares may not develop or the price of Common Shares may not increase. There may be relatively few potential buyers or sellers of Common Shares on the NYSE or the TSX at any time. This may increase the volatility of the market price of Common Shares. It may also affect the prevailing market price at which shareholders are able to sell their Common Shares. This may result in shareholders receiving a market price for their Common Shares that is less than the value of their initial investment.

 

The market price of the Common Shares may be subject to fluctuation and/or decline.

 

Fluctuations in the price of the Common Shares could contribute to the loss of all or part of your investment. If an active market for the Common Shares develops and continues, the trading price of the Common Shares could be volatile and subject to wide fluctuations in response to various factors, some of which are beyond the Company’s control. Any of the factors listed below could have a material adverse effect on the Common Shares and such securities may trade at prices significantly below the price you paid for them. In such circumstances, the trading price of such securities may not recover and may experience a further decline.

 

 

Factors affecting the trading price of the Common Shares may include:

 

●

actual or anticipated fluctuations in its financial results or the financial results of companies perceived to be similar to the Company;

 

●

changes in the market’s expectations about the Company’s operating results;

 

●

success of competitors;

 

●

the Company’s operating results failing to meet the expectation of securities analysts or investors in a particular period;

 

●

changes in financial estimates and recommendations by securities analysts concerning the Company or the market in general;

 

●

operating and stock price performance of other companies that investors deem comparable to the Company;

 

●

changes in laws and regulations affecting the Company’s business;

 

●

the Company’s ability to meet compliance requirements;

 

●

commencement of, or involvement in, litigation involving the Company;

 

●

changes in the Company’s capital structure, such as future issuances of securities or the incurrence of additional debt;

 

●

the volume of Common Shares available for public sale;

 

●

any major change in the board of directors or management of the Company;

 

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sales of substantial amounts of Common Shares by the Company’s directors, executive officers or significant shareholders, including the MBSC Sponsor and PIPE Investors, or the perception that such sales could occur; and

 

●

general economic and political conditions such as recessions; fluctuations in interest rates, fuel prices and international currency; and acts of war or terrorism.

 

Broad market and industry factors may materially harm the market price of the Common Shares irrespective of their operating performance. The stock market in general and the NYSE have experienced price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of the particular companies affected. The trading prices and valuations of these stocks, and of the Common Shares, may not be predictable. A loss of investor confidence in the market for retail stocks or the stocks of other companies which investors perceive to be similar to the Company could depress the Company’s share price regardless of its business, prospects, financial conditions or results of operations. A decline in the market price of the Common Shares also could adversely affect the Company’s ability to issue additional securities and its ability to obtain additional financing in the future.

 

The trading price of the securities of oil and natural gas issuers is subject to substantial volatility often based on factors related and unrelated to the financial performance or prospects of the issuers involved. Factors unrelated to the Company’s performance could include macroeconomic developments nationally, within North America or globally, domestic and global commodity prices, and/or current perceptions of the oil and natural gas market. In recent years, the volatility of commodities has increased due, in part, to the implementation of computerized trading and the decrease of discretionary commodity trading. In addition, the volatility, trading volume and share price of issuers have been impacted by increasing investment levels in passive funds that track major indices, as such funds only purchase securities included in such indices. Similarly, the market price of the Common Shares could be subject to significant fluctuations in response to variations in the Company’s operating results, financial condition, liquidity and other internal factors. Accordingly, the price at which the Common Shares will trade cannot be accurately predicted.

 

 

The listing of our securities on the NYSE did not benefit from the process customarily undertaken in connection with an underwritten initial public offering, which could result in diminished investor demand, inefficiencies in pricing and a more volatile public price for our securities.

 

Unlike an underwritten initial public offering of our securities, the initial listing of the Common Shares as a result of the Business Combination did not benefit from the book-building process undertaken by underwriters that helps to inform efficient price discovery with respect to opening trades of newly listed securities or underwriter support to help stabilize, maintain or affect the public price of the new issue immediately after listing.

 

The lack of such a process in connection with the listing of our securities could result in diminished investor demand, inefficiencies in pricing and a more volatile public price for our securities during the period immediately following the listing than in connection with an underwritten initial public offering.

 

On February 21, 2024 the Company was notified by the NYSE that the Company was not in compliance with the NYSE’s continued listing standard that requires all listed companies to have a minimum of 400 public stockholders on a continuous basis. Under the NYSE’s rules, the Company has 90 days to present a business plan to the NYSE that demonstrates how the Company intends to cure the deficiency within 18 months of the date of the notice. Throughout this 18-month cure period, the Company’s common shares will continue to be traded on the NYSE, subject to the Company’s compliance with other NYSE listing requirements. The Company believes that the recent listing of the Common Shares on the TSX and the expiration on March 18, 2024 of the Lock-up Agreement covering approximately 65% of the outstanding Common Shares, which occurred subsequent to the date of that notice, will contribute to aiding the Company in meeting the NYSE’s public stockholder requirement, however there can be no assurance that the Company will be able to do so within the required period or that the Company will be able to continue to comply with the NYSE’s other listing requirements.

 

The NYSE or TSX may delist Common Shares from trading on their exchanges, which could limit investors’ ability to make transactions in the Common Shares and subject the Company to additional trading restrictions.

 

The Common Shares may not continue to be listed on the NYSE or the TSX.

 

If the NYSE or the TSX delists the Common Shares from trading on its exchange and the Company is not able to list its securities on another national securities exchange, the Company expects that its securities could be quoted on an over-the-counter market. If this were to occur, the Company could face significant material adverse consequences, including:

  

●

a limited availability of market quotations for the Common Shares;

 

●

reduced liquidity for the Common Shares;

 

●

a determination that Common Shares are a “penny stock” which will require brokers trading in Common Shares to adhere to more stringent rules and possibly result in a reduced level of trading activity in the secondary trading market for the Common Shares;

 

●

a limited amount of news and analyst coverage; and

 

●

a decreased ability to issue additional securities or obtain additional financing in the future.

 

The National Securities Markets Improvement Act of 1996, which is a United States federal statute, prevents or preempts the states from regulating the sale of certain securities, which are referred to as “covered securities.” If the Common Shares are not listed on the NYSE or another United States national securities exchange, the Common Shares would not qualify as covered securities and the Company would be subject to regulation in each state in which the Company offers its Common Shares because states are not preempted from regulating the sale of securities that are not covered securities

 

There is no guarantee that the exercise price of Company Warrants will ever be less than the trading price of the Common Shares, and the Company Warrants may expire worthless. In addition, we may reduce the exercise price of the Company Warrants in accordance with the provisions of the Warrant Agreements, and a reduction in exercise price of the Company Warrants would decrease the maximum amount of cash proceeds we could receive upon the exercise in full of the Company Warrants for cash.

 

As of the date of this prospectus, the exercise price for Company Warrants is $11.50 per Common Share. On May 8, 2024, the closing price of our Common Shares was $5.87 on the NYSE. If the price of our Common Shares remains below $11.50 per share, we believe holders of Greenfire will be unlikely to exercise their Company Warrants, resulting in little or no cash proceeds to us. There is no guarantee that the Company Warrants will be in the money prior to their expiration and, as such, the Company Warrants may expire worthless.

 

In addition, at the current exercise price of $11.50 per share, we would receive up to approximately $62.3 million from the exercise of the Company Warrants, assuming the exercise in full of all of the Company Warrants for cash. However, we may lower the exercise price of the in accordance with the Warrant Agreements. The Company may effect such reduction in exercise price without the consent of warrant holders and such reduction would decrease the maximum amount of cash proceeds we would receive upon the exercise in full of the Company Warrants for cash.

 

  

USE OF PROCEEDS

 

All of the Common Shares offered by the Selling Securityholders pursuant to this prospectus will be sold by the Selling Securityholders for their respective accounts. The Company will not receive any of the proceeds from these sales.

 

The Company would receive up to an aggregate of approximately $62 million from the exercise of Company Warrants, assuming the exercise in full of all such warrants for cash. We expect to use the net proceeds from the exercise of Company Warrants, if any, to support the Company’s execution of its capital program. Our management will have broad discretion over the use of any proceeds received from the exercise of the Company Warrants.

 

There is no assurance that the holders of Company Warrants will elect to exercise any or all of the Company Warrants. Whether holders of Company Warrants will exercise their Company Warrants, and therefore the amount of cash proceeds we would receive upon exercise, is dependent upon the trading price of the Common Shares. The last reported sales prices of the Common Shares on the NYSE and TSX on May 8, 2024 was $5.87 and CAD$7.97, respectively. On the NYSE. Each Company Warrant is exercisable for one Common Share at an exercise price of $11.50. Therefore, if and when the trading price of the Common Shares is less than $11.50, we expect that holders of Company Warrants would not exercise their Company Warrants. Although we could receive up to an aggregate of approximately $62 million if all of the Company Warrants are exercised for cash, we would only receive any proceeds if and when the holders exercise those warrants. The Company Warrants may not be in the money during the period they are exercisable and prior to their expiration, and the Company Warrants may not be exercised prior to their maturity on September 20, 2028, even if they are in the money, and as such, the Company Warrants may expire worthless and we may receive minimal proceeds, if any, from the exercise of the Company Warrants. To the extent that any of the Company Warrants are exercised on a “cashless basis,” we will not receive any proceeds upon such exercise. As a result, we do not expect to rely on the cash exercise of Company Warrants to fund our operations. Instead, we intend to rely on other sources of cash discussed elsewhere in this prospectus to continue to fund our operations. See “Risk Factors—Risks Related to Ownership of the Company’s Securities—There is no guarantee that the exercise price of our Company Warrants will ever be less than the trading price of our Common Shares on the NYSE, and they may expire worthless. In addition, we may reduce the exercise price of the Warrants in accordance with the provisions of the Warrant Agreement, and a reduction in exercise price of the Company Warrants would decrease the maximum amount of cash proceeds we could receive upon the exercise in full of the Company Warrants for cash” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resource and Liquidity.”

 

 

MARKET PRICE OF OUR SECURITIES AND DIVIDENDS

 

The common shares of the Company are traded on the NYSE and the TSX under the symbol “GFR”. The last reported sales prices of the Common Shares on the NYSE and TSX on May 8, 2024 was $5.97 and CAD$7.97, respectively.

 

Dividends

 

Except pursuant to the Plan of Arrangement, neither the Company nor its predecessors has paid any dividends to its shareholders. Under the Company Articles, the holders of the Common Shares will be entitled to receive dividends at such times and in such amounts as the Board may in their discretion from time to time declare, subject to the prior rights and privileges attached to any other class or series of shares of the Company. The holders of each series of Company Preferred Shares (if any) will be entitled, in priority to holders of Common Shares and any other shares of the Company ranking junior to the Company Preferred Shares from time to time with respect to the payment of dividends, to be paid rateably with holders of each other series of Company Preferred Shares, the amount of accumulated dividends (if any) specified as being payable preferentially to the holders of such series.

 

Under the ABCA, the Company may not pay a dividend in money or other property if there are reasonable grounds for believing that the Company is, or would after the payment be, unable to pay its liabilities as they become due, or the realizable value of the Company’s assets would thereby be less than the aggregate of its liabilities and stated capital of all classes.

 

The Company currently intends to retain any earnings to fund the development and growth of its business and repay indebtedness and does not currently anticipate paying dividends in the near term. Any decision to pay dividends in the future will be at the discretion of the Board and will depend on many factors including, among others, the Company’s financial condition, fluctuations in commodity prices, production levels, capital expenditure requirements, debt services requirements, operating costs, royalty burdens, foreign exchange rates, contractual restrictions (including other credit facilities), financing agreement covenants, solvency tests imposed by applicable corporate law and other factors that the Board may deem relevant.

 

  

BUSINESS

 

History and Development of the Company

 

The Company is an intermediate-sized oil sands producer focused on responsible energy development in the Athabasca region of Alberta, Canada. The Company is actively developing its existing producing assets using SAGD, an enhanced oil recovery extraction method, to responsibly increase the economic recovery of oil.

 

The Company is an Alberta corporation incorporated on December 9, 2022, for the purpose of effectuating the Business Combination. Upon the terms and subject to the conditions of the Business Combination Agreement, MBSC, the Company, Canadian Merger Sub, DE Merger Sub and Greenfire effected a series of the transactions that closed on September 20, 2023, as a result of which the Company became the parent of Greenfire and MBSC. For additional information regarding the Business Combination, please see the section of this prospectus under the heading “Summary of Prospectus—Business Combination”.

 

Following the Business Combination, the Company has continued the business of Greenfire.

 

Effective as of January 1, 2024, Greenfire Resources Operating Corporation and Greenfire amalgamated in accordance with the provisions of the ABCA, with the surviving corporation continuing as Greenfire Resources Operation Corporation and as a wholly subsidiary of the Company.

 

Greenfire Corporate History

  

Greenfire was the result of a number of transactions (collectively referred to herein as the “Reorganization Transactions”) that included: (i) the acquisition of the Demo Asset out of the insolvency proceedings of an unaffiliated corporation named GHOPCO; (ii) a series of incorporations, amalgamations and other reorganization transactions; and (iii) the acquisition JACOS (which held the Expansion Asset). The Reorganization Transactions were completed in the following manner:

 

Greenfire Acquisition Corporation (“GAC”) was incorporated under the provisions of the ABCA on November 2, 2020. GAC HoldCo Inc. (“GAC HoldCo”) was incorporated under the provisions of the ABCA on June 1, 2021. HE Acquisition Corporation (“HEAC”) was incorporated under the provisions of the ABCA as a wholly-owned subsidiary of GAC HoldCo on July 12, 2021.

 

On September 9, 2021: (i) 2373436 Alberta Ltd. (“SubCo”), as a wholly-owned subsidiary of GAC HoldCo; (ii) Hangingstone Demo (GP) Inc. (“Demo GP”), as a wholly-owned subsidiary of SubCo; (iii) Hangingstone Expansion (GP) Inc. (“Expansion GP”), as a wholly-owned subsidiary of HEAC; and (iv) 2373525 Alberta Ltd. (“ServiceCo”), as a wholly-owned subsidiary of HEAC, were incorporated under the provisions of the ABCA.

 

On September 9, 2021, (i) Expansion GP, as general partner, and HEAC, as limited partner, formed Hangingstone Expansion Limited Partnership (“Expansion LP”) and (ii) Demo GP, as general partner, and SubCo, as limited partner, formed Hangingstone Demo Limited Partnership (“Demo LP”).

 

GAC acquired the Demo Asset from GHOPCO on April 5, 2021 as a result of the proceedings commenced on October 8, 2020, by each of GHOPCO and its parent company, Greenfire Oil and Gas Ltd., filing a Notice of Intention to Make A Proposal pursuant to the provisions of the Bankruptcy and Insolvency Act (Canada) (the “NOI Proceedings”).

 

On September 16, 2021, GAC, GAC HoldCo and SubCo entered into an amalgamation agreement providing for a triangular amalgamation whereby: (i) GAC and SubCo were combined to form the original iteration of “Greenfire Resources Operating Corporation” (“GAC AmalCo”); (ii) the Demo Asset was transferred (via amalgamation) to GAC AmalCo; and (ii) the shareholders of GAC received a nominal number of common shares of GAC HoldCo.

 

JACOS Acquisition

 

On September 17, 2021, the JACOS Acquisition was completed, whereby HEAC acquired all of the issued and outstanding shares of JACOS and thereby took ownership of JACOS’s primary asset, a 75% working interest in the Expansion Asset. On September 17, 2021, JACOS contributed all of its oil and gas assets to Expansion LP and GAC AmalCo contributed all of its oil and gas assets to Demo LP. On September 17, 2021, HEAC and JACOS were amalgamated to form a temporary amalgamated entity (“Temporary AmalCo”) and Temporary AmalCo and GAC AmalCo were amalgamated to form the final iteration of “Greenfire Resources Operating Corporation” (“GROC”).

 

Following the Reorganization Transactions, GAC HoldCo changed its name to “Greenfire Resources Inc.” and ServiceCo changed its name to “Greenfire Resources Employment Corporation.”

 

 

General Development of the Business of Greenfire

 

Prior to the incorporation of GAC on November 2, 2020, neither Greenfire nor any of its subsidiaries conducted any business or had any operations. The following is a summary description of the development of Greenfire’s business since the incorporation of GAC on November 2, 2020.

 

Discussion of Initial Incorporation and Financing

 

The principals of McIntyre Partners and Griffon Partners, each private investment companies, based in the United Kingdom, founded GAC on November 2, 2020 for the purpose of pursuing the acquisition of the Demo Asset pursuant to the NOI Proceedings.

 

Acquisition of the Demo Asset

 

In 2016, a wildfire in Northern Alberta caused the temporary shutdown of a number of oilsands facilities, including the Demo Asset, which was then owned and operated by JACOS. Although there was no physical damage to the facilities and equipment at the Demo Asset, JACOS elected not to restart the facility after the wildfire was contained. JACOS was also planning for and constructing the Expansion Asset at that time. The Demo Asset remained non-operational until 2018.

 

In 2018, GHOPCO, the unaffiliated predecessor company that owned and operated the Demo Asset prior to GAC, acquired the Demo Asset from JACOS. GHOPCO successfully restarted production in 2018 and operated the facility until May 2020, when GHOPCO shut down operations following the onset of the COVID-19 pandemic. On October 8, 2020, each of GHOPCO and its parent company, Greenfire Oil and Gas Ltd., filed a Notice of Intention to Make A Proposal pursuant to the provisions of the Bankruptcy and Insolvency Act (Canada) (the “NOI Proceedings”) commencing the NOI Proceedings.

 

Around December 1, 2020, GHOPCO and GAC entered into an asset purchase agreement pursuant to which GAC agreed to acquire the Demo Asset from GHOPCO (the “NOI Transaction”). Despite its similar name, GAC was not affiliated with GHOPCO. On December 18, 2020, pursuant to an Order (the “Insolvency Court Order”) of the Court of Queen’s Bench of Alberta (as it was then called) (the “Court”) approved the NOI Transaction. On April 5, 2021, following receipt of all necessary approvals, GAC completed the acquisition of the Demo Asset pursuant to the terms of the Insolvency Court Order, free and clear of all encumbrances (except those permitted encumbrances set out in the Insolvency Court Order). The total cash consideration paid by GAC for the Demo Asset was CAD$19.7 million. This consideration was comprised of the assumption by GAC of amounts advanced by the Petroleum Marketer to GHOPCO in the NOI Proceedings pursuant to the terms of an interim financing facility. GAC assumed the amounts outstanding under the interim financing pursuant to the terms of a term loan agreement with the Petroleum Marketer.

 

Following the acquisition of the Demo Asset, GAC employed a substantial majority of the GHOPCO operations team and certain members of the former GHOPCO management team. Following the completion of certain repairs to the Demo Asset, GAC restarted operations at the Demo Asset and worked to increase production with limited capital expenditures, primarily by facility optimization and reservoir management.

 

Acquisition of the Expansion Asset

 

On September 17, 2021, HEAC, as predecessor of GROC, acquired all of the issued and outstanding shares in the capital of JACOS pursuant to the JACOS Acquisition for a purchase price of approximately CAD$347 million. At the time of the JACOS Acquisition, JACOS’s primary asset was a 75% working interest and operatorship in the Expansion Asset.

 

Corporate Information

 

The Company’s principal office is located at 2700, 525-8th Avenue SW, Calgary, Alberta, Canada T2P 1G1, our registered office is located at 1900 – 205 5th Avenue SW, Calgary, Alberta, T2P 2V7 and our telephone number is (403) 264-9046. The SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. The SEC’s website at http://www.sec.gov contains our reports and other information that we file electronically with the SEC. Company’s website is https://www.greenfireres.com.

 

Description of Business of the Company

 

The Company is an intermediate-sized oil sands producer focused on responsible energy development in the Athabasca region of Alberta, Canada. The Company is actively developing its existing producing assets using SAGD, an enhanced oil recovery extraction method, to responsibly increase the economic recovery of oil.

 

About 80% of Alberta’s bitumen reserves are too deep to be mined and must be extracted in-place (or in-situ) using steam, whereby bitumen is heated and pumped out of the ground, leaving most of the solids behind. In-situ extraction has a much smaller footprint than oil sands mining, uses less water, and does not produce a tailings stream.

 

 

SAGD uses a dual-pair of horizontal wells drilled approximately five meters apart, one above the other. Well depth can vary anywhere from 150 to 450 meters and length can be over 1,600 meters. High pressure steam is injected into the top well, or the injection well, and the hot steam heats the surrounding bitumen. As the bitumen warms up, it liquefies and, due to gravity, begins to flow to the lower well, or the producing well. The bitumen and condensed steam emulsion contained in the lower well are pumped to the surface and sent to a processing plant, where the bitumen and water are separated. The recovered water is treated and recycled back into the process and the bitumen is typically diluted with natural gas condensate, and sold to market.

 

Both the Demo Asset and the Expansion Asset use SAGD to produce bitumen reserves. Both the Demo Asset and Expansion Asset are considered by the Company to be Tier 1 SAGD reservoirs in that they have no top gas, bottom water or lean zones. Top gas, bottom water or lean zones are considered “thief zones” as they provide an unwanted outlet for steam and reservoir pressure. Thief zones require costly downhole pumps and recurring pump replacements to achieve targeted production rates, leading to higher capital and operating expenditures.

 

Principal Properties

 

Hangingstone Expansion Asset

 

The Company owns a 75% working interest in the Expansion Asset. The Expansion Asset is located in the southern Athabasca region of Northeastern Alberta, approximately 30 miles southwest of Fort McMurray. JACOS commenced Phase I construction of the Expansion Asset in 2013, investing approximately $1.5 billion of capital to create robust infrastructure to support growth. The Expansion Asset’s first steam occurred in April 2017 and first production occurred in July 2017. The Company estimates that the Expansion Asset has a debottlenecked capacity of 35,000 bbls/d of bitumen production. Since the commencement of production in 2017, 32 well pairs have been developed at the Expansion Asset. The Expansion Asset is pipeline connected for diluted bitumen and diluent, and as a result, all production from the Expansion Asset is transported by pipeline following the blending of bitumen with diluent to meet pipeline specifications.

 

In 2023, the annual average gross production from the Expansion Asset was 18,439 bbls/d (approximately 13,829 bbls/d net to Greenfire’s working interest) of bitumen. The Company has an interest in 17,730 gross hectares (13,298 net hectares) of land at the Expansion Asset.

 

Hangingstone Demo Asset

 

The Company owns a 100% working interest in the Demo Asset, which is approximately three miles from the Expansion Asset. Management estimates that the Demo Asset has a debottlenecked capacity of 7,500 bbls/d of bitumen production. The Demo Asset was originally commissioned in 1999 by JACOS as a demonstration asset to prove the economic viability of enhanced thermal oil recovery. As of December 31, 2023, approximately 40 million barrels of bitumen had been produced at the Demo Asset and the facility has a relatively long history of production.

 

Bitumen production from the Demo Asset is unique relative to other thermal oil assets in western Canada as it is produced without the use of added diluent or synthetic oils. This attribute results in relatively lower operating expenses when compared to other oilsands assets of similar scale and provides more options in terms of marketing and selling the product. Access to a diluent-free heavy crude oil barrel is also valued by refiners in the United States, which facilitates additional sales points for the Demo Asset’s production, including transportation by rail to the United States to access West Texas Intermediate (“WTI”) indexed pricing, when it is economically viable to do so. Following the JACOS Acquisition, Greenfire constructed a truck offloading facility at the Expansion Asset to accept trucked production volumes from the Demo Asset. Prior to the construction of the truck offloading facility, production from the Demo Asset was required to be trucked over 600 miles round trip to a pipeline salespoint, and following completion of the construction of the truck offloading facility the round trip trucking distance has been reduced to approximately six miles. Aside from enhancing profitability by reducing transportation costs, the reduction of distance trucked reduces emissions associated with the transportation of its production. 

 

In 2023, the gross and net annual average bitumen production from the Demo Asset was 3,810 bbls/d. Greenfire has an interest in 974 hectares of land at the Demo Asset.

 

Undeveloped Properties

 

As a result of the JACOS Acquisition, the Company holds significant undeveloped leases at three locations, Chard, Corner, and Liege, all of which are in the Athabasca region of Alberta, Canada. The Company believes that the Chard and Corner properties are potential prospects for future in-situ bitumen production using SAGD processes.

 

Land Acreage

 

Developed acreage, as used herein, means those acres spaced or assignable to productive wells. A gross acre is an acre in which a working interest is owned, and a net acre is the result that is obtained when the fractional ownership working interest of a lease is multiplied by gross acres of that lease. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof. Greenfire’s developed acreage consists of the drainage areas of bitumen producing wells.

 

Undeveloped acreage, as used herein, means acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether or not that acreage contains proven reserves, but does not include undrilled acreage held by production under the terms of a lease. Select undeveloped acreage at the Expansion Asset and Demo Asset contains proved reserves. 

 

 

All of the Company’s acreage is located in the Province of Alberta and is held indefinitely. There are no near-term undeveloped acreage expirations. The following table shows the Company’s total gross and net mineral rights acreage by asset location as of December 31, 2023:

 

Developed Acreage

 

Area		Property		Interest (%)				Gross Area (Hectares)				Net Area (Hectares)
Hangingstone		Expansion			75				361				271
Hangingstone		Demo			100				242				242
Total Developed Acreage									604				513

 

Undeveloped Acreage

 

Area		Property		Interest (%)				Gross Area (Hectares)				Net Area (Hectares)
Hangingstone		Expansion			75				17,369				13,027
Hangingstone		Demo			100				732				732
Corner		Corner North			100				6,516				6,516
Corner		Corner South			12				12,004				1,440
Chard		Chard North			100				7,318				7,318
Chard		Chard West			25				7,800				1,950
Chard		Chard East			25				7,250				1,812
Chard		Chard			25				8,031				2,008
Hangingstone		Gas			100				1,024				1,024
Liege		Liege			25				13,824				3,456
Total Undeveloped Acreage									81,867				39,283

 

Well Information  

 

The Company had 54 gross (46 net) horizontal wells capable of producing bitumen as of each of the years ended December 31, 2023, 2022 and 2021. As of December 31, 2023, the Company had drilled eight new redevelopment infill (“Refill”) wells and drilled two additional Refill wells as of February 2024, to complete its initial ten well program at the Expansion Asset, with the intention of producing bitumen. Refill wells utilize an existing producer wellhead and casing to reduce costs associated with drilling and facilities, with an acceleration of first production anticipated, relative to producing from traditional infill wells. The addition of a Refill well does not change well count as the process utilizes an existing well head and infrastructure. The Company expects that Refill wells will enhance the total bitumen recovery of previously drilled and steamed well pairs, with marginal incremental capital expenditure and minimal geological risk. The SAGD industry has a long-term track record of consistently and effectively producing incremental pre-heated bitumen volumes from infill and Refill wells.

 

The Company has no exploratory wells and did not drill any dry exploratory or development wells in the last three fiscal years.

 

 

As evaluated by McDaniel as of December 31, 2023, proved undeveloped reserves are from planned well locations in the Alberta Energy Regulator (“AER”) approved development area and are within three miles from existing bitumen producing wells at the Demo Asset and Expansion Asset. Development plans include new well pairs that consist of horizontal steam injector wells placed approximately 15 feet (5 meters) above horizontal bitumen production wells in a reservoir that has a minimum of 32 feet (10 meters) of average bitumen net pay and up to over 100 feet (30 meters). Spacing between well pairs at both the Demo Asset and Expansion Asset is approximately 325 feet (100 meters). Future development plans include drilling infill horizontal bitumen production wells between existing and new well pairs.

 

In order to make the most efficient use of the Company’s steam generating and oil treating facilities, the drilling and steaming of new wells would take place over 30 years. Development of the Company’s proved undeveloped reserves will take place in an orderly manner as additional well pairs and infills are drilled to use available steam when existing well pairs reach the end of their steam injection phase. The forecasted production of the Company’s proved reserves extends approximately 31 years.

 

 Seasonality of the Business

 

The level of activity in the Canadian oil and gas industry is influenced by seasonal weather patterns. A mild winter or wet spring may result in limited access and, as a result, reduced operations or a cessation of operations. The Company operates in an area of extreme weather conditions. Cold temperatures affect the properties of diluent and bitumen and may contribute to production difficulties, delivery problems and increased operating costs. Winter driving conditions in Northern Alberta can affect truck transportation of the Company’s bitumen, and cold weather can lead to equipment failure and slowdown. Warmer temperatures can lead to equipment failures and slowdowns not only at the Expansion Asset and Demo Asset but can also affect delivery of operating inputs such as natural gas and cause power price surges.

 

Municipalities and provincial transportation departments enforce road bans that restrict the movement of drilling rigs and other heavy equipment during periods of wet weather, thereby reducing activity levels. Also, certain oil and natural gas producing areas are located in areas that are inaccessible other than during the winter months because the ground surrounding the sites in these areas consists of swampy terrain. Seasonal factors and unexpected weather patterns may lead to increases or declines in exploration and production activity as well as increases or declines in the demand for the goods the Company produces.

 

Raw Materials

 

Production from in-situ oil sands reservoirs using SAGD processes has various inputs including natural gas, power and water to create steam, and condensate as diluent for blending with the bitumen in order to transport the bitumen production via pipeline.

 

Pursuant to the Expansion Diluent Agreement (as defined below), the Petroleum Marketer has agreed to sell to Greenfire all of the condensate required for Greenfire’s blending with its bitumen production to satisfy pipeline specification. Condensate is locally sourced at Edmonton and delivered to the Expansion Asset via the Inter Pipeline Polaris Pipeline. Production from the Expansion Asset is diluted with condensate to meet pipeline specifications.

 

The Company produces non-diluted bitumen at the Demo Asset. That is a product that is relatively unique in Alberta’s oilsands. Historically, each barrel of production was transported from the Demo Asset to several locations, with optionality to deliver to both pipeline and rail sales points, depending on the economics of each option at the time of sale. At pipeline connected sales points, Demo Asset bitumen is blended with diluent to reach pipeline specifications. At rail connected terminals, Demo Asset bitumen is moved into railcars and transported to its final sales destination, generally without the need to blend with diluent.

 

 

With the construction of the truck offloading facility at the Expansion Asset, most of the bitumen production from the Demo Asset is trucked to the Expansion Asset, blended with diluent and sold into the pipeline. However, from time to time, the Company may choose to transport bitumen from the Demo Asset to other pipeline sales points or by rail if the economics of selling non-diluted bitumen at those sales points are relatively attractive.

 

Natural gas is a primary energy input cost for the Company. Natural gas is used as fuel to generate steam for SAGD operations. The Company purchases natural gas in Alberta from the AECO system. AECO is the Western Canadian benchmark for natural gas. The AECO Hub gas storage facility in southern Alberta is one of the largest natural gas hubs in North America, with its substantial production and storage capability and extensive network of export pipelines. Generally, natural gas is shipped to the Company’s systems via the NOVA Gas Transmission Ltd. system.

 

The Company sources water for its SAGD operations from water wells. Condensed steam emulsion is recovered with bitumen from wells, which are processed at the surface to separate the bitumen from water. The recovered water is treated and recycled back into the process. The Company has a water recycling rate of 94%.

 

Electricity necessary for the operation of the Expansion Asset and Demo Asset is sourced from the Alberta power grid and the Company pays market prices for electricity.

 

Marketing

 

The Company has entered into three separate marketing agreements with the Petroleum Marketer as described under the heading “Business — Material Contracts, Liabilities and Indebtedness — Marketing Agreements.” The Petroleum Marketer purchases all of the Company’s bitumen and blend and provides and arranges transportation via trucks and pipelines for the Company’s products in exchange for a marketing fee.

 

Customer Base and Principal Markets

 

The Company’s revenue from contracts with customers primarily consists of non-diluted and diluted bitumen sales. All of the Company’s diluted and non-diluted bitumen production is produced by the Company in Alberta and is sold to the Petroleum Marketer. As such, substantially all of the Company’s total revenue in the last three fiscal years was from Alberta and provided by the Petroleum Marketer. For a description of the terms of the marketing agreements with the Petroleum Marketer see subsection “—Legal — Material Contracts, Liabilities and Indebtedness — Marketing Agreements” below.

 

Principal Capital Expenditures

 

The Company’s principal capital expenditures (excluding capital expenditures relating to the acquisitions of the Demo Asset and Expansion Asset) are set forth in the table below:

 

		Year ended December 31,
(CAD$ in thousands)		2023				2022				2021
Drilling and completion			22,501				6,942				17
Equipment, facilities and pipelines			7,877				23,329				3,151
Workovers and maintenance capital			1,974				204				831
Geological & geophysical (G&G)			25				(9	)			64
Capitalized and other			1,051				9,126				531
Total Capital expenditures			33,428				39,592				4,594

 

 

As at December 31, 2023, the Company had planned approximately CAD$85.2 million of further net capital expenditures in 2024 related to its Refill drilling program and facility optimization activities for the Expansion Asset and Demo Asset, which are described under the heading “—Property, Plant and Equipment Expenditures” below. The Company anticipates satisfying these capital commitments with funds from operations.

  

Maintenance

 

Partial outages are a recurring event for the Company, typically taking place annually around September. However, steps have been taken to mitigate their impact on production. Pipeline bypasses and tie-in points were installed during the most recent major turnaround in September 2022. These improvements are expected to reduce the annual maintenance-related production impacts going forward. As a result, the major plant maintenance requiring a full plant shutdown is now scheduled every four years, with the next one planned for 2026.

 

Operations

 

The following section describes the Company’s: (i) reserves; (ii) operational processes and systems and (iii) cost efficiency of operation.

 

Reserves

 

The Company’s 2023 year-end reserves evaluations were conducted by McDaniel with an effective date of December 31, 2023. McDaniel evaluated 100% of the Company’s reserves, which are all located in the Province of Alberta, Canada. First established in 1955, McDaniel has a reputation for consistent and reliable oil and gas consulting services, providing third party reserve reports and certifications for over 60 years with a team of highly skilled and qualified engineers and geoscientists. The technical person primarily responsible for preparing and overseeing the estimates of the Company’s annual reserves evaluation is Mr. Jared Wynveen, the Executive Vice President of McDaniel. Mr. Wynveen graduated from Queen’s University in 2006 with a Bachelor of Science degree in Mechanical Engineering. A professional member of the Association of Professional Engineers and Geoscientists of Alberta (“APEGA”) (Permit No. 3145), Mr. Wynveen brings over 15 years of experience in oil and gas reservoir studies and evaluations. Mr. Wynveen’s education, training and technical expertise along with his years of experience within the oil and gas industry, more than qualify him in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information as set forth by the Society of Petroleum Engineers. Mr. Wynveen is proficient in applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.

 

The primary technical person responsible for overseeing the reserve estimates at the Company is Ms. Crystal Park, the Senior Vice-President, Commercial. Ms. Park graduated from the University of Alberta in 1998 with a Bachelor of Science degree in Chemical Engineering. Ms. Park also holds a Master of Business Administration with a dual specialization in Finance and Global Energy Management from the Haskayne Faculty of the University of Calgary. A professional member with APEGA (Permit No. 66172) since her enrollment in 1998, Ms. Park has over 25 years of related oil and gas industry experience including reserves evaluation and coordination at companies such as AJM Deloitte, Sproule Associates Limited, Enerplus Corporation, and Sunshine Oilsands Ltd. Ms. Park is proficient in applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.

 

The Company’s internal staff of engineers, geoscience professionals, operations, land, finance and accounting, and, prior to Greenfire’s annual reserves process, marketing personnel, work closely together to ensure the integrity, accuracy and timeliness of data to furnish to, and work with, our independent reserve engineers in their reserve evaluation process. Our internal reserves process follows a rigorous workflow where the multidisciplinary teams come together to vet model assumptions and input before the technical team meets with the independent reserve engineers to review our properties and discuss methods and assumptions used to prepare reserve estimates.

 

 

Our internal controls over reserve estimates include reconciliation and review controls, including: an internal review of assumptions used in the estimation; senior executive approval on data inputs provided by the technical staff; reconciliations between the evaluation report and the data provided by the technical staff; and a thorough internal review performed by both management and the executive team over the independent reserve engineers’ evaluation of our oil and gas reserves, prior to the presentation of those reserve estimates to the Company Board.

  

The Company has implemented certain oversight, review and internal control processes regarding its reserve evaluation, including requiring approval from the Company Board. The Company Board performs the oversight role of the Company’s oil and gas reserves. On a yearly basis, the Company Board will meet with the Company’s management, where the reserves evaluation performed by the independent engineering firm is presented and the Company Board provides its review, analysis and approval of that evaluation.

 

We establish our proved reserves estimates using standard geological and engineering technologies and computational methods, which are generally accepted by the petroleum industry. We primarily prepare proved reserves additions by analogy using type curves that are based on volumetric and decline curve analysis of producing wells in our and analogous reservoirs. Reasonable certainty is further established over our proved reserve estimates by using one or more of the following methods: geological and geophysical information to establish reservoir continuity between penetrations, analytical and numerical simulations, or other proprietary technical and statistical methods.

 

The technologies employed by McDaniel use standard engineering methods that are generally accepted by the petroleum industry. The Company employs well logs, production tests, seismic and core data, as well as historical and analogous production trends to develop proved reserves estimations.

 

For the purposes of determining proved oil and natural gas reserves under SEC requirements as at December 31, 2023, 2022 and 2021, the Company used the 12-month average price, defined by the SEC as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period.

 

McDaniel prepared the annual reports on the reserves of the Company as of December 31, 2023, 2022 and 2021, respectively, which were prepared in accordance with guidelines specified in Item 1202(a)(8) of Regulation S-K and in conformity with Rule 4-10(a) of Regulation S-X, and are to be used for inclusion in certain filings of the SEC; such reports are filed as Exhibits 99.1, 99.2 and 99.3 to the registration statement of which this prospectus forms a part.

 

Employees and Training

 

As at December 31, 2023, the Company had 175 full and part-time employees (with 39 of those employees at the Company’s principal office in Calgary and the remaining employees on site at the Expansion Asset and/or the Demo Asset), compared to 165 as at December 31, 2022 (with 35 of those employees at the Company’s head office in Calgary and the remaining on site at the Expansion Asset and Demo Asset). All employees were located in Canada, and all pertained to the Company’s core business activity of producing bitumen by SAGD processes from in-situ oil sands reservoirs.

 

Operational Processes and Systems

 

To assist in managing fluctuations in commodity pricing, the Company seeks to implement cost efficiencies across all of its operations.

 

Since acquiring the Demo Asset and Expansion Asset in 2021, the Company has sought to improve its operating and transportation expenses and pursue low risk opportunities to further enhance production with limited capital expenditures. The costs of energy and goods and services have increased over the period that the Company has operated the Demo Asset and Expansion Asset. The Company has managed its operating expenses by increasing water handling, surface facility debottlenecking and optimizing workforce and operating processes.

 

 

Capital Cost Efficiencies

 

Since acquiring the Demo Asset and Expansion Asset in 2021, the Company has implemented a modest capital expenditure program focused on surface debottlenecking programs at the Expansion Asset and Demo Asset to enable additional potential capacity for production growth at both existing facilities. As of December 31, 2023, the Company commissioned water disposal wells at both sites to improve water handling capability. These wells are in the process of being conditioned for maximum water disposal which will reduce off site waste disposal expenses. The Company believes that increasing water disposal capability at the Demo Asset and Expansion Asset will optimize fluid handling capacity at the sites which may lead to increased production. As of December 31, 2023, the Company had only approximately 39 of its 56 drilled wells pairs currently online.

 

Redevelopment Infill Wells, NCG, and Disposal Wells.

 

The Company continued to progress its production growth initiatives at the Expansion Asset, including drilling extended reach Refill wells and implementing surface facility debottlenecking projects to restore higher reservoir pressure. The Company successfully drilled eight extended reach Refill wells in 2023 as part of the planned 10 well program, which was successfully completed in first quarter of 2024. These ten extended reach Refill wells had average horizontal lengths of approximately one mile (approximately 1,600 meters). At year-end 2023, five extended reach Refill wells have been on production for over two months at the Expansion Asset and have realized an average monthly production rate of approximately 1,500 bbls/d per well, on a 100% working interest basis, in the second month of production. Greenfire successfully executed multiple NCG debottlenecking initiatives at the Expansion Asset in the second half of 2023, including the commissioning of an NCG compressor in the fourth quarter of 2023 as planned. These completed debottlenecking initiatives have enabled the Company to deliver NCG at higher and more consistent rates for co-injection. With heightened rates of NCG co-injection sustained, the Company expects that higher reservoir pressure will be restored at the Expansion Asset around mid-2024, which management anticipates will support increased production rates.

 

At the Demo Asset, the Company’s disposal well has been temporarily shut-in since the beginning of October 2023. Remediation work for this well is now complete, and the Company is awaiting regulatory approval to recommence disposal operations, which is expected to increase bitumen production by approximately 1,000 bbls/d at the Demo Asset

 

Additional future drilling plans for the Company are expected to remain focused on exploiting the Company’s existing inventory of pre-heated bitumen locations at the Hangingstone Facilities with Refill wells, which, combined with surface facility optimizations, is anticipated to result in a material increase in production and profitability at the Hangingstone Facilities. To provide cost and service availability certainty for the Company’s planned multi-year drilling program, the Company entered into a two-year take-or-pay drilling commitment with an established SAGD drilling contractor in Western Canada in 2023.

 

Sustainability

 

The Company seeks to do business in a responsible, safe and sustainable manner. The Company seeks to continue to improve and strengthen its strategies for air quality, emissions, water, waste, land and biodiversity, risk management, health and safety and First Nations relations. These areas are critical based on their significant impact to building a sustainable company and the Company’s ESG framework. Since the Company acquired the Demo Asset and Expansion Asset, it has focused on optimization efficiencies to improve carbon intensity and reduce waste. To date, the Company’s sustainability program has been focused on the following goals:

 

●

Improve Assets Carbon Emission Intensity — Optimization and efficiency gains at the Expansion Asset and Demo Asset are reducing carbon emission intensity per barrel.

  

 

●

Reduced Diluent Use and Waste — More attentive operations team and processes to operate equipment at enhanced conditions to reduce diluent loss and usage.

 

●

Transportation and Travel Mileage — Construction of a truck offloading facility at the Expansion Asset to accept trucked production volumes from the Demo Asset has reduced approximately 620 miles of trucking per truck load of bitumen production from the Demo Asset.

 

●

Water Quality and Recycling — The Company operates with higher quality boiler feed water and water quality standards relative to the previous operator. The Company has improved its water recycling performance and is currently recycling 94% of the water used in its steam production operations with minimal water loss replacements.

 

●

Fugitive Emissions Monitoring — Annual fugitive emissions studies to proactively identify and rectify any potential leaks.

 

The Company intends to continue to evolve its approach to sustainability and to developing ESG focus areas to bring visibility to what the Company feels are key priorities as a Canadian oil sands producer. 

  

Climate, Air & Emissions

 

The Company is committed to evaluating opportunities to reduce its Scope 1 and Scope 2 greenhouse gas emissions in line with the Canadian government’s national commitments and is evaluating process optimizations and carbon reduction technologies that have the potential to deliver localized solutions.

 

The Company is constantly monitoring the air quality at and adjacent to its Hangingstone Facilities. The results from this monitoring consistently show compliance with Alberta and Canadian air quality objectives. For 2022 and through 2023, the Company reported zero contraventions with its air quality monitoring.

  

Water

 

The Company is actively working to reduce its reliance on non-saline water by optimizing its usage at its Hangingstone Facilities. By recycling 94% used in its steam production operations, the Company minimizes the need for non-saline water to be used to make-up any water shortages within its industrial process. All the Company’s non-saline water is conveyed via dedicated underground pipelines, eliminating the need for trucks and their corresponding emissions.

 

Indigenous Relations

 

The Company recognizes the rights of First Nations, Metis, and Inuit peoples and is committed to working collaboratively with First Nation communities in an atmosphere of integrity, honor and respect. The Company continues its collaborative participation in the Indigenous Advisory Group (the “IAG”). Founded by JACOS, the IAG comprises members from various local First Nation communities in the Fort McMurray region, providing valuable traditional knowledge and ensuring the Company upholds the highest possible standards of environmental protection and monitoring. The IAG is a critical instrument in guiding engagement with the local First Nation communities.

 

The Company also provides scholarships for local First Nations students to train in environmental monitoring programs. These programs increase access to related future employment opportunities, help the development of First Nation entrepreneurial enterprises, promote the transmission of First Nation knowledge within local communities and enhance cultural connections to the land.

 

The Company is committed to the ongoing development of trust-based equitable and beneficial partnerships with local First Nation communities.

 

 

Land & Biodiversity

 

The Company seeks to minimize its land disturbances by practicing avoidance, using existing land disturbances for future development and reclaiming end-of-life site to equivalent land capacity. Additionally, the Company supports a road reclamation research project at its Demo Asset that is implementing innovative solutions to the remediation and reclamation of local swamps/bogs, commonly referred to as muskeg.

 

Risk Management

 

The Company’s operating team identifies operational risks to the Company in order to implement systems and execute procedures to adequately address those risks and reduce their impact on the Company. This process has been driven on a team basis with each individual team (i.e., Health and Safety, Facilities, or Drilling) identifying, assessing and managing their own operational risks with associated risk matrices. The Company believes that risks related to climate change and the transition to a lower carbon economy will increasingly impact the Company. A net zero economy, supported by the Canadian Net-Zero Emissions Accountability Act (the “CNEAA”) and enacted through new policies, regulations, and standards is emerging in Canada. The Company continues to evaluate key emerging issues that may impact the Canadian energy sector as it moves to align with Canada’s Net-Zero 2050 ambitions.

 

Health & Safety

 

The health and safety of the Company’s personnel, including its employees, contractors, and the communities the Company works in, is its highest priority. The Company actively works to ensure that every employee and contractor is aware of, understands, and adheres to the Health and Safety Management System and associated policies. Safety is a shared responsibility of the Company’s leaders, employees, and contractors.

 

Legal

 

This section describes legal and other general matters relating to the Company, including insurance, material contracts entered into outside the ordinary course of business, property, plant and equipment, intellectual property rights and legal proceedings, investigations and other regulatory matters, industry conditions and government regulation.

 

Material Contracts, Liabilities and Indebtedness

 

Letters of Credit

 

On November 1, 2023, the Company entered into an unsecured $55.0 million letter of credit facility with a Canadian bank that is supported by a performance security guarantee from Export Development Canada (the “EDC Facility”). The EDC facility replaced the cash collateralized credit facility with the Petroleum Marketer.

 

2028 Notes

 

Concurrently with the Business Combination, the Company closed a private offering of $300 million aggregate principal amount of its 2028 Notes. The 2028 Notes mature on October 1, 2028, and have a fixed coupon of 12.0% per annum, paid semi-annually on April 1 and October 1 of each year, commencing on April 1, 2024. The 2028 Notes are secured by a lien on substantially all the assets of the Company and the guarantors. The Senior Credit Facility ranks senior to the 2028 Notes. For additional details of the terms of the 2028 Notes and the indenture governing the 2028 Notes, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Resources and Liquidity — Long Term Debt”.

 

 

Marketing Agreements

 

The Company has three separate marketing agreements with Petroleum Marketer. The Petroleum Marketer purchases substantially all of the Company’s bitumen and blend and provides and arranges transportation via trucks and pipelines for the Company’s products and condensate in exchange for a marketing fee.

 

In April 2021, in conjunction with GAC completing the acquisition of the Demo Asset, the Petroleum Marketer and GAC entered into a marketing agreement (the “Demo Marketing Agreement”) pursuant to which the Petroleum Marketer agreed to purchase 100% of monthly produced bitumen volumes from the Demo Asset. The Demo Marketing Agreement was subsequently amended to replace GAC with GROC. Under the Demo Marketing Agreement, the purchase price is the weighted average of all sales to third parties of the product purchased by Petroleum Marketer. The price is adjusted based on a number of other factors and there are certain other fees and payments payable by GROC. The Demo Marketing Agreement originally had a term expiring on April 1, 2024, but in December 2022, the Demo Marketing Agreement was amended to extend the term until April 1, 2025, in addition to making certain other amendments, all of which became effective upon the closing of the Business Combination. An additional amendment in September 2023 extended the term to April 1, 2026. Under the terms of the Demo Marketing Agreement, under certain circumstances if there is a “Change of Control” (as defined in the Demo Marketing Agreement) of Greenfire or GROC, there will be a fee payable by Greenfire to the Petroleum Marketer, however the Petroleum Marketer agreed to waive that fee for the Business Combination and the other transactions contemplated by the Business Combination Agreement.

 

In October 2021, in conjunction with Greenfire completing the JACOS Acquisition, the Petroleum Marketer and JACOS (as predecessor to GROC) entered into a marketing agreement (the “Expansion Marketing Agreement”) pursuant to which the Petroleum Marketer agreed to purchase 100% of monthly diluted bitumen volumes from the Expansion Asset. Under the Expansion Marketing Agreement, the purchase price is based on the weighted average of all sales to third parties of the product purchased by Petroleum Marketer. The price is adjusted based on a number of other factors and there are certain other fees and payments payable by Greenfire. The Expansion Marketing Agreement originally had a term expiring in October 2026, but in December 2022, the Expansion Marketing Agreement was amended to extend the term until October 2027, in addition to making certain other amendments. An additional amendment in September 2023 extended the term to October 2028. 

 

In October 2021, in conjunction with Greenfire completing the JACOS Acquisition, the Petroleum Marketer and JACOS (as predecessor to GROC) entered a marketing agreement (the “Expansion Diluent Agreement”) pursuant to which the Petroleum Marketer agreed to sell to Greenfire 100% of the condensate required for Greenfire’s blending with its bitumen production to satisfy pipeline specifications. Under the Expansion Diluent Agreement, the purchase price is based on the weighted average market price for condensate at the time. The price is adjusted based on a number of other factors, and there are certain other fees and payments payable by Greenfire under the terms of the Expansion Diluent Agreement. The Expansion Diluent Agreement originally had a term expiring in October 2026, but in December 2022, the Expansion Marketing Agreement was amended to extend the term until October 2027, in addition to making certain other amendments. An additional amendment in September 2023 extended the term to October 2028.

 

Risk Management Contracts

 

As part of the Company’s normal operations, it is exposed to volatility in commodity prices. In an effort to manage these exposures, the Company uses various financial risk management contracts and physical sales contracts that are intended to reduce the volatility in the Company’s cash flow, as well as to ensure the Company’s ability to service and repay indebtedness.

 

The 2028 Notes and the Credit Agreement each require the Company, on or prior to the last day of each calendar month, to enter into and maintain at all times hedge arrangements (the “Hedges”) for the consecutive 12-calendar month period commencing from November 1, 2023, in respect of Hydrocarbons, the net notional volumes for no less than 50% of the Company’s reasonably expected output of production of Hydrocarbons; provided, however, that the Hedges shall have a floor price equal to the greater of (i) at least 80% of the price of WTI for such month being hedged and (ii) $55/bbl for such month being hedged. Notwithstanding the foregoing:

 

●

in the event that (i) the price for WTI is equal to or less than $55/bbl for such month being hedged or (ii) the Company is unable to obtain reasonable additional credit to enter into such hedge arrangement, having used its best efforts to obtain such credit, for such month being hedged, the Company shall not be required to enter into any hedge arrangement for such month;

 

●

the Company will not be required to enter into any Hedges for any period if, at the beginning of the applicable period, less than $100 million of the aggregate principal amount of the 2028 Notes originally issued remain outstanding; and

 

●

the Company will be permitted to monetize any existing hedging obligations for any period if less than $100 million of the aggregate principal amount of the 2028 Notes originally issued remain outstanding.

 

Insurance

 

The Company maintains insurance coverage for damage to its commercial property, third-party liability, and employers’ liability, sudden and accidental pollution and other types of loss or damage. The insurance coverage is subject to deductibles that must be met prior to any recovery. Additionally, the insurance is subject to exclusions and limitations, and such coverage may not adequately protect it against liability from all potential consequences and damages. See “Risk Factors — Risks Relating to the Company’s Operations and the Oil and Gas Industry — Not all risks of conducting oil and natural gas opportunities are insurable and the occurrence of an uninsurable event may have a material adverse effect on the Company.”   

 

 

Legal Proceedings, Investigations and Other Regulatory Matters

 

From time to time, the Company is involved in litigation matters and may be subject to fines or regulatory audits, including in relation to health, safety, security and environment matters, arising in the ordinary course of business. The Company is not currently a party to any litigation, legal proceedings, investigations or other regulatory matters that are likely to have a material adverse effect on the Company’s business, financial position or profitability.

 

Industry Conditions and Governmental Regulation

 

Companies operating in the Canadian oil and gas industry are subject to extensive regulation and control of operations (including with respect to land tenure, exploration, development, production, refining and upgrading, transportation, and marketing) as a result of legislation enacted by various levels of government as well as with respect to the pricing and taxation of petroleum and natural gas through legislation enacted by, and agreements among, the federal and provincial governments of Canada, all of which should be carefully considered by investors in the Company. All current legislation is a matter of public record and the Company is unable to predict what additional legislation or amendments governments may enact in the future.

 

The Company’s assets and operations are regulated by administrative agencies that derive their authority from legislation enacted by the applicable level of government. Regulated aspects of the Company’s upstream oil and natural gas business include all manner of activities associated with the exploration for and production of oil and natural gas, including, among other matters: (i) permits for the drilling of wells and construction of related infrastructure; (ii) technical drilling and well requirements; (iii) permitted locations and access to operation sites; (iv) operating standards regarding conservation of produced substances and avoidance of waste, such as restricting flaring and venting; (v) minimizing environmental impacts, including by reducing emissions; (vi) storage, injection and disposal of substances associated with production operations; and (vii) the abandonment and reclamation of impacted sites. To conduct oil and natural gas operations and remain in good standing with the applicable federal or provincial regulatory scheme, producers must comply with applicable legislation, regulations, orders, directives and other directions (all of which are subject to governmental oversight, review and revision, from time to time). Compliance in this regard can be costly and a breach of the same may result in fines or other sanctions.

 

The discussion below outlines some of the principal aspects of the legislation, regulations, agreements, orders, directives and a summary of other pertinent conditions that impact the oil and gas industry in Western Canada, specifically in the province of Alberta where the Company’s assets are located. While these matters do not affect the Company’s operations in any manner that is materially different than the manner in which they affect other similarly sized industry participants with similar assets and operations, investors should consider such matters carefully.

 

Pricing and Marketing in Canada

 

Crude Oil

 

Oil producers are entitled to negotiate sales contracts directly with purchasers. As a result, macroeconomic and microeconomic market forces determine the price of oil. Worldwide supply and demand factors are the primary determinant of oil prices, but regional market and transportation issues also influence prices. The specific price that a producer receives will depend, in part, on oil quality, prices of competing products, distance to market, availability of transportation, value of refined products, supply/demand balance and contractual terms of sale.

 

In February 2022, Russian military forces invaded Ukraine. Ongoing military conflict between Russia and Ukraine has significantly impacted the supply of oil and gas from the region. In addition, certain countries including Canada and the United States have imposed strict financial and trade sanctions against Russia, which sanctions may have far reaching effects on the global economy in addition to the near term effects on Russia. The long-term impacts of the conflict remain uncertain.

 

 

On October 7, 2023, Hamas terrorists infiltrated Israel’s southern border from the Gaza Strip and conducted a series of attacks on civilian and military targets. Hamas also launched extensive rocket attacks on the Israeli population and industrial centers located along Israel’s border with the Gaza Strip and in other areas within the State of Israel. Following the attack, Israel’s security cabinet declared war against Hamas and the military campaign against these terrorist organizations has launched a series of responding attacks in Palestine. The outcome of the conflict has the potential to have wide-ranging consequences on the world economy and commodity prices, although the long-term impacts of the conflict remain uncertain.

 

Natural Gas

 

Negotiations between buyers and sellers determine the price of natural gas sold in intra-provincial, interprovincial and international trade. The price received by a natural gas producer depends, in part, on the price of competing natural gas supplies and other fuels, natural gas quality, distance to market, availability of transportation, length of contract term, weather conditions, supply/demand balance and other contractual terms of sale. Spot and future prices can also be influenced by supply and demand fundamentals on various trading platforms.

 

Natural Gas Liquids (“NGLs”)

 

The pricing of condensates and other NGLs such as ethane, butane and propane sold in intra-provincial, interprovincial and international trade is determined by negotiation between buyers and sellers. The profitability of NGLs extracted from natural gas is based on the products extracted being of greater economic value as separate commodities than as components of natural gas and therefore commanding higher prices. Such prices depend, in part, on the quality of the NGLs, price of competing chemical stock, distance to market, access to downstream transportation, length of contract term, supply/demand balance and other contractual terms of sale.

 

Exports from Canada

 

The Canada Energy Regulator (the “CER”) regulates the export of oil, natural gas and NGLs from Canada through the issuance of short-term orders and long-term export licenses pursuant to its authority under the Canadian Energy Regulator Act (the “CERA”). Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts continue to meet certain criteria prescribed by the CER and the federal government. The Company does not directly enter into contracts to export its production outside of Canada.

 

Transportation Constraints and Market Access

 

Capacity to transport production from Western Canada to Eastern Canada, the United States and other international markets has been, and continues to be, a major constraint on the exportation of crude oil, natural gas and NGLs. Although certain pipeline and other transportation projects have been announced or are underway, many proposed projects have been cancelled or delayed due to regulatory hurdles, court challenges and economic and socio-political factors. Due in part to growing production and a lack of new and expanded pipeline and rail infrastructure capacity, producers in Western Canada have experienced low commodity pricing relative to other markets in the last several years.

 

Oil Pipelines

 

Under Canadian constitutional law, the development and operation of interprovincial and international pipelines fall within the federal government’s jurisdiction and, under the CERA, new interprovincial and international pipelines require a federal regulatory review and Cabinet approval before they can proceed. However, recent years have seen a perceived lack of policy and regulatory certainty in this regard such that, even when projects are approved, they often face delays due to actions taken by provincial and municipal governments and legal opposition related to issues such as Indigenous rights and title, the government’s duty to consult and accommodate Indigenous peoples and the sufficiency of all relevant environmental review processes. Export pipelines from Canada to the United States face additional unpredictability as such pipelines also require approvals from several levels of government in the United States.

 

Producers negotiate with pipeline operators to transport their products to market on a firm or interruptible basis depending on the specific pipeline and the specific substance. Transportation availability is highly variable across different jurisdictions and regions. This variability can determine the nature of transportation commitments available, the number of potential customers and the price received.

 

Specific Pipeline Updates

 

The Trans Mountain Pipeline expansion received Cabinet approval in November 2016. Following a period of political opposition in British Columbia, the federal government acquired the Trans Mountain Pipeline in August 2018. Following the resolution of a number of legal challenges and a second regulatory hearing, construction on the Trans Mountain Pipeline expansion commenced in late 2019. Earlier estimated at $12.6 billion, Trans Mountain increased the project budget to $30.9 billion in March 2023. The pipeline is expected to be in service in 2024, an extension from Trans Mountain’s initial December 2022 estimate. The budget increase and in-service date delay have been attributed to, among other things, high global inflation, global supply chain challenges, the widespread flooding in British Columbia in late 2021, and unexpected major archeological discoveries.

 

 

In November 2020, the Attorney General of Michigan filed a lawsuit to terminate an easement that allows the Enbridge Line 5 pipeline system to operate below the Straits of Mackinac, attempting to force the lines comprising this segment of the pipeline system to be shut down. Enbridge Inc. stated in January 2021 that it intends to defy the shut down order, as the dual pipelines are in full compliance with U.S. federal safety standards. The Government of Canada invoked a 1977 treaty with the United States on October 4, 2021, triggering bilateral negotiations over the pipeline. In August 2022, the United States District Court for Western Michigan rejected the Attorney General of Michigan’s lawsuit efforts to move the dispute to Michigan state court citing important federal interests at stake in having the dispute heard in federal court. Michigan’s Attorney General appealed that decision, and the United States District Court granted the motion to appeal in February 2023.

 

In September 2022, the District Court of Wisconsin ruled in favor of the Bad River Band in its dispute with Enbridge Inc. over the Enbridge Line 5 pipeline system in that state. Stopping short of ordering the system to be shut down, the Court ruled that the Bad River Band is entitled to financial compensation, and ordered Enbridge Inc. to reroute the pipeline around Bad River territory within five years.

 

In December 2023, the Canada Energy Regulator denied Trans Mountain’s pipeline variance application for the Mountain 3 Horizontal Directional Drill (located in the Fraser Valley), however in January 2024, it approved the request with conditions, meaning the Trans Mountain Pipeline expansion can now proceed toward completion in compliance with the order.

 

Natural Gas and Liquefied Natural Gas (“LNG”)

 

Natural gas prices in Western Canada have been constrained in recent years due to increasing North American supply, limited access to markets and limited storage capacity. Companies that secure firm access to infrastructure to transport their natural gas production out of Western Canada may be able to access more markets and obtain better pricing. Companies without firm access may be forced to accept spot pricing in Western Canada for their natural gas, which is generally lower than the prices received in other North American regions. The Company consumes natural gas for its SAGD operations and has entered into firm transportation delivery contracts to mitigate its risk of not receiving sufficient amounts of natural gas for its operations.

 

Required repairs or upgrades to existing pipeline systems in Western Canada have also led to reduced capacity and apportionment of access, the effects of which have been exacerbated by storage limitations. In October 2020, TC Energy Corporation received federal approval to expand the Nova Gas Transmission Line system (the “NGTL System”) and the expanded NGTL System was completed in April 2022.

 

Specific Pipeline and Proposed LNG Export Terminal Updates

 

While a number of LNG export plants have been proposed in Canada, regulatory and legal uncertainty, social and political opposition and changing market conditions have resulted in the cancellation or delay of many of these projects. Nonetheless, in October 2018, the joint venture partners of the LNG Canada export terminal announced a positive final investment decision. Once complete, the project will allow producers in northeastern British Columbia to transport natural gas to the LNG Canada liquefaction facility and export terminal in Kitimat, British Columbia via the Coastal GasLink pipeline (the “CGL Pipeline”). With more Alberta and northeastern British Columbia gas egressing through the CGL Pipeline, the NGTL System will have more capacity, resulting in a narrower price relationship between the AECO and New York Mercantile Exchange gas prices. The Company anticipates it will see higher AECO pricing, more in line with the United States market, and generally, higher gas prices overall. Phase 1 of the LNG Canada project reached 70% completion in October 2022, with a completion target of 2025.

 

In May 2020, TC Energy Corporation sold a 65% equity interest in the CGL Pipeline to investment companies KKR & Co Inc. and Alberta Investment Management Corporation, while remaining the pipeline operator. Despite its regulatory approval, the CGL Pipeline has faced legal and social opposition. For example, protests involving the Hereditary Chiefs of the Wet’suwet’en First Nation and their supporters have delayed construction activities on the CGL Pipeline, although construction is proceeding. As of November 2022, construction of the CGL Pipeline is approximately 80% complete.

 

Woodfibre LNG Limited (“Woodfire LNG”) issued a notice to proceed with construction of the Woodfibre LNG project to its prime contractor in April 2022. The Woodfibre LNG project is located near Squamish, British Columbia, and upon completion will produce approximately 2.1 million tonnes of LNG per year. Major construction is set to commence in 2023, with substantial completion of the project expected in late 2027. In November 2022, Enbridge Inc. completed a transaction with Pacific Energy Corporation Limited, the owner of Woodfibre LNG Limited, to retain a 30% ownership stake in the project.

 

In addition to LNG Canada, the CGL Pipeline and the Woodfibre LNG project, a number of other LNG projects are underway at varying stages of progress, though none have reached a positive final investment decision.

 

 

Marine Tankers

 

The Oil Tanker Moratorium Act (Canada), which was enacted in June 2019, imposes a ban on tanker traffic transporting crude oil or persistent crude oil products in excess of 12,500 metric tonnes to and from ports located along British Columbia’s north coast. The ban may prevent pipelines from being built to, and export terminals from being located on, the portion of the British Columbia coast subject to the moratorium.

 

International Trade Agreements

 

Canada is party to a number of international trade agreements with other countries around the world that generally provide for, among other things, preferential access to various international markets for certain Canadian export products. Examples of such trade agreements include the Comprehensive Economic and Trade Agreement (“CETA”), the Comprehensive and Progressive Agreement for Trans-Pacific Partnership and, most prominently, the United States Mexico Canada Agreement (the “USMCA”), which replaced the former North American Free Trade Agreement (“NAFTA”) on July 1, 2020. Because the United States remains Canada’s primary trading partner and the largest international market for the export of oil, natural gas and NGLs from Canada, the implementation of the USMCA could impact Western Canada’s oil and gas industry as a whole, including the Company’s business.

 

While the proportionality rules in Article 605 of NAFTA previously prevented Canada from implementing policies that limit exports to the United States and Mexico relative to the total supply produced in Canada, the USMCA does not contain the same proportionality requirements. This may allow Canadian producers to develop a more diversified export portfolio than was possible under NAFTA, subject to the construction of infrastructure allowing more Canadian production to reach Eastern Canada, Asia and Europe.

 

Canada is also party to CETA, which provides for duty-free, quota-free market access for Canadian crude oil and natural gas products to the European Union. Following the United Kingdom’s departure from the European Union on January 31, 2020, the United Kingdom and Canada entered into the Canada-United Kingdom Trade Continuity Agreement (“CUKTCA”), which replicates CETA on a bilateral basis to maintain the status quo of the Canada-United Kingdom trade relationship.

 

While it is uncertain what effect CETA, CUKTCA or any other trade agreements will have on the petroleum and natural gas industry in Canada, the lack of available infrastructure for the offshore export of crude oil and natural gas may limit the ability of Canadian crude oil and natural gas producers to benefit from such trade agreements. 

 

Land Tenure

 

Mineral rights

 

With the exception of Manitoba, each provincial government in Western Canada owns most of the mineral rights to the oil and natural gas located within their respective provincial borders. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licenses and permits (collectively, “leases”) for varying terms, and on conditions set forth in provincial legislation, including requirements to perform specific work or make payments in lieu thereof. The provincial governments in Western Canada conduct regular land sales where oil and natural gas companies bid for the leases necessary to explore for and produce oil and natural gas owned by the respective provincial governments. These leases generally have fixed terms, but they can be continued beyond their initial terms if the necessary conditions are satisfied.

 

  

In response to COVID-19, the Government of Alberta, among others, announced measures to extend or continue Crown leases and permits that may have otherwise expired in the months following the implementation of pandemic response measures.

 

All of the provinces of Western Canada have implemented legislation providing for the reversion to the Crown of mineral rights to deep, non-productive geological formations at the conclusion of the primary term of a disposition. In addition, Alberta has a policy of “shallow rights reversion” which provides for the reversion to the Crown of mineral rights to shallow, non-productive geological formations for new leases and licenses.

 

In addition to Crown ownership of the rights to oil and natural gas, private ownership of oil and natural gas (i.e. freehold mineral lands) also exists in Western Canada. Rights to explore for and produce privately owned oil and natural gas are granted by a lease or other contract on such terms and conditions as may be negotiated between the owner of such mineral rights and companies seeking to explore for and/or develop oil and natural gas reserves.

 

An additional category of mineral rights ownership includes ownership by the Canadian federal government of some legacy mineral lands and within Indigenous reservations designated under the Indian Act (Canada). Indian Oil and Gas Canada, which is a federal government agency, manages subsurface and surface leases in consultation with applicable Indigenous peoples, for the exploration and production of oil and natural gas on Indigenous reservations through An Act to Amend the Indian Oil and Gas Act and the accompanying regulations.

 

Surface rights

 

To develop oil and natural gas resources, producers must also have access rights to the surface lands required to conduct operations. For Crown lands, surface access rights can be obtained directly from the government. For private lands, access rights can be negotiated with the landowner. Where an agreement cannot be reached, however, each province has developed its own process that producers can follow to obtain and maintain the surface access necessary to conduct operations throughout the lifespan of a well, including notification requirements and providing compensation to affected persons for lost land use and surface damage. Similar rules apply to facility and pipeline operators.

 

Royalties and Incentives

 

General

 

Each province has legislation and regulations in place to govern Crown royalties and establish the royalty rates that producers must pay in respect of the production of Crown resources. The royalty regime in a given province is in addition to applicable federal and provincial taxes and is a significant factor in the profitability of oil sands projects and oil, natural gas and NGL production. Royalties payable on production from lands where the Crown does not hold the mineral rights are negotiated between the mineral freehold owner and the lessee, though certain provincial taxes and other charges on production or revenues may be payable. Royalties from production on Crown lands are determined by provincial regulation and are generally calculated as a percentage of the value of production.

 

Producers and working interest owners of oil and natural gas rights may create additional royalties or royalty-like interests, such as overriding royalties, net profits interests and net carried interests, through private transactions, the terms of which are subject to negotiation.

 

Occasionally, both the federal government and the provincial governments in Western Canada create incentive programs for the oil and gas industry. These programs often provide for volume-based incentives, royalty rate reductions, royalty holidays or royalty tax credits and may be introduced when commodity prices are low to encourage exploration and development activity. Governments may also introduce incentive programs to encourage producers to prioritize certain kinds of development or use technologies that may enhance or improve recovery of oil, natural gas and NGLs, or improve environmental performance. In addition, from time-to-time, including during the COVID-19 pandemic, the federal government creates incentives and other financial aid programs intended to assist businesses operating in the oil and gas industry as well as other industries in Canada.

 

Alberta

 

Crown royalties

 

In Alberta, oil and natural gas producers are responsible for calculating their royalty rate on an ongoing basis. The Crown’s royalty share of production is payable monthly and producers must submit their records showing the royalty calculation.

 

In 2016, the Government of Alberta adopted a modernized Crown royalty framework (the “Modernized Framework”) that applies to all conventional oil (i.e., not oil sands) and natural gas wells drilled after December 31, 2016 that produce Crown-owned resources. The previous royalty framework (the “Old Framework”) will continue to apply to wells producing Crown-owned resources that were drilled prior to January 1, 2017 until December 31, 2026, following which time they will become subject to the Modernized Framework. The Royalty Guarantee Act (Alberta), came into effect on July 18, 2019, and provides that no major changes will be made to the current oil and natural gas royalty structure for a period of at least 10 years.

 

 

Royalties on production from wells subject to the Modernized Framework are determined on a “revenue-minus-costs” basis. The cost component is based on a drilling and completion cost allowance formula that relies, in part, on the industry’s average drilling and completion costs, determined annually by the Alberta Energy Regulator (the “AER”), and incorporates information specific to each well such as vertical depth and lateral length.

 

Under the Modernized Framework, producers initially pay a flat royalty of 5% on production revenue from each producing well until payout, which is the point at which cumulative gross revenues from the well equals the applicable Drilling and Completion Cost Allowance. After payout, producers pay an increased royalty of up to 40% that will vary depending on the nature of the resource and market prices. Once the rate of production from a well is too low to sustain the full royalty burden, its royalty rate is gradually adjusted downward as production declines, eventually reaching a floor of 5%.

 

Under the Old Framework, royalty rates for conventional oil production can be as high as 40% and royalty rates for natural gas production can be as high as 36%. Similar to the Modernized Framework, these rates vary based on the nature of the resource and market prices. The natural gas royalty formula also provides for a reduction based on the measured depth of the well, as well as the acid gas content of the produced gas.

 

Oil sands production in Alberta is also subject to a royalty regime. Prior to payout of an oil sands project, the royalty is payable on gross revenues and, depending on market prices, the applicable rates are capped at 9%. After payout, the royalty payable is the greater of the gross revenue royalty (described above) and a net revenue royalty based on rates that range from 25% – 40%.

 

In addition to royalties, producers of oil and natural gas from Crown lands in Alberta are also required to pay annual rentals to the Government of Alberta.

 

Freehold royalties and taxes

 

Royalty rates for the production of privately owned oil and natural gas are negotiated between the producer and the resource owner. Producers and working interest participants may also pay additional royalties to parties other than the freehold mineral owner where such royalties are negotiated through private transactions.

 

The Government of Alberta levies annual freehold mineral taxes for production from freehold mineral lands. On average, the tax levied in Alberta is 4% of revenues reported from freehold mineral title properties and is payable by the registered owner of the mineral rights.

 

Incentives

 

The Government of Alberta has from time to time implemented drilling credits, incentives or transitional royalty programs to encourage crude oil and natural gas development and new drilling. In addition, the Government of Alberta has implemented certain initiatives intended to accelerate technological development and facilitate the development of unconventional resources, including coalbed methane wells, shale gas wells and horizontal crude oil and natural gas wells.

  

Regulatory Authorities and Environmental Regulation

 

General

 

The Canadian oil and gas industry is subject to environmental regulation under a variety of Canadian federal, provincial, territorial, and municipal laws and regulations, all of which are subject to governmental review and revision from time to time. Such regulations provide for, among other things, restrictions and prohibitions on the spill, release or emission of various substances produced in association with certain oil and gas industry operations, such as sulphur dioxide and nitrous oxide. The regulatory regimes set out the requirements with respect to oilfield waste handling and storage, habitat protection and the satisfactory operation, maintenance, abandonment and reclamation of well, facility and pipeline sites. Compliance with such regulations can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licenses and authorizations, civil liability, and the imposition of material fines and penalties. In addition, future changes to environmental legislation, including legislation related to air pollution and GHG emissions (typically measured in terms of their global warming potential and expressed in terms of carbon dioxide equivalent (“CO2e”)), may impose further requirements on operators and other companies in the oil and gas industry.

 

 

Federal

 

Canadian environmental regulation is the responsibility of both the federal and provincial governments. While provincial governments and their delegates are responsible for most environmental regulation, the federal government can regulate environmental matters where they impact matters of federal jurisdiction or when they arise from projects that are subject to federal jurisdiction, such as interprovincial transportation undertakings, including pipelines and railways, and activities carried out on federal lands. Where there is a direct conflict between federal and provincial environmental legislation in relation to the same matter, the federal law prevails.

 

The CERA and the Impact Assessment Act (the “IAA”) provide a number of important elements to the regulation of federally regulated major projects and their associated environmental assessments. The CERA separates the CER’s administrative and adjudicative functions. The CER has jurisdiction over matters such as the environmental and economic regulation of pipelines, transmission infrastructure and certain offshore renewable energy projects. In its adjudicative role, the CERA tasks the CER with reviewing applications for the development, construction and operation of many of these projects, culminating in their eventual abandonment.

 

The IAA relies on a designated project list as a trigger for a federal assessment. Designated projects that may have effects on matters within federal jurisdiction will generally require an impact assessment administered by the Impact Assessment Agency (the “IA Agency”) or, in the case of certain pipelines, a joint review panel comprised of members from the CER and the IA Agency. The impact assessment requires consideration of the project’s potential adverse effects and the overall societal impact that a project may have, both of which may include a consideration of, among other items, environmental, biophysical and socio-economic factors, climate change, and impacts to Indigenous rights. It also requires an expanded public interest assessment. Designated projects specific to the oil and gas industry include pipelines that require more than 45 miles of new rights of way and pipelines located in national parks, large scale in-situ oil sands projects not regulated by provincial GHG emissions caps and certain refining, processing and storage facilities.

 

The federal government has stated that an objective of the legislative changes was to improve decision certainty and turnaround times. Once a review or assessment is commenced under either the CERA or IAA, there are limits on the amount of time the relevant regulatory authority will have to issue its report and recommendation. Designated projects will go through a planning phase to determine the scope of the impact assessment, which the federal government has stated should provide more certainty as to the length of the full review process.

 

In May 2022, the Alberta Court of Appeal released its decision in response to the Government of Alberta’s submission of a reference question regarding the constitutionality of the IAA. The Court found the IAA to be unconstitutional in its entirety, stating that the legislation effectively granted the federal government a veto over projects that were wholly within provincial jurisdiction. The Government of Canada appealed the decision to the Supreme Court of Canada, which released its decision in October 2023, and held that the designated projects scheme created by the IAA was unconstitutional as ultra vires of federal jurisdiction. Specifically, the Supreme Court of Canada held that the assessment of projects under the IAA must be limited to the aspects of such projects that fall within federal jurisdiction (such as fisheries), and was overbroad as it attempted to regulate aspects of projects that otherwise fell within exclusive provincial jurisdiction. It remains to be seen how the Canadian federal government will respond to the Supreme Court’s decision, and the implications for the IAA.

 

Alberta

 

The AER is the principal regulator responsible for all energy resource development in Alberta. It derives its authority from the Responsible Energy Development Act and a number of related statutes including the Oil and Gas Conservation Act (the “OGCA”), the Oil Sands Conservation Act, the Pipeline Act, and the Environmental Protection and Enhancement Act. The AER is responsible for ensuring the safe, efficient, orderly and environmentally responsible development of hydrocarbon resources, including allocating and conserving water resources, managing public lands, and protecting the environment. The AER’s responsibilities exclude the functions of the Alberta Utilities Commission and the Land and Property Rights Tribunal, as well as the Alberta Ministry of Energy’s responsibility for mineral tenure.

 

The Government of Alberta relies on regional planning to accomplish its resource development goals. Its approach to natural resource management provides for engagement and consultation with stakeholders and the public and examines the cumulative impacts of development on the environment and communities. While the AER is the primary regulator for energy development, several other governmental departments and agencies may be involved in land use issues, including the Alberta Ministry of Environment and Parks, the Alberta Ministry of Energy, the Aboriginal Consultation Office and the Land Use Secretariat.

 

 

The Government of Alberta’s land-use policy sets out an approach to manage public and private land use and natural resource development in a manner that is consistent with the long-term economic, environmental and social goals of the province. It calls for the development of seven region-specific land-use plans in order to manage the combined impacts of existing and future land use within a specific region and the incorporation of a cumulative effects management approach into such plans.

 

The AER monitors seismic activity across Alberta to assess the risks associated with, and instances of, earthquakes induced by hydraulic fracturing. Hydraulic fracturing involves the injection of water, sand or other proppants and additives under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate oil and natural gas production. In recent years, hydraulic fracturing has been linked to increased seismicity in the areas in which hydraulic fracturing takes place, prompting regulatory authorities to investigate the practice further.

 

Liability Management

 

Alberta

 

The AER administers the Liability Management Framework (the “AD LM Framework”) and the Liability Management Rating Program (the “AB LMR Program”) to manage liability for most conventional upstream oil and natural gas wells, facilities and pipelines in Alberta. The AER is in the process of replacing the AB LMR Program with the AB LM Framework. This change was effected under key new AER directives in 2021, and further updates released in 2022. Broadly, the AB LM Framework is intended to provide a more holistic approach to liability management in Alberta, as the AER found that the more formulaic approach under the AB LMR Program did not necessarily indicate whether a company could meet its liability obligations. New developments under the AB LM Framework include a new Licensee Capability Assessment System (the “AB LCA”), a new Inventory Reduction Program (the “AB IR Program”), and a new Licensee Management Program (“AB LM Program”). Meanwhile, some programs under the AB LMR Program remain in effect, including the Oilfield Waste Liability Program (the “AB OWL Program”), the Large Facility Liability Management Program (the “AB LF Program”) and elements of the Licensee Liability Rating Program (the “AB LLR Program”). The mix between active programs under the AB LM Framework and the AB LMR Program highlights the transitional and dynamic nature of liability management in Alberta. While the province is moving towards the AB LM Framework and a more holistic approach to liability management, the AER has noted that this will be a gradual process that will take time to complete. In the meantime, the AB LMR Program continues to play an important role in Alberta’s liability management scheme.

 

Complementing the AB LM Framework and the AB LMR Program, Alberta’s OGCA establishes an orphan fund (the “Orphan Fund”) to help pay the costs to suspend, abandon, remediate and reclaim a well, facility or pipeline included in the AB LLR Program and the AB OWL Program if a licensee or working interest participant becomes insolvent or is unable to meet its obligations. Licensees in the AB LLR Program and the AB OWL Program fund the Orphan Fund through a levy administered by the AER. However, given the increase in orphaned oil and natural gas assets, the Government of Alberta has loaned the Orphan Fund approximately $335 million to carry out abandonment and reclamation work. In response to the COVID-19 pandemic, the Government of Alberta also covered $113 million in levy payments that licensees would otherwise have owed to the Orphan Fund, corresponding to the levy payments due for the first six months of the AER’s fiscal year. A separate orphan levy applies to persons holding licenses subject to the AB LF Program. Collectively, these programs are designed to minimize the risk to the Orphan Fund posed by the unfunded liabilities of licensees and to prevent the Government of Alberta from incurring costs to suspend, abandon, remediate and reclaim wells, facilities or pipelines.

 

The Supreme Court of Canada’s decision in Orphan Well Association v. Grant Thornton (also known as the “Redwater decision”), provides the backdrop for Alberta’s approach to liability management. As a result of the Redwater decision, receivers and trustees can no longer avoid the AER’s legislated authority to impose abandonment orders against licensees or to require a licensee to pay a security deposit before approving a license transfer when any such licensee is subject to formal insolvency proceedings. This means that insolvent estates can no longer disclaim assets that have reached the end of their productive lives (and therefore represent a net liability) in order to deal primarily with the remaining productive and valuable assets without first satisfying any abandonment and reclamation obligations associated with the insolvent estate’s assets. In April 2020, the Government of Alberta passed the Liabilities Management Statutes Amendment Act, which places the burden of a defunct licensee’s abandonment and reclamation obligations first on the defunct licensee’s working interest partners, and second, the AER may order the Orphan Fund to assume care and custody and accelerate the clean-up of wells or sites which do not have a responsible owner. These changes came into force in June 2020.

 

One important step in the shift to the AB LM Framework has been amendments to Directive 067: Eligibility Requirements for Acquiring and Holding Energy Licences and Approvals (“Directive 067”), which deals with licensee eligibility to operate wells and facilities. All license transfers and the granting of new well, facility and pipeline licenses in Alberta are subject to AER approval. Previously under the AB LMR Program, as a condition of transferring existing AER licenses, approvals and permits, all transfers required transferees to demonstrate that they had a liability management rating of 2.0 or higher immediately following the transfer. If transferees did not have the required rating, they would have to otherwise prove to the satisfaction of the AER that they could meet their abandonment and reclamation obligations, through means such as posting security or reducing their existing obligations. However, amendments from April 2021 to Directive 067 expanded the criteria for assessing licensee eligibility. Notably, the recent amendments increase requirements for financial disclosure, detail new requirements for when a licensee poses an “unreasonable risk” of orphaning assets, and adds additional general requirements for maintaining eligibility.

 

 

Alongside changes to Directive 067, the AER introduced Directive 088: Licensee Life-Cycle Management (“Directive 088”) in December 2021 under the AB LM Framework. Directive 088 replaces, to an extent, the AB LLR Program with the AB LCA. Whereas the AB LLR Program previously assessed a licensee based on a liability rating determined by the ratio of a licensee’s deemed asset value relative to the deemed liability value of its oil and gas wells and facilities, the AB LCA now considers a wider variety of factors and is intended to be a more comprehensive assessment of corporate health. Such factors are wide reaching and include: (i) a licensee’s financial health; (ii) its established total magnitude of liabilities; (iii) the remaining lifespan of its mineral resources and infrastructure; (iv) the management of its operations; (v) the rate of closure activities and spending, and pace of inactive liability growth; and (vi) its compliance with administrative and regulatory requirements. These various factors feed into a broader holistic assessment of a licensee under the AB LM Framework. In turn, that holistic assessment provides the basis for assessing risk posed by license transfers, as well as any security deposit that the AER may require from a licensee in the event that the regulator deems a licensee at risk of not being able to meet its liability obligations. However, the liability management rating under the LLR Program is still in effect for other liability management programs such as the AB OWL Program and the AB LF Program, and will remain in effect until a broadened scope of Directive 088 is phased in over time.

 

In addition to the AB LCA, Directive 088 also implemented other new liability management programs under the AB LM Framework. These include the AB LM Program and the AB IR Program. Under the AB LM Program the AER will continuously monitor licensees over the life cycle of a project. If, under the AB LM Program, the AER identifies a licensee as high risk, the regulator may employ various tools to ensure that a licensee meets its regulatory and liability obligations. In addition, under the AB IR Program the AER sets industry wide spending targets for abandonment and reclamation activities. Licensees are then assigned a mandatory licensee specific target based on the licensee’s proportion of provincial inactive liabilities and the licensee’s level of financial distress. Certain licensees may also elect to provide the AER with a security deposit in place of their closure spend target.

 

The Government of Alberta followed the announcement of the AB LM Framework with amendments to the Oil and Gas Conservation Rules and the Pipeline Rules in late 2020. The changes to these rules fall into three principal categories: (i) they introduce “closure” as a defined term, which captures both abandonment and reclamation; (ii) they expand the AER’s authority to initiate and supervise closure; and (iii) they permit qualifying third parties on whose property wells or facilities are located to request that licensees prepare a closure plan.

 

To address abandonment and reclamation liabilities in Alberta, the AER also implements, from time to time, programs intended to encourage the decommissioning, remediation and reclamation of inactive or marginal oil and natural gas infrastructure. In 2018, for example, the AER announced a voluntary area-based closure (the “ABC”) program. The ABC program is designed to reduce the cost of abandonment and reclamation operations though industry collaboration and economies of scale. Parties seeking to participate in the program must commit to an inactive liability reduction target to be met through closure work of inactive assets. To date, the Company has not had abandonment or reclamation activity that has been a part of the ABC program. The Company reviews planned closure activities on a regular basis and continually assesses whether any such activities would include participation in the ABC program in the future.

 

Climate Change Regulation

 

Climate change regulation at each of the international, federal and provincial levels has the potential to significantly affect the future of the oil and gas industry in Canada. These impacts are uncertain and it is not possible to predict what future policies, laws and regulations will entail. Any new laws and regulations (or additional requirements to existing laws and regulations) could have a material impact on the Company’s operations and cash flow.

  

Federal

 

Canada has been a signatory to the United Nations Framework Convention on Climate Change (the “UNFCCC”) since 1992. Since its inception, the UNFCCC has instigated numerous policy changes with respect to climate governance. On April 22, 2016, 197 countries, including Canada, signed the Paris Agreement, committing to prevent global temperatures from rising more than 2° Celsius above pre-industrial levels and to pursue efforts to limit this rise to no more than 1.5° Celsius. To date, 189 of the 197 parties to the UNFCCC have ratified the Paris Agreement, including Canada. In 2016, Canada committed to reducing its emissions by 30% below 2005 levels by 2030. In 2021, Canada updated its original commitment by pledging to reduce emissions by 40 – 45% below 2005 levels by 2030, and to net-zero by 2050.

 

During the course of the 2021 United Nations Climate Change Conference in Glasgow, Scotland, Canada’s Prime Minister Justin Trudeau made several pledges aimed at reducing Canada’s GHG emissions and environmental impact, including: (i) reducing methane emissions in the oil and gas sector to 75% of 2012 levels by 2030; (ii) ceasing export of thermal coal by 2030; (iii) imposing a cap on emissions from the oil and gas sector; (iv) halting direct public funding to the global fossil fuel sector by the end of 2022; and (v) committing that all new vehicles sold in the country will be zero-emission on or before 2040.

 

 

The Government of Canada released the Pan-Canadian Framework on Clean Growth and Climate Change in 2016, setting out a plan to meet the federal government’s 2030 emissions reduction targets. On June 21, 2018, the federal government enacted the Greenhouse Gas Pollution Pricing Act (the “GGPPA”), which came into force on January 1, 2019. This regime has two parts: an output-based pricing system (“OBPS”) for large industry (enabled by the Output-Based Pricing System Regulations) and a fuel charge (enabled by the Fuel Charge Regulations), both of which impose a price on CO2e emissions. This system applies in provinces and territories that request it and in those that do not have their own equivalent emissions pricing systems in place that meet the federal standards and ensure that there is a uniform price on emissions across the country. Originally under the federal plans, the price was set to escalate by CAD$10 per year until it reached a maximum price of CAD$50/tonne of CO2e in 2022. However, on December 11, 2020, the federal government announced its intention to continue the annual price increases beyond 2022. Commencing in 2023, the benchmark price per tonne of CO2e will increase by $15 per year until it reaches CAD$170/tonne of CO2e in 2030. Effective January 1, 2023, the minimum price permissible under the GGPPA rose to CAD$65/tonne of CO2e.

 

While several provinces challenged the constitutionality of the GGPPA following its enactment, the Supreme Court of Canada confirmed its constitutional validity in a judgment released on March 25, 2021.

 

On April 26, 2018, the federal government passed the Regulations Respecting Reduction in the Release of Methane and Certain Volatile Organic Compounds (Upstream Oil and Gas Sector) (the “Federal Methane Regulations”). The Federal Methane Regulations seek to reduce emissions of methane from the oil and natural gas sector, and came into force on January 1, 2020. By introducing a number of new control measures, the Federal Methane Regulations aim to reduce unintentional leaks and the intentional venting of methane and ensure that oil and natural gas operations use low-emission equipment and processes. Among other things, the Federal Methane Regulations limit how much methane upstream oil and natural gas facilities are permitted to vent. The federal government anticipates that these actions will reduce annual GHG emissions by about 20 megatonnes by 2030.

 

The federal government has enacted the Multi-Sector Air Pollutants Regulation under the authority of the Canadian Environmental Protection Act, 1999, which regulates certain industrial facilities and equipment types, including boilers and heaters used in the upstream oil and gas industry, to limit the emission of air pollutants such as nitrogen oxides and sulphur dioxide.

 

In the November 23, 2021 Speech from the Throne, the federal government restated its commitment to achieve net-zero emission by 2050. In pursuit of this objective, the government’s proposed actions include: (i) moving to cap and cut oil and gas sector emissions; (ii) investing in public transit and mandating the sale of zero-emission vehicles; (iii) increasing the federally imposed price on pollution; (iv) investing in the production of cleaner steel, aluminum, building products, cars, and planes; (v) addressing the loss of biodiversity by continuing to strengthen partnerships with First Nations, Inuit, and Métis, to protect nature and the traditional knowledge of those groups; (vi) creating a Canada Water Agency to safeguard water as a natural resource and support Canadian farmers; (vii) strengthening action to prevent and prepare for floods, wildfires, droughts, coastline erosion, and other extreme weather worsened by climate change; and (viii) helping build back communities impacted by extreme weather events through the development of Canada’s first-ever National Adaptation Strategy.

 

The Canadian Net-Zero Emissions Accountability Act (the “CNEAA”) received royal assent on June 29, 2021, and came into force on the same day. The CNEAA binds the Government of Canada to a process intended to help Canada achieve net-zero emissions by 2050. It establishes rolling five-year emissions-reduction targets and requires the government to develop plans to reach each target and support these efforts by creating a Net-Zero Advisory Body. The CNEAA also requires the federal government to publish annual reports that describe how departments and crown corporations are considering the financial risks and opportunities of climate change in their decision-making. A comprehensive review of the CNEAA is required every five years from the date the CNEAA came into force.

 

The Government of Canada introduced its 2030 Emissions Reduction Plan (the “2030 ERP”) on March 29, 2022. In the 2030 ERP, the Government of Canada proposes a roadmap for Canada’s reduction of GHG emissions to 40-45% below 2005 levels by 2030. As the first emissions reduction plan issued under the CNEAA, the 2030 ERP aims to reduce emissions by incentivizing electric vehicles and renewable electricity, and capping emissions from the oil and gas sector, among other measures.

 

 

On June 8, 2022 the Canadian Greenhouse Gas Offset Credit System Regulations were published in the Canada Gazette. The regulations establish a regulatory framework to allow certain kinds of projects to generate and sell offset credits for use in the federal OBPS through Canada’s Greenhouse Gas Offset Credit System. The system enables project proponents to generate federal offset credits through projects that reduce GHG emissions under a published federal GHG offset protocol. Offset credits can then be sold to those seeking to meet limits imposed under the OBPS or those seeking to meet voluntary targets.

 

Additionally, on December 7, 2023, the Minister of Environment and Climate Change and the Minister of Energy and Natural Resources, introduced Canada’s draft cap-and-trade framework to limit emissions from the oil and gas sector. The proposed Regulatory Framework for an Oil and Gas Sector Greenhouse Gas Emissions Cap proposes capping 2030 emissions at 35 to 38 percent below 2019 levels, while providing certain flexibilities to emit up to a level around 20 to 23 percent below 2019 levels. The purpose of the proposed cap is to ensure that Canada is on track to meet its target of achieving net-zero by 2050. The federal government collected feedback from the public on the proposed framework until February 5, 2024. It is expected that the regulations will be finalized and released sometime in 2025 with annual reporting required as early as 2026 and a phasing in period taking place between 2026 and 2030. The form of emissions cap on the oil and gas sector and the overall effect of such a cap remain uncertain.

 

The Government of Canada is also in the midst of developing a carbon capture utilization and storage (“CCUS”) strategy. CCUS is a technology that captures carbon dioxide from facilities, including industrial or power applications, or directly from the atmosphere. The captured carbon dioxide is then compressed and transported for permanent storage in underground geological formations or used to make new products such as concrete. Beginning in 2022, the federal government plans to spend $319 million over seven years to ramp up CCUS in Canada, as this will be a critical element of the plan to reach net-zero by 2050.

  

The Government of Canada is also in the midst of developing a carbon capture utilization and storage (“CCUS”) strategy. CCUS is a technology that captures carbon dioxide from facilities, including industrial or power applications, or directly from the atmosphere. The captured carbon dioxide is then compressed and transported for permanent storage in underground geological formations or used to make new products such as concrete. Beginning in 2022, the federal government plans to spend $319 million over seven years to ramp up CCUS in Canada, as this will be a critical element of the plan to reach net-zero by 2050.

 

Alberta

 

In December 2016, the Oil Sands Emissions Limit Act came into force, establishing an annual 100 megatonne limit for GHG emissions from all oil sands sites, but the regulations necessary to enforce the limit have not yet been developed. The delay in drafting these regulations has been inconsequential thus far, as Alberta’s oil sands emit roughly 70 megatonnes of GHG emissions per year, well below the 100 megatonne limit.

 

In June 2019, the fuel charge element of the federal backstop program took effect in Alberta. On January 1, 2023, the carbon tax payable in Alberta increased from $65 to $80 per tonne of CO2e and will continue to increase at a rate of $15 per year until it reaches $170 per tonne in 2030. In December 2019, the federal government approved Alberta’s Technology Innovation and Emissions Reduction (“TIER”) regulation, which applies to large emitters. The TIER regulation came into effect on January 1, 2020 (as amended January 1, 2023) and replaced the previous Carbon Competitiveness Incentives Regulation. The TIER regulation meets the federal benchmark stringency requirements for emissions sources covered in the regulation, but the federal backstop continues to apply to emissions sources not covered by the regulation.

 

The TIER regulation applies to emitters that emit more than 100,000 tonnes of CO2e per year in 2016 or any subsequent year. The initial target for most TIER-regulated facilities is to reduce emissions intensity by 10% as measured against that facility’s individual benchmark, with a further 2% reduction in each subsequent year. The annual reduction rate applied to oil sands mining, in-situ and upgrading is 4% in 2029 and 2030. The facility-specific benchmark does not apply to all facilities, such as those in the electricity sector, which are compared against the good-as-best-gas standard. Similarly, for facilities that have already made substantial headway in reducing their emissions, a different “high-performance” benchmark is available. Under the TIER regulation, certain facilities in high-emitting or trade exposed sectors can opt-in to the program in specified circumstances if they do not meet the 100,000 tonne threshold. To encourage compliance with the emissions intensity reduction targets, TIER-regulated facilities must provide annual compliance reports. Facilities that are unable to achieve their targets may either purchase credits from other facilities, purchase carbon offsets, or pay a levy to the Government of Alberta.

 

The Government of Alberta aims to lower annual methane emissions by 45% by 2025. The Government of Alberta enacted the Methane Emission Reduction Regulation on January 1, 2020, and in November 2020, the Government of Canada and the Government of Alberta announced an equivalency agreement regarding the reduction of methane emissions such that the Federal Methane Regulations will not apply in Alberta.

 

 

Indigenous Rights

 

Constitutionally mandated government-led consultation with and, if applicable, accommodation of, the rights of Indigenous groups impacted by regulated industrial activity, as well as proponent-led consultation and accommodation or benefit sharing initiatives, play an increasingly important role in the Western Canadian oil and gas industry. In addition, Canada is a signatory to the UNDRIP and the principles set forth therein may continue to influence the role of Indigenous engagement in the development of the oil and gas industry in Western Canada. For example, in November 2019, the Declaration on the Rights of Indigenous Peoples Act (“DRIPA”) became law in British Columbia. The DRIPA aims to align British Columbia’s laws with UNDRIP. In June 2021, the United Nations Declaration on the Rights of Indigenous Peoples Act (“UNDRIP Act”) came into force in Canada. Similar to British Columbia’s DRIPA, the UNDRIP Act requires the Government of Canada to take all measures necessary to ensure the laws of Canada are consistent with the principles of UNDRIP and to implement an action plan to address UNDRIP’s objectives. On June 21, 2022, the Minister of Justice and Attorney General issued the First Annual Progress Report on the implementation of the UNDRIP Act (the “Progress Report”). The Progress Report provides that, as of June 2022, the federal government has sought to implement the UNDRIP Act by, among other things, creating a Secretariat within the Department of Justice to support Indigenous participation in the implementation of UNDRIP (the “Implementation Secretariat”), consulting with Indigenous peoples to identify their priorities, drafting an action plan to align federal laws with UNDRIP’s, and implementing efforts to educate federal departments on UNDRIP principles. On June 21, 2023, the Implementation Secretariat released The United Nations Declaration on the Rights of Indigenous Peoples Act Action Plan with respect to aligning federal laws with UNDRIP.

 

Continued development of common law precedent regarding existing laws relating to Indigenous consultation and accommodation as well as the adoption of new laws such as DRIPA and UNDRIP Act are expected to continue to add uncertainty to the ability of entities operating in the Canadian oil and gas industry to execute on major resource development and infrastructure projects, including, among other projects, pipelines. The Government of Canada has expressed that implementation of the UNDRIP Act has the potential to make meaningful change in how Indigenous peoples collaborate in impact assessment moving forward, but has confirmed that the current IAA already establishes a framework that aligns with UNDRIP and does not need to be changed in light of the UNDRIP Act.

 

On June 29, 2021, the British Columbia Supreme Court issued a judgement in Yahey v British Columbia (the “Blueberry Decision”), in which it determined that the cumulative impacts of industrial development on the traditional territory of the Blueberry River First Nation (“BRFN”) in northeast British Columbia had breached the BRFN’s rights guaranteed under Treaty 8. The Blueberry Decision may have significant impacts on the regulation of industrial activities in northeast British Columbia and may lead to similar claims of cumulative effects across Canada in other areas covered by numbered treaties, as has been seen in Alberta.

 

On January 18, 2023, the Government of British Columbia and the BRFN signed the Blueberry River First Nations Implementation Agreement (the “BRFN Agreement”). The BRFN Agreement aims to address cumulative effects of development on BRFN’s claim area through restoration work, establishment of areas protected from industrial development, and a constraint on development activities. Such measures will remain in place while a long-term cumulative effects management regime is implemented. Specifically, the BRFN Agreement includes, among other measures, the establishment of a $200-million restoration fund by June 2025, an ecosystem-based management approach for future land-use planning in culturally important areas, limits on new petroleum and natural gas development, and a new planning regime for future oil and gas activities. The BRFN will receive $87.5 million over three years, with an opportunity for increased benefits based on petroleum and natural gas revenue sharing and provincial royalty revenue sharing in the next two fiscal years.

 

The BRFN Agreement has acted as a blueprint for other agreements between the Government of British Columbia and Indigenous groups in Treaty 8 territory. In late January 2023, the Government of British Columbia and four Treaty 8 First Nations — Fort Nelson, Salteau, Halfway River and Doig River First Nations — reached consensus on a collaborative approach to land and resource planning (the “Consensus Agreement”). The Consensus Agreement implements various initiatives including a “cumulative effects” management system linked to natural resource landscape planning and restoration initiatives, new land-use plans and protection measures, and a new revenue-sharing approach to support the priorities of Treaty 8 First Nations communities.

 

In July 2022, Duncan’s First Nation filed a lawsuit against the Government of Alberta relying on similar arguments to those advanced successfully by the BRFN. Duncan’s First Nation claims in its lawsuit that Alberta has failed to uphold its treaty obligations by authorizing development without considering the cumulative impacts on the First Nation’s treaty rights. The long-term impacts of the Blueberry Decision and the Duncan’s First Nation lawsuit on the Canadian oil and gas industry remain uncertain.

 

 

Organizational Structure

 

The Company was formed on December 9, 2022 under the laws of the Province of Alberta for the purpose of effectuating the Business Combination. The Company owns no material assets other than its interests in its wholly-owned subsidiaries.

  

The following is a chart of our current corporate structure as of the date of the registration statement of which this prospectus form a part: 

 

 

Property, Plants and Equipment

 

The Company’s headquarters are located in Calgary, Alberta, Canada. The Company’s operating assets are located in the Athabasca region of Alberta, Canada, approximately 30 miles southwest of Fort McMurray, Alberta, Canada. The Company’s principal properties are the Demo Asset and Expansion Asset. In addition, the Company holds approximately 63,766 gross hectares (25,524 net hectares) of undeveloped lands which are also in the Athabasca region.

 

The Company’s property, plant and equipment (the “PP&E”) primarily relates to its development and production assets, which primarily consist of the Hangingstone Facilities (which are SAGD production facilities) ultimately used to generate bitumen production.

 

The land included in the PP&E is not owned by the Company. The surface and mineral rights attached to the land are primarily leased from the Government of Alberta pursuant to standard Alberta government lease agreements as described in more detail under the heading “— Land Tenure — Mineral rights”.

 

Alberta has surface rights owners and mineral rights owners, and some individuals or organizations may own rights to both. Surface rights owners own the surface and substances such as sand and gravel, but not the minerals. The Company or individual who owns the mineral rights owns all mineral substances found on and under the property. There are often different surface and mineral owners on the same land. The mineral owner has the right to explore for and recover the minerals but at the same time must do this in a reasonable manner so as to not significantly affect use of the surface. The Crown owns 81% of mineral rights in Alberta, with the remaining mineral rights largely owned by federal groups (National parks, Indigenous rights, etc.), and legacy companies (Canadian Pacific Railway Limited, Canadian National Railway Company, etc.).

 

Prior to beginning any development activity, the Company is required to undergo multiple consultations, including environmental and First Nations assessments. These assessments can impact how, and when, the Company proceeds with development activity. 

 

 

Well and facility assets (including the Hangingstone Facilities) included in the PP&E are owned by the Company in proportion to its working interest in each respective asset. These assets are used to extract and process bitumen produced from the Company’s leased properties.

 

In association with each of these assets, the Company has a responsibility to safely manage each well it leases and operates, as well as the associated pipelines and facilities. This includes all stages of a well’s life cycle: exploration, development and operation, and end-of-life activities including abandonment, and reclamation. When energy infrastructure has been suspended and is no longer needed, the company that owns it must permanently dismantle it. The provincial requirements for how this is done vary by the type of infrastructure. For example, when a company no longer needs a well to support its oil and gas development, the well must be permanently sealed and taken out of service. This part of the closure process is known as abandonment, and includes both subsurface and surface abandonment activities. After the well is abandoned, the land around it must be returned to its original state, in a process known as reclamation. As part of required reclamation activities, companies have a duty to reduce land disturbance, clean up contamination, salvage, store and replace soil, and revegetate the area to equivalent land capacity.

 

The Company’s corporate assets include furniture and fixtures, computer hardware and software, and leasehold improvements. Right-of-use assets consist of the Company’s office leases in Calgary.

 

(CAD$ in thousands)		Development and Production Assets				Corporate Assets				Right-of- Use Assets				Total
PP&E, at cost:
Balance – December 31, 2022			1,057,316				629				969				1,058,914
Expenditures on PP&E(1)			32,909				(11	)			-				32,898
Right-of-use asset additions			-				-				12,798				12,789
Balance – December 31, 2023			1,090,225				618				13,758				1,104,601
Accumulated depletion, depreciation and impairment
Balance – December 31, 2022			95,572				232				60				95,864
Depletion and depreciation(2)			67,580				130				183				67,893
Balance – December 31, 2023			163,152				362				243				163,757
Net book value – December 31, 2022			961,744				397				909				963,050
Net book value – December 31, 2023			927,073				256				13,515				940,844

  

(1)

Additions for the year ended December 31, 2023, include capital expenditures on the Refill Wells drilling program and facilities improvements at both the Expansion Asset and Demo Asset.

 

(2)

No indicators of impairment were identified at December 31, 2023 as such no impairment test was performed.

 

Facility and Infrastructure Planning

 

The Company estimates that it has debottlenecked facility capacity of approximately 35,000 bbls/d at the Demo Asset and 7,500 bbls/d at the Expansion Asset. The Company is currently planning an approximate CAD$85.2 million net capital expenditure program in 2024, in order to further optimize and grow production, which is expected to be funded with the Company’s cash flow.

 

Capital Expenditures		2024 Expected Net Spend (CAD$MM)
Demo Asset		$	34.0
Expansion Asset		$	51.2
Total		$	85.2

 

Employess

 

At December 31, 2023, the Company had 39 full-time employees and 5 consultants located at its Calgary office and 134 full-time employees and 16 contracted operators in various field locations. The Company’s goal is to hire and retain highly qualified and motivated individuals.  

  

 

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

On September 20, 2023, the Company consummated the Business Combination with MBSC, pursuant to which, among other things, Greenfire and MBSC became wholly owned subsidiaries of the Company. Prior to the Business Combination, the Company had not conducted any material activities other than those incidental to its formation and to the matters contemplated by the Business Combination Agreement. Following the Business Combination, the Company has continued the business of Greenfire. The following management’s discussion and analysis (“MD&A”) provides information which management believes is relevant to an assessment and understanding of the Company’s consolidated results of operations for the periods described herein, and should be read in conjunction with the Company’s audited annual consolidated financial statements and notes as of and for the years ended December 31, 2023, 2022 and 2021 and JACOS’s audited financial statements and notes for the period from January 1, 2021 to September 17, 2021 and the year ended December 31, 2020 that are included elsewhere in this prospectus. This MD&A contains forward looking information based on management’s current expectations and projections. For information on the material factors and assumptions underlying such forward-looking information, refer to Cautionary Note Regarding Forward-Looking Statements and Risk Factors. Certain dollar amounts have been rounded to the nearest million dollars or thousand dollars, as noted, and tables may not add due to rounding. Production volumes and per unit statistics are presented throughout this MD&A on a net of the Company’s working interest and before royalty or “gross” basis. Dollar per barrel ($/bbl) costs are based upon sold bitumen barrels unless otherwise noted. In this section, “Greenfire,” refers to Greenfire Resources Inc. and its subsidiaries. The “Company,” “we,” or “us” refers to Greenfire Resources Ltd. and its subsidiaries following the Business Combination.

 

Overview

 

Greenfire was incorporated on June 18, 2021 under the ABCA as a Calgary-based energy company focused on the sustainable production and development of upstream energy resources from the oil sands in the Athabasca region of Alberta, Canada, using in-situ thermal oil production extraction techniques such as steam-assisted gravity drainage at: (i) the Demo Asset; and (ii) the Expansion Asset. Greenfire has a 100% working interest in the Demo Asset and a 75% working interest in the Expansion Asset.

 

GAC, the predecessor entity of Greenfire, was incorporated on November 2, 2020 and acquired the Demo Asset on April 5, 2021. HEAC was incorporated on July 12, 2021 and acquired JACOS, including its primary asset, the Expansion Asset, on September 17, 2021. Greenfire became the ultimate holding company of the Demo Asset and the Expansion Asset through a series of Reorganization Transactions described in the “Business” section of this prospectus. Prior to the acquisition of the Demo Asset in April of 2021, neither Greenfire nor any of its subsidiaries had any material operations and JACOS is therefore deemed to be a predecessor of Greenfire. A discussion of certain results of operations of JACOS for the period from January 1, 2021 to September 17, 2021 and the year ended December 31, 2020 follows management’s discussion and analysis of the financial condition and results of operation of Greenfire.

 

Greenfire had no material operations in 2020 as the acquisitions of the Demo Asset and JACOS occurred in 2021.

 

On September 20, 2023, Greenfire, the Company, MBSC and the other parties thereto closed the Business Combination as a result of which, among other things, Greenfire became a wholly-owned subsidiary of the Company. On January 1, 2024, Greenfire amalgamated with GROC, with the surviving entity continuing as “Greenfire Resources Operating Corporation” and as a wholly-owned subsidiary of the Company. For more information, see “Summary —Business Combination.” The Company had no material operations prior to the Business Combination and following the Business Combination continues the business of Greenfire.

 

Key Factors Affecting Operating Results

 

The Company believes its performance depends on several factors that present significant opportunities for it but also pose risks and challenges.

 

Commodity Prices

 

Prices for crude oil, condensate and natural gas have historically been volatile. This volatility is expected to continue due to the many uncertainties associated with the global political and economic environment, including the supply of, and demand for, crude oil and natural gas and the availability of other energy supplies, both regionally and internationally, as well as the relative competitive relationships of the various energy sources in the view of consumers and other factors.

 

The market prices of crude oil, condensate and natural gas impact the amount of cash generated from the Company’s operating activities, which, in turn, impact the Company’s financial position and results of operations.

 

Competition

 

The petroleum industry is competitive in all of its phases. The Company competes with numerous other entities in the exploration, development, production and marketing of oil. The Company’s competitors include oil and natural gas companies that have substantially greater financial resources, workforce and facilities than those of the Company. Some of these companies not only explore for, develop and produce oil, but also carry on refining operations and market oil and natural gas on an international basis. As a result of these complementary activities, some of these competitors may have greater and more diverse competitive resources to draw on than the Company. The Company’s ability to increase its reserves in the future will depend not only on its ability to explore and develop its present properties, but also on its ability to select and acquire other suitable producing properties or prospects for exploratory drilling. Competitive factors in the distribution and marketing of oil include price, process, and reliability of delivery and storage.

 

 

The Company also faces competition from companies that supply alternative resources of energy, such as wind or solar power. Other factors that could affect competition in the marketplace include additional discoveries of hydrocarbon reserves by the Company’s competitors, changes in the cost of production, and political and economic factors and other factors outside of the Company’s control.

 

The petroleum industry is characterized by rapid and significant technological advancements and introductions of new products and services utilizing new technologies that may increase the viability of reserves or reduce production costs. Other companies may have greater financial, technical and personnel resources that allow them to implement and benefit from such technological advantages. The Company may not be able to respond to such competitive pressures and implement such technologies on a timely basis, or at an acceptable cost. If the Company does implement such technologies, the Company may not do so successfully. One or more of the technologies currently used or implemented in the future by the Company may become obsolete or uneconomic. If the Company is unable to employ the most advanced commercially available technology, or is unsuccessful in implementing certain technologies, its business, financial condition and results of operations could also be adversely affected in a material way.

 

Royalty Regimes

 

The Company pays royalties in accordance with the established royalty regime in the Province of Alberta. the Company’s royalties are paid to the Crown, which are based on government prescribed pre- and post- payout royalty rates determined on sliding scales and dependent on commodity prices. The Government of Alberta may adopt new royalty regimes, or modify the existing royalty regime, which may have an impact on the economics of the Company’s projects. An increase in royalties would reduce the Company’s earnings and could make future capital investments, or the Company’s operations, less economic.

 

Impact of COVID-19

 

The COVID-19 pandemic, which began in early 2020, continues to create uncertainty and negatively impact the commodity price environment by suppressing the continued recovery in global economic activity and demand for hydrocarbon product. It continues to be difficult to forecast and account for the risk posed by the COVID-19 pandemic.

 

Non-GAAP Measures

 

Refer to “—Non-GAAP Measures” for reconciliations and information regarding the following measures and ratios used in this prospectus: “adjusted EBITDA,” “operating netback,” “adjusted funds flow,” “adjusted free cash flow”, “adjusted working capital,” “net debt,”. “adjusted EBITDA ($/bbl),” and “operating netback ($/bbl).”

 

Selected Financial and Operational Highlights

 

		Three months ended December 31,								Year ended December 31,
(CAD$ thousands, unless otherwise noted)		2023				2022				2023				2022
Bitumen production – Expansion Asset (bbls/d)			14,079				15,710				13,829				16,802
Bitumen production – Demo Asset (bbls/d)			3,256				3,869				3,810				3,701
Bitumen production – Consolidated (bbls/d)			17,335				19,579				17,639				20,503
Oil sales			161,730				180,741				675,970				998,849
Oil sales (CAD$/bbl)			71.04				72.18				73.91				96.82
Operating netback(1)			27,353				34,567				132,704				229,694
Operating netback (CAD$/bbl)(1)			17.19				19.27				20.56				30.58
Operating expenses			35,084				42,429				148,965				160,826
Operating expenses (CAD$/bbl)			22.05				23.65				23.08				21.41
Cash provided (used) by operating activities			25,530				17,322				86,548				164,727
Adjusted funds flow(1) (2)			10,517				16,902				73,206				163,926
Cash provided (used) by investing activities			18,732				(17,316	)			(12,103	)			(63,746	)
Capital expenditures			19,413				12,361				33,428				39,592
Adjusted free cash flow(1)			(8,896	)			4,541				39,778				124,334
Net income (loss) and comprehensive income (loss)			(4,659	)			87,995				(135,671	)			131,698
Per share – basic(2)			(0.07	)			1.80				(2.49	)			2.69
Per share – diluted(2)			(0.07	)			1.25				(2.49	)			1.88
Adjusted EBITDA(1)			23,434				32,528				117,316				218,033

 

	(1)	Non-GAAP measures do not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the “Non-GAAP Measures” section in this MD&A for further information.

(2)	For the year ended December 31, 2022, the Company’s basic and diluted earnings per share is the net income per common share of Greenfire and the weighted average common shares outstanding has been scaled by the applicable exchange ratio following the completion of the Business Combination.

 

 

Selected Liquidity and Balance Sheet Highlights

 

		December 31,				December 31,
(CAD$ thousands)		2023				2022
Cash and cash equivalents			109,525				35,363
Restricted cash			-				35,313
Available credit facilities(1)			50,000				7,000
Face value of Long-term debt(2)			396,780				295,173

 

	(1)	As at December 31, 2023, the Company had $50.0 million of available credit under the Senior Credit Facility, which was undrawn as of December 31, 2023. As at December 31, 2022 the Company had $15.0 million of available credit under available credit facilities, of which $8.0 million was drawn.

(2)

As at December 31, 2023, the 2028 Notes had a face value of US$300.0 million and have been converted into Canadian dollars as at period end exchange rates. As at December 31, 2022, the 2025 Notes had a face value of US$217.9 million and have been converted into Canadian dollars as at period end exchange rates.

 

Results of Operations

 

Comparison of certain production, financial and operating results for the year ended December 31, 2023 to the year ended December 31, 2022:

 

Production

  

The Company’s net average bitumen production was 17,335 bbls/d and 17,639 bbls/d for the three and twelve months ended December 31, 2023, respectively, both lower than 19,579 bbls/d and 20,503 bbls/d from the same respective periods in 2022.

 

At the Expansion Asset, net average bitumen production was 14,079 bbls/d during the fourth quarter of 2023, lower than the 15,710 bbls/d during the fourth quarter of 2022, mainly due to a combination of lower reservoir pressure resulting from short-term limitations of NCG availability for co-injection from the Company’s natural gas provider during 2023, as well as planned well reductions and well shut-ins to facilitate the Refill wells drilling program. Full year 2023 net average bitumen production was 13,829 bbls/d, lower than the 16,802 bbls/d in the same period in 2022, reflecting a combination of lower reservoir pressure resulting from short-term limitations of NCG availability for co-injection from the Company’s natural gas provider during 2023, unplanned field downtime due to consecutive external power grid outage, and the unplanned well shut-ins noted in the fourth quarter of 2023.

 

At the Demo Asset, net average bitumen production of 3,256 bbls/d for the fourth quarter of 2023 was lower than 3,869 bbls/d from the same period in 2022 due to the temporary shut-in of the disposal well, while full year net average bitumen production was 3,810 bbls/d and was slightly higher than 3,701 bbls/d from the full year in 2022, mainly due to the continued optimization of water disposal wells that debottlenecked water handling capabilities for the first three quarters of 2023, partially offset by the temporary shut-in of the disposal well in the fourth quarter of 2023. Subject to regulatory approval to recommence disposal operations, management anticipates net average bitumen production at the Demo Asset will increase by approximately 1,000 bbls/d. 

 

		Three months ended December 31,								Year ended December 31,
(Average barrels per day, unless otherwise noted)		2023				2022				2023				2022
Bitumen Production - Expansion Asset			14,079				15,710				13,829				16,802
Bitumen Production - Demo Asset			3,256				3,869				3,810				3,701
Total Bitumen Production			17,335				19,579				17,639				20,503
Total Diluted Bitumen Sales			23,736				25,026				24,052				24,985
Total Non-diluted Bitumen Sales			1,010				2,193				1,006				3,277
Total Sales Volumes			24,746				27,219				25,058				28,264

 

 

Commodity Prices

 

The prices received for the Company’s crude oil production directly impact earnings, cash flow and financial position. The following table shows benchmark pricing of crude oil, natural gas and electricity for the periods indicated:

 

		Three months ended December 31,								Year ended December 31,
Benchmark Pricing		2023				2022				2023				2022
Crude oil (US$/bbl)
WTI(1)			78.32				82.65				77.62				94.23
WCS differential to WTI			(21.89	)			(25.89	)			(18.71	)			(18.27	)
WCS(2)			56.43				56.76				58.91				75.96
Edmonton Condensate (C5+)			76.78				83.46				76.79				93.86
Natural gas (CAD$/GJ)
AECO 5A			2.18				4.85				2.50				5.04
Electricity (CAD$/MWh)
Alberta power pool			81.73				213.64				133.55				161.88
Foreign exchange rate(3)
US$:CAD$			1.3618				1.3577				1.3495				1.3016

 

(1)

As per NYMEX oil futures contract

 

(2)

Reflects heavy oil prices at Hardisty, Alberta

 

(3)

Annual or quarterly average exchange rates as per the Bank of Canada.

 

WCS

 

Revenue from the Company’s bitumen production is closely linked to WCS, the pricing benchmark for Canadian heavy oil at Hardisty, Alberta. WCS trades at a discount to WTI, which is known as the WCS differential, and fluctuates based on heavy oil production, inventory levels, infrastructure egress capacity and refinery demand in Canada and the United States, among other factors.

 

Condensate

 

In order to facilitate pipeline transportation of the Company’s produced bitumen, the Company uses condensate as diluent for blending at the Expansion Asset, which is from Edmonton and delivered via the Inter Pipeline Polaris Pipeline. The price of condensate is historically within approximately 5% of the price of WTI and is typically higher in winter months due to increased diluent requirements in colder temperatures relative to warmer summer months.

 

Oil Sales

 

The Company’s oil sales include blended bitumen sales from the Expansion Asset and non-diluted bitumen sales from the Demo Asset. At the Demo Asset each barrel can be transported to multiple potential sales locations, including both pipeline and rail sales points, depending on the economics of each option at the time of sale. During mid-October 2022, the Company commissioned a bitumen truck off-loading facility (“Truck Rack”) at the Expansion Asset that can receive up to approximately 5,000 bbls/d of bitumen production (non-diluted bitumen) from the Demo Asset that is blended with the Expansion Asset production and sold via pipeline.

  

The Company recorded oil sales of CAD$161.7 million in the fourth quarter of 2023, compared to CAD$180.7 million during the same period in 2022 reflecting lower production volumes in 2023. Full year 2023 oil sales totaled CAD$676.0 million, lower than CAD$998.8 million in 2022 as a result of lower realized WCS benchmark oil prices and lower production volumes.

 

		Three months ended December 31,								Year ended December 31,
(CAD$ thousands, unless otherwise noted)		2023				2022				2023				2022
Oil Sales			161,730				180,741				675,970				998,849
- (CAD$/bbl)			71.04				72.18				73.91				96.82

 

 

Royalties

 

Royalties paid by the Company are crown royalties to the Province of Alberta. Alberta oil sands royalty projects are based on government prescribed pre and post payout royalty rates, which are determined on a sliding scale using the Canadian dollar equivalent WTI benchmark price.

 

Royalties for a pre-payout project are based on a monthly calculation that applies a royalty rate (ranging from one percent to nine percent, based on the Canadian dollar equivalent WTI benchmark price) to the gross revenues from the project. Gross revenues are a function of sales revenues less diluent costs and transportation costs. The Expansion Asset is a pre-payout project.

 

Royalties for a post-payout project are based on an annualized calculation that uses the greater of: (1) the gross revenues multiplied by the applicable royalty rate (one percent to nine percent, based on the Canadian dollar equivalent WTI benchmark price); or (2) the net revenues of the project multiplied by the applicable royalty rate (25 percent to 40 percent, based on the Canadian dollar equivalent WTI benchmark price). Net revenues are a function of sales revenues less diluent costs, transportation costs, and allowable operating and capital costs. While the Demo Asset is a post-payout project, due to the carry forward of previous years costs, it is currently assessed under scenario (1) discussed above. The Demo Asset may become assessable under scenario (2) in 2024, depending on actual production performance, oil prices and costs.

 

Fourth quarter 2023 royalties of CAD$3.79/bbl were lower than CAD $4.17/bbl for the same period in 2022, while full year 2023 royalties were CAD$3.67/bbl compared to CAD$6.67/bbl in 2022, all attributable to lower WTI benchmark oil prices. 

 

		Three months ended December 31,								Year ended December 31,
(CAD$ thousands, unless otherwise noted)		2023				2022				2023				2022
Royalties			6,024				7,477				23,706				50,064
- (CAD $/bbl)			3.79				4.17				3.67				6.67

 

Risk Management Contracts

 

The Company is exposed to commodity price risk on its oil sales and energy operating costs due to fluctuations in market prices. The Company executes a risk management program that is primarily designed to reduce the volatility of revenue and cash flow and ensure sufficient cash flows to service debt obligations and fund the Company’s operations. The Company’s risk management liabilities may consist of hedging instruments such as fixed price swaps and option structures, including costless collars on WTI, WCS differentials, condensate differential, natural gas and electricity swaps. The Company does not use financial derivatives for speculative purposes.

 

As at December 31, 2023, the Company’s obligations under the indenture governing the 2028 Notes (as outlined under the heading — Capital Resources and Liquidity — Long Term Debt”), include a requirement to maintain 12 consecutive months of commodity hedges on WTI for not less than 50% of the hydrocarbon output under the proved developed producing reserves forecast in the most recent reserves report, as determined by a qualified and independent reserves evaluator. The hedging obligation is in place until the aggregate principal amount of the 2028 Notes outstanding is at or below US$100.0 million, at which point, the Company will no longer be required to enter into subsequent commodity hedges. In the event that WTI is equal or less than US$55/bbl for such month being hedged, the Company is not required to hedge for that month.

 

The Company’s commodity price risk management program does not involve margin accounts that require posting of margin, including in scenarios of increased volatility in underlying commodity prices. Financial risk management contracts are measured at fair value, with gains and losses on re-measurement included in the consolidated statements of comprehensive income (loss) in the period in which they arise.

 

Financial contracts

 

The Company’s financial risk management contracts are subject to master netting agreements that create the legal right to settle the instruments on a net basis. The fair value of the risk management contracts resulted in a net current liability of CAD$0.4 million at December 31, 2023.  The following table summarizes the gross asset and liability positions of the Company’s individual risk management contracts that are offset in the consolidated balance sheets: 

 

		As at December 31,								As at December 31,
		2023								2022
(CAD$ thousands)		Asset				Liability				Asset				Liability
Gross amount			-				(417	)			21,375				(48,379	)
Amount offset			-				-				(21,375	)			21,375
Risk management contracts			-				(417	)			-				(27,004	)

 

Financial contracts settled in the period result in realized gains or losses based on the market price compared to the contract price and the notional volume outstanding. Changes in the fair value of unsettled financial contracts are reported as unrealized gains or losses in the period as the forward markets for commodities fluctuate and as new contracts are executed.

 

 

Outstanding Financial Risk Management Contracts at December 31, 2023

 

		WTI - Costless Collar												Natural Gas - Fixed Price Swaps
Term		Volume (bbls)				Put Strike Price (US$/bbl)				Call Strike Price (US$/bbl)				Volume (GJs)				Swap Price (CAD$/GL)
Q1 2024			877,968			$	60.00			$	77.00				455,000			$	2.97
Q2 2024			877,968			$	60.00			$	74.55				-				-
Q3 2024			887,800			$	62.00			$	92.32				-				-
Q4 2024			887,800			$	59.46			$	87.58

 

Realized and Unrealized Risk Management Contracts

 

In the three and twelve months ended December 31, 2023, the Company recorded total risk management contract gains of CAD$14.8 million and CAD$16.4 million, respectively, compared to total risk management contract gains of CAD $2.2 million and losses of CAD$121.5 million for the same respective periods in 2022.

 

In the fourth quarter, the Company realized CAD$3.2 million risk management contracts loss (CAD$6.2 million realized gain in the same period of 2022) as market prices for WTI settled at levels above the Company’s risk management contracts during the quarter. CAD$18.0 million unrealized gain on risk management contracts (CAD$4.0 million unrealized loss in the same period of 2022) was primarily a result of the market prices for WTI settling at levels below those set at the end of the third quarter of 2023.

 

For the year ended December 31, 2023, the Company realized CAD$10.2 million of risk management contracts loss (CAD$122.4 million realized loss in the same period of 2022), primarily a result of the market prices for WTI settling at levels above the Company’s risk management contracts outstanding during 2023, partially offset by gains due to the widening of WCS differentials. CAD$26.6 million of unrealized gain on risk management contracts (CAD$0.9 million unrealized gain in the same period of 2022), was primarily a result of the market prices for WTI settling at levels within the Company’s outstanding risk management contracts, in addition to the settlement of the risk management contracts realized during the first twelve months of 2023.

 

Realized and Unrealized Gain (Loss) on Commodity Price Risk Management Contracts

 

		Three months ended December 31,								Year ended December 31,
(CAD$ thousands)		2023				2022				2023				2022
Realized gain (loss)			(3,225	)			6,243				(10,182	)			(122,408	)
Unrealized gain (loss)			18,035				(4,019	)			26,587				930
Risk management contracts gains (losses)			14,810				2,224				16,405				(121,478	)

 

Diluent Expense

 

In order to facilitate pipeline transportation of bitumen, the Company uses condensate as diluent for blending at the Expansion Asset and for trucked volumes from the Demo Asset that are delivered to the Truck Rack that is located at the Expansion Asset. The Company’s diluent expense includes the cost of diluent plus the pipeline transportation of the diluent from Edmonton to the Expansion Asset facility via the Inter Pipeline Polaris Pipeline.

 

The table below shows the Company’s diluent expense in the fourth quarter of 2023 was CAD$17.65/bbl, lower than CAD$19.34/bbl in the comparative period of 2022 and for the full year 2023 was CAD$16.39/bbl, higher than CAD$12.83/bbl in the full year 2022. The factors driving the lower diluent pricing are discussed above under the heading “ – Commodity Prices”.

 

		Three months ended December 31,								Year ended December 31,
(CAD$ thousands, unless otherwise noted)		2023				2022				2023				2022
Diluent expense			76,768				85,946				304,740				368,015
- (CAD$/bbl)			17.65				19.34				16.39				12.83

 

Transportation and Marketing Expense

 

Transportation expense at the Expansion Asset includes the costs to move production from the facility to the sales point in Edmonton, Alberta, via the Enbridge Lateral Pipeline and Enbridge Waupisoo Pipeline. At the Demo Asset, transportation expenses relate to the trucking of bitumen from the facility to various pipeline and rail sales points, including to the Truck Rack commissioned at the Expansion Asset facility on October 12, 2022.

 

 

The Company has an exclusive petroleum marketing contract with the Petroleum Marketer for the Company’s production at the Demo Asset, pursuant to which, in addition to marketing fees, the Company pays royalty incentive and performance fees, among other costs, to the Petroleum Marketer which are oil price- and production volume- dependent. Following the JACOS Acquisition, the Company entered into an exclusive marketing contract with the Petroleum Marketer for the Petroleum Marketer to provide marketing services for the Expansion Asset (the “Expansion Marketing Agreement”), including facilitating all pipeline transportation and storage. The exclusive marketing services at the Expansion Asset expire in October 2028 and include the purchase of all blended bitumen produced, the supply of all diluent and the facilitation of all pipeline transportation and storage costs. The exclusive marketing services at the Demo Asset expire in April 2026 and include the purchase of all bitumen produced, and the facilitation of all bitumen transportation. In addition to the marketing fees, production at the Demo Asset is further subject to additional costs associated with the marketing contract that include royalty incentive and performance fees. See the section under the heading “Business— Material Contracts, Liabilities and Indebtedness — Marketing Agreements” for a further description of the Demo Marketing Agreement and the Expansion Marketing Agreement.

 

The Company’s transportation and marketing expense was CAD$8.34/bbl and CAD$8.63/bbl in the fourth quarter and year ended December 31, 2023, respectively, lower than CAD$9.23/bbl and CAD$9.03/bbl for the same respective periods in 2022, primarily due to lower oil transportation costs at the Demo Asset from utilizing the Truck Rack. 

 

		Three months ended December 31,								Year ended December 31,
(CAD$ thousands, unless otherwise noted)		2023				2022				2023				2022
Marketing fees(1)			2,419				2,866				10,934				12,441
Oil transportation expense			10,858				13,698				44,739				55,401
Transportation and marketing			13,277				16,566				55,673				67,842
Marketing fees(1) (CAD$/bbl)			1.52				1.60				1.69				1.66
Oil transportation expense (CAD$/bbl)			6.82				7.64				6.93				7.38
Transportation and marketing (CAD$/bbl)			8.34				9.24				8.62				9.04

 

(1)

Marketing fees include marketing fees paid to the Petroleum Marketer and terminal fees.

 

Operating Expenses

 

Operating expenses include energy operating expenses and non-energy operating expenses. Energy operating expenses reflect the cost of natural gas to generate steam and to support reservoir pressure through NCG co-injection to enhance oil production and recovery as well as electricity to operate the Company’s facilities. Non-energy operating expenses relate to production-related operating activities, including staff, contractors and associated travel and camp costs, chemicals and treating, insurance, equipment rentals, maintenance and site administration, among other costs.

 

The Company’s energy operating expenses for the three months and year ended December 31, 2023 were CAD$7.68/bbl and CAD$8.77/bbl, respectively, which was lower than the comparative periods in 2022 of CAD$12.32/bbl and CAD$11.35/bbl, respectively. The lower per barrel energy operating expenses in 2023, were primarily related to lower natural gas and electricity prices partially offset by lower sales volumes.

 

Non-energy operating expenses for the fourth quarter and full year 2023 were CAD $14.37/bbl and CAD $14.31/bbl, higher than the comparative periods in 2022 of CAD $11.33/bbl and CAD $10.06/bbl. The higher per barrel non-energy operating expenses in 2023 was primarily the result of the recognition of higher greenhouse gas emission fees, the planned minor turnaround being expensed, and inflationary pressures on the costs of goods and services combined with lower sales volumes for the three months ended December 31, 2023.

 

 

		Three months ended December 31,								Year ended December 31,
(CAD$ thousands, unless otherwise noted)		2023				2022				2023				2022
Operating expenses - energy			12,223				22,100				56,624				85,232
Operating expenses - non-energy			22,861				20,329				92,341				75,594
Operating expenses			35,084				42,429				148,965				160,826
Operating expenses - energy (CAD$/bbl)			7.68				12.32				8.77				11.35
Operating expenses - non-energy (CAD$/bbl)			14.37				11.33				14.31				10.06
Operating expenses (CAD$/bbl)			22.05				23.65				23.08				21.41

 

Operating Netback

 

Oil sales is a GAAP measure that is the most directly comparable measure to operating netback, which is a non-GAAP measure.

 

During the three months and year ended December 31, 2023, the Company had oil sales of CAD$161.7 million and CAD$676.0 million, respectively, compared to oil sales of CAD$180.7 million and CAD$998.8 million, during the comparative periods in 2022.

 

Operating netback for the three and twelve months ended December 31, 2023 was CAD$17.19/bbl and $20.56/bbl, respectively, lower than the same respective periods in 2022 which were CAD$19.27/bbl and CAD$30.58/bbl. The lower per barrel operating netback in the fourth quarter of 2023, compared to the same period in 2022 was primarily due to increased realized loss on risk management contracts and higher non-energy operating costs per barrel due to lower oil sales volumes, partially offset by lower natural gas and power prices. The lower per barrel operating netback in year ended 2023 was mainly due to lower realized WCS benchmark oil prices and higher non-energy operating costs per barrel due to lower oil sales volumes, partially offset by lower realized risk management contract losses, lower gas and power prices and lower royalties, relative to the same period in 2022.

 

The following table shows a reconciliation of oil sales to operating netback and oil sales ($/bbl) to operating netback ($/bbl) for the periods indicated:

 

		Three months ended December 31,								Year ended December 31,
(CAD$ thousands, unless otherwise noted)		2023				2022				2023				2022
Oil sales			161,730				180,741				675,970				998,849
Diluent expense			(76,768	)			(85,946	)			(304,740	)			(368,015	)
Transportation and marketing			(13,277	)			(16,566	)			(55,673	)			(67,842	)
Royalties			(6,024	)			(7,477	)			(23,706	)			(50,064	)
Operating expense – energy			(12,223	)			(22,100	)			(56,624	)			(85,232	)
Operating expense – non-energy			(22,862	)			(20,329	)			(92,342	)			(75,594	)
Operating netback(1), excluding realized gain (loss) risk management contracts			30,576				28,324				142,885				352,102
Realized gain (loss) risk management contracts			(3,225	)			6,243				(10,182	)			(122,408	)
Operating netback(1)			27,351				34,567				132,703				229,694
Oil sales (CAD$/bbl)			71.04				72.18				73.91				96.82
Diluent expense (CAD $/bbl)			(17.65	)			(19.34	)			(16.39	)			(12.83	)
Transportation and marketing (CAD $/bbl)			(8.34	)			(9.23	)			(8.63	)			(9.03	)
Royalties (CAD$/bbl)			(3.79	)			(4.17	)			(3.67	)			(6.67	)
Operating expense – energy (CAD $/bbl)			(7.68	)			(12.32	)			(8.77	)			(11.35	)
Operating expense – non-energy (CAD $/bbl)			(14.37	)			(11.33	)			(14.31	)			(10.06	)
Operating netback(1), excluding realized gain (loss) risk management contracts (CAD $/bbl)			19.21				15.79				22.14				46.88
Realized gain (loss) risk management contracts (CAD $/bbl)			(2.03	)			3.48				(1.58	)			(16.30	)
Operating netback (CAD $/bbl)(1)			17.19				19.27				20.56				30.58

 

(1)

Non-GAAP measures do not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the “Non-GAAP Measures” section in this MD&A for further information.

 

 

General & Administrative Expenses

 

General and administrative (“G&A”) expenses include head office and corporate costs such as salaries and employee benefits, office rent, independent third-party audit and engineering services, and administrative recoveries earned for operating exploration and development activities on behalf of the Company’s working interest partners, among other costs. G&A expenses primarily fluctuates with head office staffing levels and the level of operated exploration and development activity during the period. G&A may also include expenses related to corporate strategic initiatives, if any.

 

G&A expenses for the three months and year ended December 31, 2023, were CAD$2.14/bbl and CAD$1.79/bbl, respectively, which was higher than the comparative periods in 2022 of CAD $1.60/bbl and CAD CAD$1.31/bbl, respectively. The increase in G&A expenses per barrel was primarily due to the listing of the Common Shares on the NYSE and related public company expenditures, among other items. The increase in G&A expenses per barrel was also due to lower sales volumes for the three months and year ended December 31, 2023 compared to the same period in 2022.

 

		Three months ended December 31,								Year ended December 31,
(CAD$ thousands, unless otherwise noted)		2023				2022				2023				2022
General and administrative expenses			3,401				2,874				11,536				9,836
- (CAD$/bbl)			2.14				1.60				1.79				1.31

 

Stock-based Compensation

 

On September 20, 2023, with the closing of the Business Combination, all outstanding Company Performance Warrants vested and became exercisable. As a result, the remaining unrecognized fair market value of the Company Performance Warrants was immediately recorded as stock-based compensation during the third quarter of 2023. The Company Performance Warrants expire ten years following the date they were original issued as Greenfire performance warrants prior to the closing of the Business Combination.

 

The Company recorded stock-based compensation of CAD$0 and CAD$9.8 million during the three months and year ended December 31, 2023, respectively, compared to CAD$1.2 million for both of the respective periods during 2022.

 

		Three months ended December 31,								Year ended December 31,
(CAD$ thousands, unless otherwise noted)		2023				2022				2023				2022
Stock-based compensation			-				1,183				9,808				1,183
- (CAD $/bbl)			-				0.66				1.52				0.16

 

Interest and Finance Expenses

 

Interest and finance expenses include coupon interest, amortization of debt issue costs and debt underwriter fees, issuer discount, redemption premiums on long term debt, interest on revolving credit facility, letter of credit facilities and other interest charges. Coupon interest and required redemption premiums related to long term debt are accrued and paid according to the indenture that governs the 2028 Notes.

 

Interest and finance expenses for the three and twelve months ended December 31, 2023 were CAD$16.4 million and CAD$110.2 million, respectively, higher than the comparative periods in 2022 of CAD$10.8 million and CAD$77.1 million, mainly due to higher interest incurred on the 2028 Notes. The total interest and finance expense in 2023 of CAD$108.3 million was comprised of CAD$42.1 million of unamortized debt related costs and CAD$19.2 million from the early debt redemption premium (the “Debt Redemption Premium”) on the redemption of our previously issued senior secured notes due in 2025 (the “2025 Notes”). 

 

		Three months ended December 31,								Year ended December 31,
(CAD$ thousands)		2023				2022				2023				2022
Accretion on long-term debt		$	14,056			$	10,002			$	106,435			$	74,176
Other interest			2,078				591				2,873				2,155
Accretion of decommissioning obligations			236				200				906				743
Total interest and finance expenses		$	16,370			$	10,794			$	110,214			$	77,074

 

Depletion and Depreciation Expense

 

The Company depletes crude oil properties on a unit-of-production basis over estimated total recoverable proved plus probable (2P) reserves as prepared to the Canadian standard using NI 51-101 and COGEH. The depletion base consists of the historical net book value of capitalized costs, plus the estimated future costs required to develop the Company’s estimated recoverable proved plus probable reserves. The depletion base excludes exploration and the cost of assets that are not yet available for use.

 

 

The unit-of-production rate accounts for expenditures incurred to date, together with estimated future development expenditures required to develop those proved reserves. This rate, calculated at a facility level, is then applied to sales volume to determine depletion each period. We believe that this method of calculating depletion charges each barrel of crude oil equivalent sold with its proportionate share of the cost of capital invested over the total estimated life of the related asset as represented by 2P reserves.

 

The Company’s depletion and depreciation expense for the three months and year ended December 31, 2023 were CAD$10.23/bbl and CAD $10.54/bbl, respectively, which was higher than the comparative periods in 2022 of CAD$9.87/bbl and CAD$9.06/bbl, respectively. The higher per barrel depletion and depreciation expense in 2023, was primarily due to an increase in estimated future development costs as represented by 2P reserves in the Company’s most recent reserve report, relative to the prior reserve report. 

 

		Three months ended December 31,								Year ended December 31,
(CAD$ thousands, unless otherwise noted)		2023				2022				2023				2022
Depletion and depreciation expense			16,273				17,702				68,054				68,027
- (CAD$/bbl)			10.23				9.87				10.54				9.06

 

Exploration Expenses

 

The Company’s exploration expenses primarily consist of escalating mineral lease rentals on the undeveloped lands. In the three months and year ended December 31, 2023, exploration expenses were CAD$0.5 million and CAD$3.8 million, compared to CAD$0.3 million and CAD$1.8 million for the same respective periods in 2022. The increase in 2023 was primarily due to a one-time regulatory expense associated with the implementation of the Oil Sands Tenure Regulation^. This regulation, made under the Mines and Minerals Act, is the primary regulation that deals with tenure of oil sands agreements in Alberta. The regulation provides for the issuance and continuation of primary oil sands leases, and the payment of escalating rental when a continued lease does not meet a minimum level of production.

 

		Three months ended December 31,								Year ended December 31,
(CAD$ thousands, unless otherwise noted)		2023				2022				2023				2022
Exploration expenses			517				347				3,852				1,825

 

Other (Income) and Expense

 

Other (income) and expense in the fourth quarter of 2023 reflected income of CAD$1.3 million, compared to income of CAD $1.4 million for the comparative period in 2022. Other (income) and expenses during each of the respective periods are mainly comprised of interest earnings from savings accounts and short-term investments.

 

In the year ended December 31, 2023, other (income) and expense was income of CAD $2.9 million, compared to income of CAD $0.2 million in 2022, with the difference primarily attributable to higher interest earnings from savings accounts during 2023, compared to 2022, partially offset by expenses related to the JACOS acquisition, among other items.

 

		Three months ended December 31,								Year ended December 31,
(CAD$ thousands, unless otherwise noted)		2023				2022				2023				2022
Other (income) and expenses			(1,313	)			(1,367	)			(2,905	)			(206	)

 

Foreign Exchange Loss (Gain)

 

The Company’s foreign exchange loss (gain) is driven by fluctuations in the US dollar to Canadian dollar exchange rate, as it relates to its long-term debt that is denominated in US dollars and is primarily related to the note principal and interest components of the Company’s US dollar denominated debt.

 

In the three months and year ended December 31, 2023, the Company recorded a foreign exchange gain of CAD$8.1 million and CAD$8.7 million, respectively, compared to a gain of CAD$2.9 million and a loss of CAD$26.1 million for the comparative periods in 2022. The foreign exchange gain during the fourth quarter of 2023 and full year 2023 were mainly due to the Canadian dollar strengthening relative to the US dollar.

 

		Three months ended December 31,								Year ended December 31,
(CAD$ thousands, unless otherwise noted)		2023				2022				2023				2022
Realized foreign exchange loss (gain)			-				3,675				19,914				5,188
Unrealized foreign exchange loss (gain)			(8,072	)			(6,561	)			(28,638	)			20,911
Foreign exchange loss (gain)			(8,072	)			(2,886	)			(8,724	)			26,099

 

 

Transaction Costs

 

On September 20, 2023, the Company completed the Business Combination with MBSC. The Company expensed CAD$3.8 million and CAD$12.2 million in transaction costs during the three months and year ended December 31, 2023 respectively, compared to CAD$2.8 million for each of the respective comparative periods during 2022. Refer to the section under the heading “Summary of Prospectus—Business Combination”.

 

		Three months ended December 31,								Year ended December 31,
(CAD$ thousands, unless otherwise noted)		2023				2022				2023				2022
Transaction costs			3,848				2,769				12,172				2,769
- (CAD$/bbl)			10.55				1.54				1.89				0.37

 

Gain on Revaluation of Warrants

 

On September 20, 2023, and in connection with the Business Combination, the Company issued 5,000,000 Company Warrants to former holders of Greenfire common shares, the Greenfire Bond Warrant holders and Greenfire performance warrant holders and issued 2,526,667 Company Warrants to former holders of MBSC’s private placement warrants. The 7,526,667 outstanding Company Warrants expire five years after issuance and entitle the holder of each Company Warrant to purchase one Common Share at a price of US$11.50. If permitted by the Company, the Company Warrants can be exercised on a cashless basis. The Company Warrants are to be treated as a derivative financial liability in accordance with IFRS 9 and were measured at fair value in accordance with IFRS 13. The Company Warrants will be reassessed at the end of each reporting period with subsequent changes in fair value being recognized through the statement of comprehensive income (loss).

 

During the three months and year ended December 31, 2023, the Company incurred CAD$2.7 million and CAD$35.0 million in gains on revaluation of warrants, respectively, compared to CAD$0 for the comparative periods in 2022. The gains relate to a decrease of the warrant liability due to a reduction to the closing share price from the close of the Business Combination to December 31, 2023.

 

		Three months ended December 31,								Year ended December 31,
(CAD$ thousands, unless otherwise noted)		2023				2022				2023				2022
Gain on revaluation of warrants			(2,697	)			-				(34,973	)			-

 

Taxes

 

At December 31, 2023, the Company recognized a deferred tax asset of CAD$68.3 million (December 31, 2022 – CAD $87.7 million). As a result of improved commodity prices, the deferred tax asset has been recognized to the extent that it is probable that future taxable income will be available against which the temporary difference can be utilized. Deferred tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized.

 

(CAD$ thousands)		Year ended December 31, 2023				Year ended December 31, 2022
Income (loss) before taxes		$	(116,285	)		$	44,017
Expected statutory income tax rate			23.00	%			23.00	%
Expected income tax expense (recovery)			(26,746	)			10,124
Gain on business combination			-				-
Permanent differences			24,149				7,327
Unrecognized deferred income tax (asset) liability			21,983				(105,132	)
Deferred income tax expense (recovery)		$	19,386			$	(87,681	)

 

(1)

Certain accounts were consolidated into permanent differences for presentation purposes.

 

 

The Company has approximately CAD $1.8 billion in tax pools and loss carry forwards in the year ended December 31, 2023 (December 31, 2022 – CAD $1.8 billion) including approximately CAD $1.4 billion in non-capital losses available for immediate deduction against future income. The Company’s non-capital losses expire between 2033 and 2043.

 

		Year ended December 31				Year ended December 31
(CAD$ millions)		2023				2022
Undepreciated capital cost			329				321
Canadian oil and gas property expenditures			10				13
Canadian development expenditures			35				36
Canadian exploration expenditures			-				0.3
Federal income tax losses carried forward(1) (2)			1,377				1,402
Other(3)			90				19
Total Canadian federal tax pools			1,840				1,791

  

(1)

Federal income tax losses carried forward expire in the following years 2033 - CAD$4.3 million; 2034 - CAD$58.7 million; 2035 - CAD$30.0 million; 2037 - CAD$36.2 million; 2038 - CAD$8.3 million; 2039 - CAD$1,232.8 million; 2042 - CAD$2.9 million; 2043 - CAD$3.6 million.

 

(2)

Provincial income tax losses carry forward is CAD$985.0 million which is lower than the federal income tax losses carried forward due to differences in historical claims at the provincial level.

 

(3)

Other includes CAD$27.6 million in capital losses that have been recognized at the full amount as at December 31, 2023.

 

Net Income (loss) and comprehensive income (loss) and Adjusted EBITDA

 

During the three months ended December 31, 2023, the Company recorded net loss of CAD$4.7 million, compared to net income of CAD$88.0 million, during the same period in 2022. The CAD$92.7 million reduction to net income (loss) and comprehensive income (loss) in 2023 was primarily due to the recognition of a deferred tax asset expense of CAD$25.9 million in 2023, compared to a deferred tax asset recovery of CAD$87.7 million during the fourth quarter of 2022, partially offset by a reduction to listing expense of CAD$4.2 million during the fourth quarter of 2023. The decrease in net income was partially offset by CAD$14.8 million in risk management contract gains in the current quarter, compared to CAD$2.2 million in risk management contract losses in the prior year period, amongst other items.

 

During the year ended December 31, 2023, the Company recorded a net loss of CAD$135.7 million, compared to net income of CAD$131.7 million, respectively, during the comparative period in 2022. The CAD$267.4 million reduction to net income (loss) and comprehensive income (loss) in 2023 was primarily due to one-time costs of CAD$106.5 million of listing expenses related to the Business Combination, the recognition of a deferred tax asset expense of CAD$19.4 million in 2023, compared to a deferred tax asset recovery of CAD$87.7 million in 2022, as well as a CAD$31.2 million increase in refinancing costs related to the redemption of the 2025 Notes. Additionally, the decrease was also due to CAD$296.5 million in lower oil sales, net of royalties, partially offset by CAD$16.4 million in risk management contract gains in the current year, compared to CAD$121.5 million in risk management contract losses, as well as CAD$63.3 million in higher diluent expense in the prior year, amongst other items.

 

Net income (loss) and comprehensive income (loss) is a GAAP measure, which is the most directly comparable measure to adjusted EBITDA, which is a non-GAAP measure.

 

Adjusted EBITDA was CAD$23.4 million in the fourth quarter of 2023, compared to CAD$32.5 million in the same period in 2022, with the year over year decrease primarily due to lower oil sales volumes which more than offset the lower diluent expenses and the recognition of CAD$6.2 million of realized risk management contract gains in 2022, compared to CAD$3.2 million of risk management contract losses during the same period in 2023.

 

The Company had Adjusted EBITDA of CAD$117.3 million for the year ended December 31, 2023, compared to CAD$218.0 million during 2022, with the decrease primarily due to lower oil sales volumes and lower realized WCS benchmark oil prices which more than offset the lower diluent expenses. Further, the Company recognized CAD$122.4 million of realized risk management contract losses in 2022, compared to CAD$10.2 million in losses during the same period in 2023.

 

 

The following table is a reconciliation of net income (loss) and comprehensive income (loss) to adjusted EBITDA for the periods indicated:

 

		Three months ended December 31,								Year ended December 31,
(CAD$ thousands)		2023				2022				2023				2022
Net income (loss)			(4,659	)			87,995				(135,671	)			131,698
Add (deduct):
Income tax expense (recovery)			25,881				(87,681	)			19,386				(87,681	)
Unrealized (gain) loss risk management contracts			(18,035	)			4,019				(26,587	)			(930	)
Stock-based compensation			-				1,183				9,808				1,183
Financing and interest			16,370				10,794				110,214				77,074
Depletion and depreciation			16,273				17,702				68,054				68,027
Transaction costs			3,848				2,769				12,172				2,769
Listing expense			(4,162	)			-				106,542				-
Gain on revaluation of warrants			(2,697	)			-				(34,973	)			-
Gain on acquisitions			-				-				-				-
Foreign exchange loss (gain)			(8,072	)			(2,886	)			(8,724	)			26,099
Other (income) and expenses			(1,313	)			(1,367	)			(2,905	)			(206	)
Adjusted EBITDA(1)			23,434				32,528				117,316				218,033
Net income (loss) (CAD$/bbl)			(2.93	)			49.05				(21.02	)			17.53
Add (deduct):
Income tax recovery (expense) (CAD$/bbl)			16.26				(48.87	)			3.00				(11.67	)
Unrealized (gain) loss risk management contracts (CAD$/bbl)			(11.33	)			2.24				(4.12	)			(0.12	)
Stock-based compensation (CAD$/bbl)			-				0.66				1.52				0.16
Financing and interest (CAD$/bbl)			10.29				6.02				17.08				10.26
Depletion and depreciation (CAD$/bbl)			10.23				9.87				10.54				9.06
Transaction costs (CAD$/bbl)			2.42				1.54				1.89				0.37
Listing expense (CAD$/bbl)			(2.62	)			-				16.51				-
Gain on revaluation of warrants (CAD$/bbl)			(1.69	)			-				(5.42	)			-
Gain on acquisitions (CAD$/bbl)			-				-				-				-
Foreign exchange loss (gain) (CAD$/bbl)			(5.07	)			(1.61	)			(1.35	)			3.47
Other (income) and expenses (CAD$/bbl)			(0.83	)			(0.76	)			(0.45	)			(0.03	)
Adjusted EBITDA(1) (CAD$/bbl)			14.73				18.14				18.18				29.03

 

(1)

Non-GAAP measures do not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the “Non-GAAP Measures” section in this MD&A for further information.

 

(2)

Results are from operations that began at the Expansion Asset after the acquisition of JACOS on September 17, 2021 and at the Demo Asset when it was acquired on April 5, 2021.

 

 

Comparison of certain production, financial and operating results for the year ended December 31, 2022 to the year ended December 31, 2021:

 

		Year ended December 31,
(CAD$ in thousands, except production and unit prices)		2022				2021(1)
Production and sales volumes
Bitumen production (bbls/d)			20,503				8,009
Steam-oil ratio			3.47				3.11
Oil sales (bbls/d)			20,577				7,911
Financial highlights
Oil sales			998,849				270,674
Net Income (loss) and Comprehensive Income (loss)			131,698				661,444
Operating summary
Royalties			(50,064	)			(9,543	)
Realized loss on commodity risk management			(122,408	)			(3,614	)
Diluent expense			(368,015	)			(94,623	)
Transportation and marketing			(67,842	)			(24,057	)
Operating expenses			(160,826	)			(59,710	)
Annual production costs(2)			(157,684	)			(58,443	)
General & administrative expenses(1)			(11,019	)			(3,285	)
Interest and finance expense			(77,074	)			(25,050	)
Depletion and depreciation expense			(68,027	)			(27,071	)
Other income and expenses(3)			206				(8,373	)
Foreign exchange loss (gain)			(26,099	)			(1,512	)
Income tax expense (recovery)			87,681				—

 

(1)

Results are from operations that began at the Expansion Asset after the acquisition of JACOS on September 17, 2021 and at the Demo Asset when it was acquired on April 5, 2021. Although Greenfire was formed in November of 2020, it did not have material operations prior to the acquisition of the Demo Asset in April 2021. As such, a discussion of Greenfire’s 2020 financial statements has been omitted.

 

(2)

Annual production costs include energy expenses and non-energy expenses. Energy expenses include the cost of natural gas to generate steam and electricity to operate Greenfire’s facilities. Non-energy expenses relate to production-related activities, including staff, contractors and associated travel and camp costs, chemicals and treating, insurance, greenhouse gas fees, equipment rentals, maintenance and site administration, among other costs. The annual production costs is equal to operating expenses excluding ad valorem, severance, and similar production taxes.

 

(3)	Refer to section under the heading “— Other Income and Expenses” for additional information.

 

 

Production

 

Greenfire’s average bitumen production of 20,503 bbls/d in 2022 was higher than the average bitumen production of 8,009 bbls/d in 2021, primarily as a result of the JACOS Acquisition in September 2021 and an increase in production thereafter from optimization of well and facility operations.

 

Greenfire’s bitumen production net of royalties for years ended December 31, 2022 and 2021 was 7.1 mmbbl and 2.8 mmbl, respectively. Average bitumen production at the Expansion Asset of 16,802 bbls/d for 2022 was higher than average bitumen production of 5,352 bbls/d in 2021, primarily as a result of the timing of the JACOS Acquisition in September 2021, which results in comparing a partial year to a full year of production volumes. Greenfire’s average bitumen production at the Expansion Asset in 2021 are results for the period from September 17, 2021 to December 31, 2021, only, whereas Greenfire’s average bitumen production at the Expansion Asset in 2022 is from a full year of production. JACOS’s average bitumen production of 16,875 bbls/d at the Expansion Asset in 2021 are results prom the period from January 1, 2021 to September 17, 2021, only, compared to Greenfire’s average bitumen production of 16,802 bbls/d at the Expansion Asset in 2022, which is from a full year of production. See —Comparison of results of operations of JACOS for the period from January 1, 2021 to September 17, 2021 to the year ended December 31, 2020 — Production for a discussion of JACOS’s production.

 

Average bitumen production at the Demo Asset of 3,701 bbls/d for 2022 was higher than bitumen production of 2,657 bbls/d in 2021, primarily due to the timing of the acquisition of the Demo Asset, which occurred in April 2021, which results in comparing a partial year versus a full year of production volumes.

 

Steam-oil ratio is the amount of steam used in operations for injection into the bitumen reservoir divided by the amount of bitumen produced.

 

The following table shows production and steam oil ratios at each location for the periods indicated.

 

		Year ended December 31,
(Average barrels per day)		2022				2021(1)
The Expansion Asset
Bitumen production			16,802				5,352
Steam-oil ratio			3.01				2.74
The Demo Asset
Bitumen production			3,701				2,657
Steam-oil ratio			6.25				6.29
Consolidated
Bitumen production			20,503				8,009
Steam-oil ratio			3.47				3.11

 

(1)

Results are from operations that began at the Expansion Asset after the JACOS Acquisition on September 17, 2021 and at the Demo Asset when it was acquired on April 5, 2021.

 

Commodity Prices

 

The prices received for Greenfire’s crude oil production directly impact earnings, cash flow and financial position.

 

WTI

 

On a year over year basis, the average WTI benchmark price for 2022 was US$94.23/bbl, and the average for 2021 was US$67.91/bbl. Crude oil prices strengthened through 2021 as the global recovery from the COVID-19 pandemic resulted in higher demand for crude oil and crude oil products. The price of WTI further increased in the first half of 2022 after the Russia and Ukraine conflict began in February 2022, which disrupted global oil supplies as a result of sanctions applied to Russian oil production. In the end of the second quarter of 2022, continued evidence of global supply tightness resulted in relatively high product prices and refinery margins. By the third quarter of 2022, the price of WTI started to decline as the potential of longer-term demand destruction took hold along with broader recessionary risks. At the start of the fourth quarter of 2022, the price of WTI declined further as the U.S. government continued to release crude oil volumes from the Strategic Petroleum Reserve (“SPR”) and global demand softened.

  

 

WCS

 

WCS differentials for Canadian oil prices relative to WTI fluctuate from period to period based on production, inventory levels, infrastructure egress capacity, and refinery demand in Canada and the United States, among other factors. Year over year, the WCS heavy oil price increased to US$75.95/bbl in 2022 from US$54.87/bbl in 2021. The increase was primarily a result of a higher annual WTI price.

 

Strong refinery demand, limited Enbridge mainline apportionment and demand for heavy oil in the U.S. gulf coast contributed to the strength in the WCS differential in the first half of 2022. However, the WCS differentials widened in the second half of 2022, which was primarily a result of the SPR release in the United States reducing gulf coast demand, unplanned PADD 2 refinery outages and the rupture that occurred on the Cushing portion of the Keystone pipeline from December 7, 2022 through December 29, 2022. Apportionment also recurred in the market at the end of the fourth quarter of 2022 as more upstream supply competed with capacity issues downstream.

 

WDB

 

On a year over year basis, the WDB price was US$73.39/bbl for 2022, compared to US$52.98/bbl for 2021.

 

Condensate

 

On an annual basis, the Edmonton Condensate (C5+) price for 2022 was US$94.04/bbl, compared to US$68.44/bbl for 2021. The higher condensate pricing in 2022 was primarily a result of higher WTI pricing.

 

Non-Diluted Bitumen

 

In the fourth quarter of 2022, the Demo Asset delivered 100% of its sales volumes to pipeline connected destinations with zero volume going to rail facilities. Continued relatively strong WCS differentials resulted in favorable pipeline economics, and traditional rail customers did not bid on any Demo Asset volumes in the fourth quarter of 2022. In mid-October 2022, Greenfire commissioned the truck rack offloading facility at the Expansion Asset that can receive up to approximately 5,000 bbls/d of bitumen production from the Demo Asset that is then transported via pipeline. In the fourth quarter of 2022, Greenfire transported 1,665 bbls/d to the Expansion Asset truck rack at more favorable economics than transporting to long-haul destinations due to reduced transportation costs. In 2022, 97% of volume produced by the Demo Asset was delivered to pipeline connected sales points, with limited rail connected terminal demand in the first half of the year. Economics were generally more favorable to move volume to pipeline connected destinations in 2022.

 

Natural Gas

 

AECO gas prices of CAD$5.04 per gigajoule (“GJ”) in 2022 were significantly higher than the average price of CAD$3.44 per gigajoule in 2021. The increase in gas prices was primarily due to higher global gas prices, predicted low global storage levels and overall tight market conditions in 2022.

 

 

Power

 

On an annual basis, the Alberta power pool price increased to CAD$161.88 per megawatt hour (“MWH”) in 2022 compared to CAD$102.37 per megawatt hour in 2021. The return of power purchase agreements to suppliers in 2019 has allowed generators to more competitively tender their power, and in August 2022 and September 2022 wind generated power was below the 20 year average, which contributed to significantly higher pricing in the third quarter of 2022. In the first part of the fourth quarter of 2022, power prices were reduced as the relatively mild fall helped temper demand. This changed in December 2022, when the lack of solar and wind power combined with a polar vortex of extreme cold that increased demand and resulted in average pricing of CAD$311.73 per megawatt hour for the month and an average of CAD$213.64 per megawatt hour for the quarter. Wind makes up approximately one-third of the current power generation market in Alberta and reduced supply may continue to have a meaningful impact on power prices.

 

The following table shows benchmark pricing of crude oil, natural gas and electricity for the periods indicated:

 

Benchmark		Year ended December 31,				Year ended December 31,				2022 Three months ended,																2021 Three months ended,
Pricing		2022				2021				December 31				March 31				June 30				September 30				December 31				March 31				June 30				September 30
Crude oil (US$/bbl)
WTI(1)			94.23				67.91				82.65				91.55				108.41				94.29				77.19				70.56				66.07				57.84
WCS differential to WTI			(18.27	)			(13.04	)			(25.89	)			(19.86	)			(12.80	)			(14.53	)			(14.64	)			(13.58	)			(11.49	)			(12.47	)
WCS(2)			75.95				54.87				56.75				71.69				95.61				79.76				62.55				56.98				54.58				45.37
WDB(3)			73.39				52.98				53.25				68.62				93.92				77.77				60.63				55.21				52.81				43.28
Condensate at Edmonton			94.04				68.44				83.45				87.26				108.33				96.38				79.22				69.59				66.64				58.32
Natural gas (CAD$/GJ)
AECO 5A			5.04				3.44				4.85				3.95				6.86				4.49				4.41				3.41				2.93				2.99
Electricity (CAD$/MWh)
Alberta power pool			161.88				102.37				213.64				221.90				121.51				90.47				107.23				100.27				104.73				97.26
Foreign exchange rate(4)			1.3019				1.2536				1.3577				1.3059				1.2766				1.2662				1.2600				1.2602				1.2280				1.2663

  

(1)	As per NYMEX oil futures contract.

(2)	Reflects heavy oil prices at Hardisty, Alberta.

(3)	Blend stream comprised of Sunrise Dilbit Blend, Hangingstone Dilbit Blend, and Leismer Corner Blend.

(4)	US$ to CAD$ annual or quarterly average exchange rates reported by the Bank of Canada.

 

Oil Sales

 

Oil sales for 2022 and 2021 were CAD$998.8 million and CAD$270.7 million, respectively. The difference was primarily due to the inclusion of a full year of oil sales from the Expansion Asset and Demo Asset in 2022.

 

Royalties

 

Royalties paid by Greenfire are crown royalties to the Province of Alberta. Alberta oil sands royalty projects are based on government prescribed pre- and post-payout royalty rates, which are determined on a sliding scale using the Canadian dollar equivalent WTI benchmark price.

 

Royalties for a pre-payout project are based on a monthly calculation that applies a royalty rate (ranging from one percent to nine percent, based on the Canadian dollar equivalent WTI benchmark price) to the gross revenues from the project. Gross revenues are sales revenues less diluent costs and transportation costs. The Expansion Asset is a pre-payout project.

 

Royalties for a post-payout project are based on an annualized calculation that uses the greater of: (1) the gross revenues multiplied by the applicable royalty rate (one percent to nine percent, based on the Canadian dollar equivalent WTI benchmark price); or (2) the net revenues of the project multiplied by the applicable royalty rate (25 percent to 40 percent, based on the Canadian dollar equivalent WTI benchmark price). Net revenues are sales revenues less diluent costs, transportation costs, and allowable operating and capital costs. The Demo Asset is a post-payout project, which is currently assessed using gross revenues, as described above. The Demo Asset may become assessable using net revenues, as described above, early in 2024, depending on actual production performance, oil prices and costs.

 

 

Royalties for 2022 of CAD$6.67/bbl were higher compared to royalties for 2021 of CAD$3.30/bbl, primarily due to higher WTI benchmark oil prices.

 

The following table shows royalties by non-diluted bitumen sales barrels for the periods indicated:

 

		Year ended December 31,
(CAD$ in thousands, unless otherwise noted)		2022				2021(1)
Royalties			50,064				9,543
– (CAD$/bbl)			6.67				3.30

 

(1)	Results are from operations that began at the Expansion Asset after the JACOS Acquisition on September 17, 2021 and at the Demo Asset when it was acquired on April 5, 2021.

 

Risk Management Contracts

 

Greenfire uses commodity risk management contracts to manage commodity price risk on oil sales and operating expenses. Greenfire may also use foreign exchange risk management contracts to reduce its exposure to foreign exchange risk associated with its interest payments on its U.S. dollar denominated term debt. The calculated fair value of the risk management contracts relies on external observable market data including quoted forward commodity prices and foreign exchange rates. The resulting fair value estimates may not be indicative of the amounts realized at settlement and as such are subject to measurement uncertainty.

 

Pursuant to the Greenfire Indenture, Greenfire was required to maintain a 12-month forward commodity price risk management program encompassing not less than 50% of the hydrocarbon output under the proved developed producing reserves forecast in the most recent reserves report, as determined by a qualified and independent reserves evaluator

 

Greenfire’s commodity price risk management program does not involve margin accounts that require posting of margin with increased volatility in underlying commodity prices. Financial risk management contracts are measured at fair value, with gains and losses on re-measurement included in the consolidated statements of comprehensive income (loss) in the period in which they arise.

 

Financial contracts

 

Greenfire’s financial risk management contracts are subject to master netting agreements that create the legal right to settle the instruments on a net basis. The following table summarizes the gross asset and liability positions of Greenfire’s individual risk management contracts that are offset in the consolidated balance sheets:

 

		Year ended December 31,
		2022								2021
(CAD$ in thousands)		Asset				Liability				Asset				Liability
Gross amount			21,375				(48,379	)			—				35,677
Amount offset			(21,375	)			21,375				—				—
Risk management contracts			—				27,004				—				35,677

 

Financial contracts settled in the period result in realized gains or losses based on the market price compared to the contract price and the notional volume outstanding. Changes in the fair value of unsettled financial contracts are reported as unrealized gains or losses in the period as the forward markets for commodities fluctuate and as new contracts are executed.

 

The following table shows Greenfire’s outstanding financial risk management contracts as of December 31, 2022:

 

		WTI-Fixed Price Swap								WCS Differential-Fixed Price Swap
Term		Volume (bbls)				Swap Price (US$/bbl)(1)				Volume (bbls)				Swap Price (US$/bbl)(1)
Q1 2023			833,827				64.07				1,250,739				(15.75	)
Q2 2023			277,942				63.10				416,913				(15.75	)

 

(1)	Presented as weighted average prices

 

		WTI-Put Options												WTI-Costless Collar
Term		Volume (bbls)				Strike Price (US$/bbl)				Volume (bbls)				Put Strike Price (US$/bbl)				Call Strike Price (US$/bbl)
Q1 2023			416,912				50.00				—				—				—
Q2 2023			138,971				50.00				847,717				50.00				71.15
Q3 2023			1,278,551				50.00				—				—				—
Q4 2023			371,169				50.00				742,337				50.00				108.25

 

 

Physical delivery purchase and sales contracts

 

Greenfire has entered into forward, fixed-priced, physical delivery, purchase and sales contracts to manage commodity price risk. These contracts are not considered to be derivatives and therefore are not recorded at fair value. They are considered purchase and sales contracts for Greenfire’s own use and are recorded at cost at the time of a transaction.

 

In December 2022, with WCS differentials having widened, Greenfire elected to monetize a portion of its WCS differential hedges in May 2023 through September 2023. Total WCS differential volumes of 1.5 mmbbls were monetized at a WCS differential price of US$22.60/bbl, for an average gain of US$7.46/bbl and total monetized value of approximately CAD$15.0 million. Greenfire continues to maintain WCS differential hedges in January 2023 through September 2023 to protect against potential continued near-term volatility in the WCS differential.

 

The following table shows outstanding physical contracts at December 31, 2022:

 

		WCS Differential-Fixed Price Swap								AECO-Fixed Price Swap
Term		Volume (bbls)				Swap Price(1) US$/bbl				Volume (GJ/day)				Swap Price ($/GJ)
Q1 2023			—				—				—				—
Q2 2023			248,000				(15.48	)			—				—
Q3 2023			379,000				(14.92	)			—				—

 

(1)	Presented as weighted average prices

 

Realized and Unrealized Risk Management Contracts

 

In 2022, we recorded total risk management contract losses of CAD$121.5 million compared to total risk management contract losses of CAD$39.3 million in 2021. The realized risk management contracts loss for 2022 of CAD$122.4 million (CAD$3.6 million realized loss in 2021) was primarily a result of the market prices for WTI settling at levels above those set in the risk management contracts outstanding during the year. The unrealized gain on risk management contracts of CAD$0.9 million for 2022 (CAD$35.7 million unrealized loss in 2021) was primarily a result of the market prices for WTI settling at levels below those set at the end of 2021.

  

The fair value of our risk management contracts resulted in a net current liability of CAD$27.0 million at December 31, 2022.

 

The following table shows realized and unrealized gain (loss) on commodity price risk management contracts in 2022 and 2021:

 

		Year ended December 31,
(CAD$ in thousands)		2022				2021(1)
Realized gain (loss)			(122,408	)			(3,614	)
Unrealized gain (loss)			930				(35,677	)
Consolidated Gain (Loss)			(121,478	)			(39,291	)
Realized gain (loss) (CAD$/bbl)			(16.30	)			(1.25	)
Unrealized gain (loss) (CAD$/bbl)			0.12				(12.36	)
Consolidated Gain (Loss) (CAD$/bbl)			(16.17	)			(13.61	)

 

(1)	Results are from operations that began at the Expansion Asset after the JACOS Acquisition on September 17, 2021 and at the Demo Asset when it was acquired on April 5, 2021.

 

Diluent Expense

 

In order to facilitate pipeline transportation of bitumen, Greenfire uses condensate as diluent for blending at the Expansion Asset and for trucked volumes from the Demo Asset that are delivered to the Truck Rack located at the Expansion Asset. Greenfire’s diluent expense includes the cost of diluent plus the pipeline transportation of the diluent from Edmonton to the Expansion Asset facility via the Inter Pipeline Polaris Pipeline. Diluent expense for 2022 and 2021 were CAD$14.90/bbl and CAD$14.62/bbl, respectively.

 

The following table shows diluent expense for the years ended 2022 and 2021:

 

		Year ended December 31,
(CAD$ in thousands, unless otherwise noted)		2022				2021(1)
Diluent expense			368,015				94,623
(CAD$/bbl)			14.90				14.62

 

(1)	Results are from operations that began at the Expansion Asset after the JACOS Acquisition on September 17, 2021 and at the Demo Asset when it was acquired on April 5, 2021.

 

Transportation and Marketing Expense

 

Transportation expense at the Expansion Asset includes the costs to move production from the facility to the sales point in Edmonton, Alberta, via the Enbridge Lateral Pipeline and Enbridge Waupisoo Pipeline. At the Demo Asset, transportation expenses relate to the trucking of bitumen from the facility to various pipeline and rail sales points, including to the Truck Rack commissioned at the Expansion Asset facility on October 12, 2022.

 

 

Greenfire’s transportation and marketing expense for 2022 was CAD$9.03/bbl, which was higher than the comparative period of CAD$8.33/bbl in 2021. The increase was primarily due to higher trucking costs at the Demo Asset as well as an increase in fees paid to the Petroleum Marketer as a result of higher WTI market prices.

 

The following table shows transportation expenses for the years ended 2022 and 2021:

 

		Year ended December 31,
(CAD$ in thousands, unless otherwise noted)		2022				2021(1)
Pipeline transportation(2)			39,133				12,019
Trucking expense			16,268				9,155
Marketing fees(3)			12,441				2,884
Total transportation and marketing			67,842				24,057
Pipeline transportation (CAD$/bbl)			6.35				6.25
Trucking expense (CAD$/bbl)			12.04				9.51
Marketing fees(3) (CAD$/bbl)			1.66				1.00
Total transportation and marketing (CAD$/bbl)			9.03				8.33

 

(1)	Results are from operations that began at the Expansion Asset after the JACOS Acquisition on September 17, 2021 and at the Demo Asset when it was acquired on April 5, 2021.

(2)	Expansion Asset pipeline transportation includes marketing fees paid to our Petroleum Marketer.

(3)	Marketing fees for the Demo Asset include marketing fees paid to our Petroleum Marketer and terminal fees.

 

Operating Expenses

 

Operating expenses include energy operating expenses and non-energy operating expenses. Energy operating expenses include the cost of natural gas to generate steam and electricity to operate Greenfire’s facilities. Non-energy operating expenses relate to production-related operating activities, including staff, contractors and associated travel and camp costs, chemicals and treating, insurance, property tax, greenhouse gas fees, equipment rentals, maintenance and site administration, among other costs.

 

Greenfire’s energy operating expenses for 2022 were CAD$11.35/bbl, which were higher than the energy operating expenses of CAD$9.93/bbl in 2021. The higher per barrel energy operating expenses in 2022 was primarily related to higher natural gas and power prices as pricing has remained high due to the ongoing conflict in Ukraine, among other factors.

 

Greenfire’s non-energy operating expenses for 2022 were CAD$10.06/bbl, which was lower than non-energy operating expenses of CAD$10.75/bbl in 2021, primarily due to the minor turnaround being expensed in 2021, while the major turnaround in 2022 was capitalized. In addition, the decrease in non-energy operating expenses in 2022 was partly offset by inflationary pressures on the cost of goods and services.

 

The following table shows Greenfire’s operating expenses for the periods indicated:

 

		Year ended December 31,
(CAD$ in thousands, unless otherwise noted)		2022				2021(1)
Operating expenses – energy			85,232				28,674
Operating expenses – non-energy			75,594				31,037
Operating expenses			160,826				59,710
Operating expenses – energy (CAD$/bbl)			11.35				9.93
Operating expenses – non-energy (CAD$/bbl)			10.06				10.75
Operating expenses (CAD$/bbl)			21.41				20.68

 

(1)	Results are from operations that began at the Expansion Asset after the JACOS Acquisition on September 17, 2021 and at the Demo Asset when it was acquired on April 5, 2021.

 

Annual Production Costs

 

Annual production costs include energy production costs and non-energy production costs. Energy production costs include the cost of natural gas to generate steam and electricity to operate Greenfire’s facilities. Non-energy production costs relate to production-related operating activities, including staff, contractors and associated travel and camp costs, chemicals and treating, insurance, greenhouse gas fees, equipment rentals, maintenance and site administration, among other costs.

 

Greenfire’s energy production costs for 2022 were CAD$11.35/bbl, which were higher than the energy production costs of CAD$9.93/bbl in 2021. The higher per barrel energy production costs in 2022 was primarily related to higher natural gas and power prices as pricing has remained high due to the ongoing conflict in Ukraine, among other factors.

 

 

Greenfire’s non-energy production costs for 2022 were CAD$9.65/bbl, which was lower than non-energy production costs of CAD$10.31/bbl in 2021, primarily due to the minor turnaround being expensed in 2021, while the major turnaround in 2022 was capitalized. In addition, the decrease in non-energy production costs in 2022 was partly offset by inflationary pressures on the cost of goods and services.

 

The following table shows Greenfire’s annual production costs for the periods indicated:

 

		Year ended December 31,
(CAD$ in thousands, unless otherwise noted)		2022				2021(1)
Annual production costs – energy			85,232				28,674
Annual production costs – non-energy			72,452				29,770
Annual production costs(2)			157,684				58,443
Average annual production costs – energy (CAD$/bbl)			11.35				9.93
Average annual production costs – non-energy (CAD$/bbl)			9.65				10.31
Average annual production costs(2) (CAD$/bbl)			21.00				20.24

 

(1)	Results are from operations that began at the Expansion Asset after the JACOS Acquisition on September 17, 2021 and at the Demo Asset when it was acquired on April 5, 2021.

(2)	Annual production costs excludes ad valorem, severance, and similar production taxes.

 

General & Administrative Expenses

 

General and administrative (“G&A”) expenses include head office and corporate costs such as salaries and employee benefits, office rent, independent third-party audit and engineering services, and administrative recoveries earned for operating exploration and development activities on behalf of our working interest partners, among other costs. G&A expenses primarily fluctuates with head office staffing levels and the level of operated exploration and development activity during the period. G&A may also include expenses related to corporate strategic initiatives, if any.

 

G&A expenses of CAD$1.47/bbl for 2022 were higher than CAD$1.14/bbl in 2021 primarily due to higher legal fees, audit fees and tax services of CAD$0.43/bbl year over year, offset by other items. These higher legal fees, audit fees and tax services were primarily as a result of the various corporate strategic initiatives and multiple amendments to the Greenfire Indenture, among other items.

 

The following table shows general and administrative expenses for the periods indicated.

 

		Year ended December 31,
(CAD$ in thousands, unless otherwise noted)		2022				2021(1)
General and administrative expenses			11,019				3,285
(CAD$/bbl)			1.47				1.14

 

(1)	Results are from operations that began at the Expansion Asset after the JACOS Acquisition on September 17, 2021 and at the Demo Asset when it was acquired on April 5, 2021.

 

Interest and Finance Expenses

 

Interest and finance expense includes coupon interest, amortization of debt issue costs and issuer discount, redemption premiums on long term debt, interest on letter of credit facilities and other interest charges. Coupon interest and required redemption premiums related to long term debt are accrued and paid according to the Greenfire Indenture.

 

In 2022, total interest and finance expenses were CAD$77.1 million, compared to CAD$25.1 million in 2021, with the increase primarily related to higher interest expense on long term debt, in addition to the higher amortization of debt issuance costs and issuer discount as a result of principal repayments of the Greenfire Bonds completed on May 26, 2022, and November 28, 2022. See the section under the heading “— Capital Resources and Liquidity” for a discussion of Greenfire’s indebtedness.

  

The following table shows interest and finance expenses for the periods indicated.

 

		Year ended December 31,
(CAD$ in thousands)		2022				2021(1)
Interest and financing expense on long-term debt			44,322				20,674
Accretion on long-term debt			29,854				2,152
Other cash interest			2,155				1,926
Accretion of decommissioning obligations			743				298
Total interest and finance expense			77,074				25,050

 

(1)	Results are from operations that began at the Expansion Asset after the JACOS Acquisition on September 17, 2021 and at the Demo Asset when it was acquired on April 5, 2021.

 

 

Depletion and Depreciation

 

Greenfire depletes crude oil properties on a unit-of-production basis over estimated total recoverable proved plus probable (2P) reserves. The depletion base consists of the historical net book value of capitalized costs, plus the estimated future costs required to develop Greenfire’s estimated recoverable proved plus probable reserves. The depletion base excludes exploration and the cost of assets that are not yet available for use.

 

The unit-of-production rate accounts for expenditures incurred to date, together with estimated future development expenditures required to develop those proved reserves. This rate, calculated at a facility level, is then applied to our sales volume to determine depletion each period. We believe that this method of calculating depletion charges each barrel of crude oil equivalent sold with its proportionate share of the cost of capital invested over the total estimated life of the related asset as represented by 2P reserves.

 

Total depletion and depreciation expense of CAD$9.06/bbl for 2022 was slightly lower than CAD$9.38/bbl in 2021 primarily due to an overallocation of bitumen production in September 2021 related to the timing of the closing of the JACOS

 

Acquisition, which resulted in higher 2021 depletion and depreciation expense.

 

The following table shows depletion and depreciation expense for the periods indicated:

 

		Year ended December 31,
(CAD$ in thousands, unless otherwise noted)		2022				2021(1)
Depletion and depreciation expense			68,027				27,071
– (CAD$/bbl)			9.06				9.38

 

(1)	Results are from operations that began at the Expansion Asset after the JACOS Acquisition on September 17, 2021 and at the Demo Asset when it was acquired on April 5, 2021.

 

Other Income and Expenses

 

In 2022, other income and expenses was income of approximately CAD$0.2 million, consisting primarily of full year interest earnings from savings accounts and short-term investments, partially offset by restructuring costs incurred after the JACOS Acquisition. In 2021, other income and expenses was an expense of CAD$8.4 million and was primarily related to restructuring costs of CAD$4.6 million incurred after the JACOS Acquisition. In addition, Greenfire recognized a revaluation loss of CAD$3.8 million, primarily as a result of an adjustment to the discount rate applied to decommissioning liabilities after the closing of the JACOS Acquisition. This adjustment was a reduction of the discount rate of 20%, which was the rate initially used to measure the fair value of decommissioning liabilities in the purchase price allocation of JACOS, to 12%, which is the credit-adjusted discount rate used to measure the fair value of decommissioning liabilities on Greenfire’s balance sheet. This reduction in discount rate resulted in a larger decommissioning liability on Greenfire’s balance sheet and a revaluation loss on the income statement. This revaluation loss of CAD$3.8 million also included derecognition of own-use physical fixed price purchase contracts.

 

Foreign Exchange Loss (Gain)

 

Greenfire’s foreign exchange loss (gain) is driven by fluctuations in the U.S. dollar to Canadian dollar exchange rate that apply to its long-term debt that is denominated in U.S. dollars. In 2022 the Canadian dollar weakened relative to the U.S. dollar, resulting in a foreign exchange loss of CAD$26.1 million, compared to a foreign exchange loss of CAD$1.5 million in 2021, primarily related to the note principal and interest components of Greenfire’s U.S. dollar denominated debt.

 

Taxes

 

At December 31, 2022, Greenfire recognized a deferred tax asset of CAD$87.7 million (December 31, 2021 — $0) in the year ended December 31, 2022. As a result of improved commodity prices, the deferred tax asset has been recognized to the extent that it is probable that future taxable income will be available against which the temporary difference can be utilized. Deferred tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized.

 

The following table shows income tax expense for the periods indicated.

 

		Year ended December 31,
(CAD$ in thousands)		2022				2021(1)
Income (loss) before taxes		$	44,017			$	661,444
Expected statutory income tax rate			23.00	%			23.00	%
Expected income tax expense (recovery)			10,124				152,132
Gain on business combination			—				(159,609	)
Permanent differences			7,327				15,401
Unrecognized deferred income tax (asset) liability			(105,132	)			(7,924	)
Deferred income tax expense (recovery)		$	(87,681	)		$	—

 

(1)	Certain accounts were consolidated into permanent differences for presentation purposes.

 

Greenfire had approximately CAD$1.8 billion in tax pools and loss carry forwards in the year ended December 31, 2022 (December 31, 2021 — CAD$1.9 billion) including approximately CAD$1.4 billion in non-capital losses available for immediate deduction against future income. Greenfire’s non-capital losses have an expiry profile between 2033 and 2042.

 

 

As of December 31, 2022, Greenfire had the following tax pools, which may be used to reduce taxable income in future years, limited to the applicable rates of utilization:

 

		Year ended December 31,
(CAD$ in thousands)		2022				2021
Undepreciated capital costs			321,000				300,000
Resource pools			49,000				64,000
Non-capital losses			1,402,000				1,544,000
Other			20,000				—
Total Canadian federal tax pools			1,791,000				1,908,000

 

Net Income (Loss) and Comprehensive Income (Loss) and Adjusted EBITDA

 

Net income (loss) and comprehensive income (loss) is the most directly comparable GAAP measure for adjusted EBITDA, which is a non-GAAP measure. In 2022, Greenfire had adjusted EBITDA of CAD$218.0 million, compared to CAD$75.5 million in 2021. The improved results in 2022 were primarily due to the inclusion of a full year of oil sales from the Expansion Asset and Demo Asset in 2022 and higher commodity pricing.

 

The following table is a reconciliation of net income (loss) and comprehensive income (loss) to adjusted EBITDA:

 

		Year ended December 31,
(CAD$ in thousands)		2022				2021(1)
Net income (loss) and comprehensive income (loss)			131,698				661,444
Add (deduct):
Income tax recovery			(87,681	)			—
Unrealized (gain) loss risk management contracts			(930	)			35,677
Acquisition transaction costs			2,769				10,318
Stock based compensation			1,183				—
Depletion and depreciation			68,027				27,071
Financing and interest			77,074				25,050
Foreign exchange loss			26,099				1,512
Gain on acquisitions			—				(693,953	)
Other income and expenses(2)			(206	)			8,373
Adjusted EBITDA(3)			218,033				75,492

 

(1)	Results are from operations that began at the Expansion Asset after the acquisition of JACOS on September 17, 2021 and at the Demo Asset when it was acquired on April 5, 2021.

(2)	Refer to section under the heading “— Other Income and Expenses” for additional information.

(3)	Non-GAAP measures do not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the Non-GAAP Measures section in this MD&A for further information.

 

Decommissioning Liability

 

Greenfire’s decommissioning liabilities result from net ownership interests in oil assets including well sites, gathering systems and processing facilities. We estimate the total undiscounted amount of cash flows required to settle Greenfire’s decommissioning liabilities to be approximately CAD$206.5 million. A credit-adjusted discount rate of 12% and an inflation rate of 2.0% were used to calculate the decommissioning liabilities. A 1.0% change in the credit-adjusted discount rate would impact the discounted value of the decommissioning liabilities by approximately CAD$1.1 million with a corresponding adjustment to PP&E or net income (loss). We expect to settle decommissioning liabilities for periods through the year 2071.

 

The table below shows decommissioning liability for the periods indicated:

 

		Year ended December 31,
(CAD$ in thousands)		2022				2021
Balance, beginning of period			5,517				—
Initial recognition			—				1,957
Revaluation			1,283				3,262
Accretion expense			743				298
Balance, end of period			7,543				5,517

 

Capital Resources and Liquidity

 

The Company’s capital management objective is to maintain financial flexibility and sufficient liquidity to execute on planned capital programs, while meeting short and long-term commitments, including servicing and repaying long term debt. The Company strives to actively manage its capital structure in response to changes in economic conditions and further deleverage its balance sheet.

 

At December 31, 2023, the Company’s capital structure was primarily comprised of cash and cash equivalents, restricted cash, long-term debt and shareholders’ equity.

 

 

Lower oil sales and production volumes in the year ended December 31, 2023 relative to the prior year were partially offset by the release of CAD$43 million of restricted cash in connection with the EDC Facility and management believes the Company’s current capital resources, including its ability to borrow or raise additional funds, and its ability to manage cash flow and working capital levels, will allow the Company to meet its current and future obligations, to make scheduled interest and principal payments, and to fund the other needs of the business.

 

However, the Company may be unable to borrow or raise sufficient funds or enter into such other arrangements, when needed, on favorable terms or at all. To the extent that we raise additional capital through the sale of equity or convertible debt securities, the ownership interest of our shareholders will be, or could be, diluted, and the terms of these securities may include liquidation or other preferences that adversely affect the rights of our shareholders.

 

Sales of a substantial number of Common Shares in the public market by the Selling Securityholders and/or by our other existing securityholders, or the perception that those sales might occur, could depress the market price of our Common Shares and could impair our ability to raise capital through the sale of additional equity securities.

 

As of April 29, 2024 there were 69,074,130 Common Shares issued and outstanding, and the total number of Resale Shares being offered for resale in this prospectus represents approximately 61% of our current total outstanding Common Shares, assuming the exercise of all Company Warrants of the Selling Securityholders. Further, certain Selling Securityholders beneficially own a significant percentage of our outstanding Common Shares. As of April 29, 2024, (i) the Greenfire Holders beneficially owned, in the aggregate 32,577,645 Common Shares (representing approximately 49% of all outstanding Common Shares when including 3,098,789 Common Shares issuable upon exercise of Company Warrants of those holders), and (ii) MBSC Sponsor beneficially owned 3,850,000 Common Shares (representing approximately 9% of the Common Shares when including 2,526,667 Common Shares issuable upon exercise of Company Warrants of MBSC Sponsor). The restrictions of the Lock-up Agreement applicable to MBSC Sponsor, the Greenfire Holders and the other Company shareholders party thereto applied through March 18, 2024, when those restrictions expired. Following the expiration of the restrictions in the Lock-Up Agreement, MBSC Sponsor, the Greenfire Holders and the other Company shareholders party thereto, can sell, or indicate an intention to sell, any or all of their Common Shares in the public market for so long as the registration statement of which this prospectus forms a part is available for use or such sales are otherwise permitted under Rule 144. Certain of the PIPE Investors are also significant shareholders. The sale of substantial amounts of Common Shares in the public market by any of the Selling Securityholders, or the perception that such sales could occur, could result in a substantial decline in the trading price of the Common Shares. These sales, or the possibility that these sales may occur, also might make it more difficult for the Company to sell Common Shares in the future at a time and at a price that it deems appropriate. There can be no assurance as to the timing of any disposition of Common Shares by any of the Selling Securityholders.

 

In addition, following the Business Combination, we had 7,526,667 Company Warrants and 3,617,016 Company Performance Warrants outstanding. Whether holders will exercise their warrants, and therefore the amount of cash proceeds we would receive upon exercise, is dependent upon the trading price of the Common Shares. The Company Warrants have an exercise price of $11.50 per share, and the Company Performance Warrants have an exercise price that ranges from CAD$2.14 to CAD$11.08. The last reported sales price for the Common Shares on the NYSE on May 8, 2024 was $5.87 per share. Those warrants may not be, or remain, in the money during the period they are exercisable and they may not be exercised prior to their maturity, even if they are in the money, and as such, we may receive minimal proceeds, if any, from the exercise of warrants. To the extent that any of the warrants are exercised on a “cashless basis,” we will not receive any proceeds upon such exercise. As a result, we do not expect to rely on the cash exercise of warrants to fund our operations and we do not need such proceeds in order to support working capital and capital expenditure requirements for the next twelve months. Instead, we intend to rely on the sources of cash described herein and elsewhere in this prospectus, if available on reasonable terms or at all. The Company plans to use its current cash on hand, available borrowing capacity on the Credit Facility and funds from operations to support its operations and meet its current and long term financial obligations. If we are unable to raise additional funds through equity or debt financings when needed, we may be required to delay, limit, or substantially reduce our operations.

 

Long Term Debt

 

On August 12, 2021, the Company issued US$312.5 million of 2025 Notes. The 2025 Notes were senior secured notes that had an original issue discount of 3.5%, bore interest at the fixed rate of 12.00% per annum, payable semi-annually, and had a maturity date of August 15, 2025.

 

On September 20, 2023, in conjunction with the closing of the Business Combination and the issuance of 2028 Notes as described below, the Company redeemed the outstanding balance of CAD$294.6 million (US$217.9 million) on the 2025 Notes at a redemption premium of 106.5%, plus accrued interest of CAD$3.4 million. The total Debt Redemption Premium paid as a result of the early redemption was CAD$19.2 million (US$14.2 million) plus accrued interest of CAD$3.4 million (US$2.5 million). Unamortized debt costs of $42.1 million were also expensed in conjunction with the extinguishment of the debt.

 

On September 20, 2023, the Company issued US$300.0 million of 2028 Notes. The 2028 Notes are senior secured notes that bear interest at the fixed rate of 12.00% per annum, payable semi-annually on April 1 and October 1 of each year, commencing on April 1, 2024, and mature on October 1, 2028. The 2028 Notes are secured by a lien on substantially all the assets of the Company and its wholly owned subsidiaries, junior in priority to the Senior Credit Facility. Subject to certain exceptions and qualifications, the indenture governing the 2028 Notes contains certain covenants that limit the Company’s ability to, among other things, incur additional indebtedness, pay dividends, redeem stock, make certain restricted payments, and dispose of and transfer assets. The indenture governing the 2028 Notes has a minimum hedging requirement of 50% of the forward 12 calendar month PDP forecasted production as prepared in accordance with the Canadian standards under National Instrument 51-101 – Standards for Disclosure for Oil and Gas Activities until principal debt under the 2028 Notes is less than US$100.0 million and limits capital expenditures to US$100.0 million annually until the principal outstanding is less than US$150.0 million.

 

 

Under the indenture governing the 2028 Notes, the Company is required to redeem the 2028 Notes at 105% of the principal amount plus accrued and unpaid interest with 75% of Excess Cash Flow (as defined in the indenture governing the 2028 Notes) in six-month periods, with the first period beginning on June 30, 2024. If Consolidated Indebtedness is less than US$150.0 million, the required redemption is reduced to 25% of Excess Cash Flow to be paid in every six-month period until the principal outstanding on the 2028 Notes is less than $100.0 million.

 

As at December 31, 2023, the carrying value of the Company’s long-term debt was CAD$376.4 million and the fair value was CAD$394.1 million (December 31, 2022 carrying value – CAD$254.4 million, fair value – CAD$315.7 million).

 

The Company is exposed to foreign exchange rate fluctuations on the principal value and interest payments in respect of the 2028 Notes. As of December 31, 2023, a 10% change to the value of the Canadian dollar relative to the US dollar would result in a foreign exchange gain (loss) of approximately CAD$39.7 million (December 31, 2022 - $29.3 million, December 31, 2021 - CAD$39.6 million).

 

Senior Credit Facility

 

On September 20, 2023, the Company also entered into the Credit Agreement, providing for a senior reserve-based credit facility comprised of an operating facility and a syndicated facility (the “Senior Credit Facility”). Total credit available under the Senior Credit Facility is CAD$50.0 million, comprised of a CAD$20.0 million operating facility and a CAD$30.0 million syndicated facility.

 

The Senior Credit Facility is a committed facility available on a revolving basis until September 20, 2024, at which point in time it may be extended at the lender’s option. If the revolving period is not extended, the undrawn portion of the facility will be cancelled and any amounts outstanding would be repayable at the end of the non-revolving term, being September 20, 2025. The Senior Credit Facility is subject to a semi-annual borrowing base review, occurring in May and November of each year, with the first review scheduled in May 2024. The borrowing base is determined based on the lender’s evaluation of the Company’s petroleum and natural gas reserves and their commodity price outlook at the time of each renewal.

 

The Senior Credit Facility is secured by a first priority security interest on substantially all the assets of the Company and is senior in priority to the 2028 Notes. The Senior Credit Facility contains certain covenants that limit the Company’s ability to, among other things, incur additional indebtedness, create or permit liens to exist, make certain restricted payments, and dispose of or transfer assets.

 

Amounts borrowed under the Senior Credit Facility bear interest at a floating rate based on the applicable Canadian prime rate, US base rate, secured overnight financing rate or bankers’ acceptance rate, plus a margin of 2.75% to 6.25% based on Debt to EBITDA ratio. A standby fee on the undrawn portion of the Senior Credit Facility ranges from 0.6875% to 1.5625% based on Debt to EBITDA ratio. As at December 31, 2023, the Company had no amounts drawn under the Senior Credit Facility.

 

On November 1, 2023, the Company entered into an unsecured CAD$55.0 million letter of credit facility with a Canadian bank that is supported by a performance security guarantee from Export Development Canada (the “EDC Facility”). The EDC Facility is available on a demand basis and letters of credit issued under this facility incur an issuance and performance guarantee fee of 4.25%. As at December 31, 2023, the Company had CAD$54.3 million drawn under the EDC Facility.

 

Restricted Cash and Letter of Credit Facilities

 

In November 2023, the Company replaced the CAD$46.8 million credit facility with the Petroleum Marketer that was used to issue letters of credit related to the Company’s long-term pipeline transportation agreements with the new EDC Facility, which resulted in the release of the $43.3 million of restricted cash. 

 

Working Capital (Deficit) and Adjusted Working Capital

 

Working capital (deficit) is a GAAP measure that is the most directly comparable measure to adjusted working capital which is a non-GAAP measure.

 

As at December 31, 2023, working capital increased to CAD$33.5 million from a working capital deficit of CAD$13.4 million as at December 31, 2022, a difference of CAD$46.9 million, primarily due to an increase in cash and cash equivalents from the proceeds from the issuance of the 2028 Notes, as well as a decrease to the current liability portion of risk management contracts.

 

Adjusted working capital increased to CAD$78.3 million at year-end 2023, from CAD$76.9 million as at December 31, 2022, a difference of CAD$1.4 million, primarily due to an increase in cash and cash equivalents from the proceeds from the issuance of the 2028 Notes, partially offset by the recognition of the fair value of the Company Warrants issued to former holders of Greenfire Common Shares, Greenfire Bond Warrant holders and Greenfire Performance Warrants holders.

 

 

The following table shows a reconciliation of working capital (deficit) to adjusted working capital for the periods indicated:

 

		Year ended				Year ended
		December 31,				December 31,
(CAD$ thousands)		2023				2022
Current assets			163,814				123,527
Current liabilities			(130,283	)			(136,921	)
Working capital (deficit)			33,531				(13,394	)
Current portion of risk management contracts			417				27,004
Current portion of long-term debt			44,321				63,250
Adjusted working capital(1)			78,269				76,860

 

(1)	Non-GAAP measures do not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the “— Non-GAAP Measures” section in this MD&A for further information.

 

Cash Flow Summary

 

The following table shows a summary of cash flows for the periods indicated:

 

		Three months ended December 31,								Year ended December 31,
(CAD$ thousands, unless otherwise noted)		2023				2022				2023				2022
Cash provided (used) by:
Operating activities			25,530				17,322				86,548				164,727
Financing activities			(51	)			(62,926	)			2				(123,638	)
Investing activities			18,732				(17,316	)			(12,153	)			(63,746	)
Exchange rate impact on cash and cash equivalents held in foreign currency			(713	)			(1,539	)			(285	)			(2,849	)
Change in cash and cash equivalents			43,854				(64,459	)			74,162				(25,506	)

 

Cash Provided (used) by Operating Activities 

 

Cash provided by operating activities in the fourth quarter of 2023 was CAD$25.5 million compared to CAD$17.3 million in the same period in 2022, with the increase primarily due to changes in non-cash working capital and lower diluent expense, partially offset by lower oil sales volumes during the fourth quarter of 2023.

 

For the year ended December 31, 2023, cash provided by operating activities was CAD$86.5 million compared to CAD$164.7 million in 2022, primarily due to lower realized WCS benchmark oil prices and lower production, partially offset by CAD$10.2 million of realized risk management contract losses in 2023, compared to CAD$122.4 million of realized risk management contract losses in 2022.

 

Based on current and forecasted production levels, operating expenses, capital expenditures, existing commodity price risk management contracts and current outlook for commodity prices, the Company expects cash from operating activities will be sufficient to cover its operational commitments and financial obligations under the indenture governing the 2028 Notes and the credit agreement governing the Senior Credit Facility in the next 12 months. 

 

Cash Provided (used) by Financing Activities 

 

In 2023, cash used by financing activities in the fourth quarter was CAD$51,000 compared to cash used by financing activities of CAD$62.9 million in the same period in 2022, mainly from a debt principal repayment on the 2025 Notes during the fourth quarter of 2022. During the year ended December 31, 2023, cash provided by financing activities was CAD$2,000 as the issuance of the 2028 Notes offset the redemption of the 2025 Notes and the Business Combination, compared to cash used by financing activities of CAD$123.6 million in the same period in 2022, mainly from debt principal repayments on the 2025 Notes during the year ended 2022.

 

Cash Provided (used) in Investing Activities

 

During the three months ended December 31, 2023, cash provided by investing activities was CAD$18.7 million compared to cash used in investing activities of CAD$17.3 million in the same period in 2022, with the difference in 2023 primarily due to the Company transferring CAD$43.3 million in outstanding letters of credit from restricted cash to cash and cash equivalents as part of the EDC Facility. Additionally, the increase to cash provided (used) in investing activities during the fourth quarter of 2023 was partially offset by higher capital expenditures.

 

Cash used in investing activities during 2023 was CAD$12.1 million compared to cash used in investing activities of CAD$63.7 million in 2022, also attributable to the transfer of CAD$43.3 million in outstanding letters of credit from restricted cash to cash and cash equivalents as part of the EDC Facility, along with lower capital expenditures during the year ended 2023.

 

Capital Expenditures

 

Total capital expenditures for the three and twelve months ended December 31, 2023 was CAD$19.4 million (2022 - CAD$12.4 million) and CAD$33.4 million (2022 - CAD$39.6 million). The Company spent CAD$14.9 million and CAD$22.8 million in the fourth quarter, and full year 2023 respectively, on the Refill wells for the drilling program at the Expansion Asset, as well as CAD$4.5 million and CAD$10.6 million spent on various facility projects at the Demo Asset and the Expansion Asset for the same respective periods.

 

 

Adjusted Funds Flow and Adjusted Free Cash Flow

 

Cash provided (used) by operating activities is a GAAP measure that is the most directly comparable measure to adjusted funds flow and adjusted free cash flow, which are non-GAAP measures.

 

During the three months and year ended December 31, 2023, the Company had cash provided by operating activities of CAD$25.5 million and CAD$86.5 million, respectively, compared to cash provided by operating activities of CAD$17.3 million and CAD$164.7 million, during the comparative periods in 2022.

 

Adjusted funds flow was CAD$10.5 million, during the three months ended December 31, 2023, compared to CAD$16.9 million, during the same period in 2022. The decrease in adjusted funds flow during the fourth quarter of 2023 was primarily the result of lower oil sales volumes, partially offset by lower diluent expense.

 

Adjusted funds flow was CAD$73.2 million, during the year ended December 31, 2023, compared to CAD$163.9 million, during the same period in 2022. The decrease in adjusted funds flow during the year ended December 31, 2023, was primarily the result of lower oil sales and lower realized WCS benchmark oil prices, which was partially offset by the Company recognizing CAD$10.2 million of realized risk management contract losses in 2023, compared to CAD$122.4 million in risk management contract losses during the same period in 2022.

 

During the three months ended December 31, 2023, the Company had negative adjusted free cash flow of CAD$8.9 million, compared to positive adjusted free cash flow of CAD$4.5 million during the same period in 2022. The decrease in adjusted free cash flow during the fourth quarter of 2023 was primarily the result of lower sales volumes and higher capital expenditures, partially offset by lower diluent expense. Adjusted free cash flow during the year ended December 31, 2023 was CAD$39.8 million compared to $124.3 million during the same period in 2022, with the decrease primarily due to lower oil sales and lower realized WCS benchmark oil prices, partially offset by the recognition of CAD$10.2 million of realized risk management contract losses in 2023, compared to CAD$122.4 million in risk management contract losses during the same period in 2022.

  

The following table shows a reconciliation of cash provided (used) in operating activities to adjusted funds flow and adjusted free cash flow for the periods indicated:

 

		Three months ended December 31,								Year ended December 31,
(CAD$ thousands)		2023				2022				2023				2022
Cash provided (used) by operating activities			25,530				17,322				86,548				164,727
Transaction costs			3,848				2,769				12,172				2,769
Changes in non-cash working capital			(18,861	)			(3,189	)			(25,514	)			(3,570	)
Adjusted funds flow(1)			10,517				16,902				73,206				163,926
Capital expenditures			19,413				12,361				33,428				39,592
Adjusted free cash flow(1)			(8,896	)			4,541				39,778				124,334

 

(1)

Non-GAAP measures do not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the “Non-GAAP Measures” in this MD&A for further information.

 

Commitments And Contingencies

 

Management believes its current capital resources, combined with its ability to manage cash flow and working capital levels, will enable the Company to meet its current and future obligations, make scheduled interest and principal payments, and fund other business needs. In the short term, the Company anticipates meeting its cash requirements through a combination of cash on hand, operating cash flows, and potentially accessing available credit facilities. However, the Company acknowledges the potential impact of any adverse changes in economic conditions or unforeseen expenses on its ability to generate adequate cash in the short term.

 

The Company enters into commitments and contractual obligations in the normal course of operations. The following table is a summary of management’s estimate of the contractual maturities of obligations as at December 31, 2023:

 

($ thousands)		1 Year				2-3 Years				4-5 Years				Thereafter				Total
Transportation			31,880				59,517				58,214				203,198				352,809
Office lease commitments(1)			299				598				598				1,496				2,992
Drilling services			5,845				8,635				-				-				14,480
Total annual commitments			38,024				68,750				58,812				204,694				370,281
Accounts payable and accrued liabilities			59,850				-				-				-				59,850
Long-term debt - Principal(2)			44,321				108,340				244,239				-				396,900
Long-term debt - Interest(2)			48,048				74,066				56,349				-				178,463
Risk management contracts			417				-				-				-				417
Lease obligations			157				284				333				1,015				1,789
Decommissioning obligations(3)			-				81				6,542				199,911				206,534
Total contractual obligations			152,793				182,771				307,463				200,926				843,953
Total future payments			190,817				251,521				366,275				405,620				1,214,234

 

(1)

Relates to non-lease components and variable operating cost payments.

 

 

(2)

This represents the estimated principal repayments of the 2028 Notes and associated interest payments based on interest and foreign exchange rates in effect on December 31, 2023.

 

(3)

These values are undiscounted and will differ from the amounts presented in the 2023 Financial Statements.

 

Non-GAAP Measures

 

In this MD&A and elsewhere in this prospectus, we refer to certain financial measures (such as adjusted EBITDA, adjusted EBITDA per barrel ($/bbl), operating netback, operating netback per barrel ($/bbl), adjusted funds flow, adjusted free cash flow, adjusted working capital, and net debt) which do not have any standardized meaning prescribed by IFRS. While these measures are commonly used in the oil and natural gas industry, our determination of these measures may not be comparable with calculations of similar measures presented by other issuers. Management believes that these financial measures provide useful information to evaluate the financial results of the Company.

 

Adjusted EBITDA

 

Net income (loss) and comprehensive income (loss) is the most directly comparable GAAP measure for adjusted EBITDA, which is a non-GAAP measure. Adjusted EBITDA is calculated as net income (loss) before interest and financing expenses, income taxes, depletion, depreciation and amortization and the transaction and financing cost impacts of the Business Combination and refinancing of the 2025 Notes, and is adjusted for certain non-cash items, or other items that are not considered part of normal business operations. Adjusted EBITDA is used to measure the Company’s profitability from its underlying asset base on a continuing basis. This measure is not intended to represent net income (loss) and comprehensive income (loss) in accordance with IFRS. See the “Results of Operations – Net Income (loss) and comprehensive income (loss) and Adjusted EBITDA” section in this MD&A for a reconciliation of net income (loss) and comprehensive income (loss) to adjusted EBITDA.

 

Operating Netback

 

Oil sales is the most directly comparable GAAP measure for operating netback, which is a non-GAAP measure. This measure is not intended to represent oil sales, net earnings or other measures of financial performance calculated in accordance with IFRS. Operating netback is comprised of oil sales, less diluent expense, royalties, operating expense, transportation and marketing expense, adjusted for realized commodity risk management gains or losses, as appropriate. Operating netback is a financial measure widely used in the oil and gas industry as a supplemental measure of a Company’s efficiency and ability to generate cash flow for debt repayments, capital expenditures or other uses. See the “Results of Operations – Operating Netback” section in this MD&A for a reconciliation of oil sales to operating netback.

 

Adjusted Funds Flow

 

Cash provided by operating activities is the most directly comparable GAAP measure for adjusted funds flow, which is a non-GAAP measure. This measure is not intended to represent cash provided (used) by operating activities calculated in accordance with IFRS. The adjusted funds flow measure allows management to evaluate the Company’s ability to fund its capital programs and meet its ongoing financial obligations using cash flow internally generated from ongoing operating related activities. We compute adjusted funds flow as cash provided (used) by operating activities, excluding the impact of changes in non-cash working capital, less transaction costs. For a reconciliation of cash provided (used) by operating activities to adjusted funds flow, see the “Capital Resources and Liquidity – Adjusted Funds Flow and Adjusted Free Cash Flow” section in this MD&A.

 

Adjusted Free Cash Flow

 

Cash provided (used) by operating activities is the most directly comparable GAAP measure for adjusted free cash flow, which is a non-GAAP measure. Management uses adjusted free cash flow as an indicator of the efficiency and liquidity of its business, measuring its funds after capital investment that is available to manage debt levels and return capital to shareholders. By removing the impact of current period capital expenditures from adjusted free cash flow, management monitors its adjusted free cash flow to inform its capital allocation decisions. We compute adjusted free cash flow as cash provided (used) by operating activities, excluding the impact of changes in non-cash working capital, less transaction costs and capital expenditures. For a reconciliation of cash provided (used) by operating activities to adjusted free cash flow, see “— Capital Resources and Liquidity — Adjusted Funds Flow and Adjusted Free Cash Flow” section in this MD&A.

 

 

Adjusted Working Capital

 

Working capital (deficit) is a GAAP measure that is the most directly comparable measure to adjusted working capital. These measures are not intended to represent current assets, net earnings or other measures of financial performance calculated in accordance with IFRS. Adjusted working capital is comprised of current assets less current liabilities on the Company’s balance sheet, and excludes the current portion of risk management contracts and current portion of long-term debt, the latter of which is subject to estimates in future commodity prices, production levels and expenses, among other factors. Adjusted working capital is included within the non-GAAP measures because it is a less volatile measure of current assets and current liabilities, after isolating for current portion of long-term debt and current portion of risk management contracts, a surplus of adjusted working capital will result in a future net cash inflow to the business that can be used by management to evaluate the Company’s short-term liquidity and its capital resources available at a point in time. A deficiency of adjusted working capital will result in a future net cash outflow, which may result in the Company not being able to settle short-term liabilities more than current assets. For a reconciliation of working capital (deficit) to adjusted working capital, see “— Capital Resources and Liquidity — Adjusted Working Capital” section in this MD&A.

  

Net Debt

 

Long-term debt is a GAAP measure that is the most directly comparable financial statement measure to net debt. These measures are not intended to represent long-term debt calculated in accordance with IFRS. Net debt is comprised of long-term debt, adjusted for current assets and current liabilities on the Company’s balance sheet, and excludes the current portion of risk management contracts and current portion of warranty liability. Management uses net debt to monitor the Company’s current financial position and to evaluate existing sources of liquidity. Net debt is used to estimate future liquidity and whether additional sources of capital are required to fund planned operations.

 

The following tables show a reconciliation of long-term debt to net debt for the periods indicated:

 

		Year ended				Year ended
		December 31,				December 31,
(CAD$ thousands)		2023				2022
Long-term debt			(332,029	)			(191,158	)
Current assets			163,814				123,527
Current liabilities			(130,283	)			(136,921	)
Current portion of risk management contracts			417				27,004
Current portion of warrant liability			18,630				-
Net debt			(279,451	)			(177,548	)

 

Non-GAAP Financial Ratios

 

Adjusted EBITDA ($/bbl)

 

Net income (loss) and comprehensive income (loss) is the most directly comparable GAAP measure for adjusted EBITDA, which is a non-GAAP measure. Adjusted EBITDA is calculated as net income (loss) before interest and financing expenses, income taxes, depletion, depreciation and amortization and the transaction and financing cost impacts of the Business Combination and refinancing of the 2025 Notes, and is adjusted for certain non-cash items, or other items that are not considered part of normal business operations. Adjusted EBITDA is used to measure the Company’s profitability from its underlying asset base on a continuing basis. This measure is not intended to represent net income (loss) and comprehensive income (loss) in accordance with IFRS..

 

Operating Netback ($/bbl)

 

Oil sales ($/bbl) is a ratio calculated using oil sales, which is the most directly comparable GAAP measure for operating netback. Operating netback is the non-GAAP financial measure used to calculate operating netback ($/bbl), which is a non-GAAP financial ratio. This measure is not intended to represent oil sales, net earnings or other measures of financial performance calculated in accordance with IFRS. Operating netback ($/bbl) is calculated by dividing operating netback by the Company’s total oil sales volume, in a specified period. Operating netback ($/bbl) is a non-GAAP financial ratio widely used in the oil and gas industry as a supplemental measure of a Company’s efficiency and ability to generate cash flow for debt repayments, capital expenditures or other uses, isolated for the impact of changes in oil sales volume, in a specified period.

 

Critical Accounting Policies and Estimates

 

The Company’s critical accounting policies and estimates are those estimates having a significant impact on the financial position and operations that require management to make judgements, assumptions and estimates in the application of IFRS. Judgements, assumptions and estimates are based on the historical experience and other factors that management believes to be reasonable under current conditions. As events occur and additional information becomes available, these judgements, assumptions and estimates may be subject to change. Detailed disclosure of the material accounting policies and the significant accounting estimates, assumptions and judgements can be found in Note 3 “Material Accounting Policies” in the Company’s financial statements for the period ended December 31, 2023.

 

 

Quantitative and Qualitative Disclosure about Market Risk

 

The Company is exposed to market risk, including the effects of adverse changes in commodity prices and exchange rates. The primary objective of the following information is to provide quantitative and qualitative information about the Company’s potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in commodity prices and currency exchange rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of the Company’s market risk sensitive instruments were entered into for purposes other than speculative trading. Also, gains and losses on these instruments are generally offset by losses and gains on the offsetting expenses.

 

Commodity Price Risk

 

The Company’s major market risk exposure is in the pricing that we receive for the Company’s bitumen production. Bitumen prices have been volatile and unpredictable for several years, and this volatility may continue in the future. The prices we receive for the Company’s bitumen production depend on many factors outside of its control, such as the strength of the global economy and global supply and demand for oil and gas.

 

To reduce the impact of fluctuations in bitumen prices on the Company” revenues, we periodically enter into forward, fixed-priced, physical delivery, purchase and sales contracts to manage commodity price risk, as descried above under the heading“—Results of Operations—Risk Management Contracts”. The Company plans to continue its practice of entering into such transactions to reduce the impact of commodity price volatility on its cash flow from operations. Future transactions may include price swaps whereby we will receive a fixed price for its production and pay a variable market price to the contract counterparty.

 

Currency exchange rate risk

 

Currency exchange rate risk is the risk that the fair value of future cash flows will fluctuate as a result of changes in foreign exchange rates. The Company’s sales are in Canada and denominated in Canadian dollars, however, Canadian commodity prices are influenced by fluctuations in the Canada to U.S. dollar exchange rate as global oil prices are generally denominated in U.S. dollars.

 

The Company is also exposed to currency risk in relation to the 2028 Notes, which are denominated in U.S. dollars. To date, realized foreign currency transaction gains and losses have not been material to the Company; financial statements. We have not engaged in the hedging of foreign currency transactions to date, although we may choose to do so in the future.

 

Credit risk

 

Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its contractual obligations and arises principally from the Company’s accounts receivable. The Company is primarily exposed to credit risk from receivables associated with its oil sales. We manage the Company’s credit risk exposure by transacting with high-quality credit worthy counterparties and monitoring credit worthiness and/or credit ratings on an ongoing basis. As of December 31, 2023, the Company was exposed to concentration risk associated with its outstanding trade receivables and joint interest receivable balances as they are held by a single counterparty. The following table shows account receivables for the periods indicated:

 

		As at December 31,
(CAD$ in thousands)		2023				2022				2021
Trade receivables		$	22,452				22,428				35,020
Joint interest receivables			12,228				11,880				8,942
Accounts receivable		$	34,680				34,308				43,962

 

 

Comparison of results of operations of JACOS for the period from January 1, 2021 to September 17, 2021 to the year ended December 31, 2020

 

The following is a discussion by Greenfire’s management of the results of operations of JACOS for the period ended September 17, 2021 and for the year ended December 31, 2020. Those results relate to JACOS, prior to and without giving pro forma effect to its acquisition by Greenfire on September 17, 2021 and any operations of Greenfire, which commenced in April of 2021. This discussion is presented as supplemental information for comparability purposes, to aid the reader in evaluating our business, financial condition, results of operations and prospects, considering the historical results of operations of JACOS. Because the period presented in 2021 is not for a full year, certain data presented are not entirely comparable to amounts for the 2020 year.

 

(CAD$ in thousands, unless otherwise noted)		Period from January 1, 2021 to September 17, 2021				Year ended December 31, 2020
Bitumen production (bbls/d)			16,875				15,283
Oil sales (bbls/d)			16,944				15,728
Property, plant and equipment expenditures			9,757				27,478
Total assets			372,096				379,592
Oil sales			382,635				279,248
Diluent expense			(171,174	)			(158,272	)
Royalties			(7,178	)			(2,019	)
Transportation and marketing expenses			(27,853	)			(39,368	)
Operating expenses			(56,479	)			(67,409	)
Depletion and depreciation			(78,267	)			(108,379	)
Impairment			73,252				(270,000	)
Financing and interest			(11,154	)			(21,602	)
Net income (loss)			104,833				(378,612	)

 

Production

 

JACOS’s daily average production of 16,875 bbls/day for the period ended September 17, 2021, was higher than the year ended December 31, 2020, of 15,283 bbls/day. Management believes price-related curtailments in the second quarter of 2020, when commodity prices were depressed as a result of the COVID-19 pandemic, contributed to the increase.

 

Oil Sales

 

JACOS’s oil sales for the period ended September 17, 2021, were CAD$382.6 million compared to CAD$279.2 million for the year ended December 31, 2020. JACOS’s 2021 oil sales were higher, relative to the year ended 2020, primarily due to higher commodity pricing and pricing stability. See the section below under the heading “—Commodity Prices” for a discussion of changes in commodity prices.

 

Commodity Prices

 

The market prices of crude oil, condensate, natural gas and electricity impacted the amount of cash generated from JACOS operating activities, which, in turn, impacted JACOS financial position and results of operations.

 

The WCS heavy oil price for the period ended September 17, 2021, averaged US$52.67/bbl compared to US$26.79/bbl for the year ended December 31, 2020.

 

JACOS was producing WDB at the Expansion Asset. The WDB price for the period ended September 17, 2021, averaged US$49.70/bbl compared to US$24.70/bbl for the year ended December 31, 2020.

 

The Edmonton Condensate (C5+) price for the period ended September 17, 2021, averaged US$64.90/bbl compared to US$37.48/bbl for the year December 31, 2021.

 

The AECO natural gas price increased to CAD$2.74 per gigajoule during the period ended September 17, 2021, compared to CAD$1.90 per gigajoule during the year ended December 31, 2021. The Alberta power pool price increased to CAD$98.66 per megawatt hour during the period ended September 17, 2021, compared to CAD$46.72 per megawatt hour during the year ended December 31, 2020.

 

 

The following table shows benchmark pricing of crude oil, natural gas and electricity for the periods indicated:

 

		Period from January 1, 2021 to September 17, 2021				Year ended December 31, 2020				% Change
Crude oil
WTI (US$/bbl)(1)			64.82				39.44				64
WCS differential to WTI (US$/bbl)			(12.15	)			(12.65	)			(4	)
WCS (US$/bbl)(2)			52.67				26.79				97
WDB (US$/bbl)(3)			49.70				24.70				101
Condensate at Edmonton (US$/bbl)			64.90				37.48				73
Natural gas
AECO ($/GJ)			2.74				1.90				44
Electricity
Alberta power pool ($/MWh)			98.66				46.72				111
Foreign exchange rate(4)
US$:CAD		$	1.2503				1.2535				—

 

(1)

As per NYMEX oil futures contract.

 

(2)

Reflects heavy oil prices at Hardisty, Alberta.

 

(3)

Blend stream comprised of Sunrise Dilbit Blend, Hangingstone Dilbit Blend, and Leismer Corner Blend.

 

(4)

US$ to CAD$ annual or quarterly average exchange rates reported by the Bank of Canada.

 

Royalties

 

Royalties for the period ended September 17, 2021, were CAD$1.64/bbl. Royalties for the year ended December 31, 2020, were CAD$0.35/bbl. The higher royalty per bitumen barrel for the period ended September 17, 2021, relative to the year ended December 31, 2020, was primarily the result of higher WTI prices.

 

(CAD$ in thousands, except as noted)		Period ended September 17, 2021				Year ended December 31, 2020				% Change
Royalties			7,178				2,019				256
–$/bbl			1.64				0.35				369

 

Diluent Expense

 

JACOS’s diluent expense includes the cost of diluent plus the pipeline transportation of the diluent from Edmonton to the Expansion Asset facility via the Inter Pipeline Polaris Pipeline. JACOS’s diluent expense for the period ended September 17, 2021, of CAD$11.94/bbl was 3% lower compared to the year ended December 31, 2020, of CAD$12.37/bbl which were due to changing commodity prices.

 

Transportation and Marketing Expense

 

JACOS’s transportation and marketing expense for the period ended September 17, 2021, of CAD$6.35/bbl was lower than the year ended December 31, 2020, of CAD$6.84/bbl, primarily due to higher sales volumes in a relatively higher commodity price environment.

 

Operating Expenses

 

Operating expenses include energy operating expenses and non-energy operating expenses. Energy operating expenses reflect the cost of natural gas to generate steam and electricity to operate the JACOS facilities. Non-energy operating expenses relate to production-related operating activities, including staff, contractors and associated travel and camp costs, chemicals and treating, insurance, property tax, greenhouse gas fees, equipment rentals, maintenance and site administration, among other costs.

 

The energy operating expenses were CAD$5.73/bbl for the period ended September 17, 2021, compared to CAD$4.35/bbl for the year ended December 31, 2020. Energy operating expenses were higher for the period ended September 17, 2021, relative to the year ended December 31, 2020, due to increases in both natural gas prices and electricity prices. Overall natural gas prices increased 44% and electricity prices increase 111% relative to 2020.

 

Non-energy operating expenses were CAD$7.14/bbl for the period ended September 17, 2021, compared to CAD$7.36/bbl for the year ended December 31, 2020. Non-energy operating expenses were lower in 2021 primarily as a result of higher production volumes.

 

 

The following table shows operating expenses of JACOS for the periods indicated:

 

(CAD$ in thousands, unless otherwise noted)		Period ended December 31, 2021				Year ended December 31, 2020				% Change
Energy operating expenses			25,145				23,031				9
Non-energy operating expenses			31,334				44,378				(29	)
Total operating expenses			56,479				67,409				(16	)
Energy operating expenses (CAD$/bbl)			5.73				4.35				32
Non-energy operating expenses (CAD$/bbl)			7.14				7.36				(3	)
Total operating expenses (CAD$/bbl)			12.87				11.71				10

 

Depletion and Depreciation

 

Total depletion and depreciation expense of CAD$78.3 million or CAD$17.83/bbl for the period ended September 17, 2021, was slightly lower on a per bbl basis than the CAD$108.4 million or $18.83/bbl for the year ended December 31, 2020, primarily due to a reduction of the depletable base as a result of the impairment incurred in 2020.

 

Impairment

 

For the period ended September 17, 2021, due to increases in forward oil prices, a test for impairment reversal was completed. The recoverable value was based on fair value less costs of disposal (“FVLCOD”). FVLCOD is the amount that would be realized from the disposition of an asset or CGU in an arm’s length transaction between knowledgeable and willing parties. As JACOS had a sales agreement is place with Greenfire, the asset was written up to the value assigned in the agreement, which was approximately CAD$298.5 million.

 

For the year ended December 31, 2020, due to the continued depressed oil prices as a result of the COVID-19 pandemic, JACOS determined that there were indicators of impairment for its CGU. The recoverable amount was not sufficient to support the carrying amount which resulted in an impairment of CAD$270 million. The recoverable amount was based on its FVLCOD which was estimated using a discounted cash flow model of proved plus probable cash flows from an independent reserve report prepared as at December 31, 2020.

 

Financing and interest

 

Interest and finance expense includes coupon interest on long term debt, interest on letter of credit facilities and other interest charges. Interest on long-term debt and other cash interest was significantly lower in 2021 due mainly to lower interest rates and also due to CAD$90 million is debt being retired in 2020 and 2021 (prior to all debt being repaid in September 2021). JACOS had outstanding debt with two institutions based in Japan (US$270 million with each as at December 31, 2020) each with different interest rates. In 2021 the average interest rates with the institutions were 1.26% and 0.36% compared to 2.9% and 2% in 2020.

 

(CAD$ in thousands)		For the period ended September 17, 2021				For the year ended December 31, 2020
Accretion on long-term debt		$	7,455			$	13,791
Guarantee fees			3,348				7,290
Interest on settlement of lease liability			31				77
Accretion on decommissioning liabilities			320				444
Financing and interest expense		$	11,154			$	21,602

 

Capital Expenditures

 

Total capital expenditures for the period ended September 17, 2021, were approximately CAD$9.8 million, consisting primarily of maintenance capital at the production facility of CAD$6.6 million, geological data acquisition of CAD$1.3 million and engineering costs of CAD$1.1 million. Total capital expenditures for the year ended December 31, 2020, were CAD$27.5 million, consisting of delineation drilling of CAD$13.9 million production facility capital of CAD$6.7 million, well equipment of CAD$4.0 million and engineering costs of CAD$1.4 million.

 

Liquidity

 

(CAD$ in thousands)		Period ended September 17, 2021				Year ended December 31, 2020				% Change
Cash provided by (used in):
Operating activities			44,534				(6,687	)			(766	)
Financing activities			(84,720	)			(79,579	)			6
Investing activities			(2,891	)			(30,100	)			(90	)
Exchange rate impact on cash and cash equivalent held in foreign currency			1,246				2,846				(56	)
Change in cash and cash equivalents			(41,831	)			(113,520	)			(63	)

 

 

MANAGEMENT

 

Directors and Senior Management

 

Name		Age		Position
Robert Logan		43		President, Chief Executive Officer and a Director
Tony Kraljic		49		Chief Financial Officer
Albert Ma		42		Senior Vice President, Facilities and Engineering
Kevin Millar		60		Senior Vice President, Operations and Steam Chief
Crystal Park		48		Senior Vice President, Corporate Development
Jonathan Klesch		47		Director
Julian McIntyre		48		Director, Chair of the Company Board
Venkat Siva		41		Director
Matthew Perkal		38		Director
W. Derek Aylesworth		61		Director

 

Executive Officers

 

Robert B. Logan, MPBE, P.Eng. — President, Chief Executive Officer and a Director

 

Mr. Logan is the President and Chief Executive Officer and a director of the Company. Prior to Greenfire’s inception in September, 2021, he was the President and Chief Executive Officer of GAC. Mr. Logan co-founded GHOPCO and its parent company, Greenfire Oil and Gas Ltd., in 2016. From 2016 to 2020, Mr. Logan was the President, Chief Executive Officer and a director of GHOPCO, which previously owned and operated the Demo Asset and entered into the NOI Proceedings in 2020. After the insolvency of GHOPCO, several private actions were commenced by former shareholders and creditors of GHOPCO, against certain directors and officers of GHOPCO, including Mr. Logan, alleging various claims with respect to their losses as shareholders and creditors of GHOPCO and seeking a derivative action. Prior to co-founding GHOPCO, he was the Asset Manager of the West Ells SAGD project from 2011 to 2016 for Sunshine Oilsands Ltd. He has held multiple roles in other thermal oil sands and SAGD developments including at Petrobank Energy Resources Ltd. on the Kerrobert and Whitesands toe-to-heel air injection (THAI) in-situ oil sands projects, the Statoil Canada Ltd. Leismer SAGD projects and with Petrospec Engineering. Mr. Logan graduated with a Bachelor of Science in Petroleum Engineering from the University of Alberta and holds a Master’s Degree in Petroleum Business Engineering from the Delft University of Technology in the Netherlands. He is a member of the Association of Professional Engineers and Geoscientists of Alberta as well as Montana Board of Professional Engineers and Professional Land Surveyors.

 

Tony Kraljic — Chief Financial Officer

 

Mr. Kraljic was appointed the Chief Financial Officer of the Company on October, 2023. From July 31, 2023 to September 30, 2023, Mr. Kraljic served as Director, Corporate Strategy of the Company and Greenfire. Prior to joining the Company, Mr. Kraljic was the Chief Financial Officer of Western Zagros Resources Ltd. (“WesternZagros”) from August 2017 to May 2023. Since commencing employment at WesternZagros in August 2012, Mr. Kraljic served as the principal financial officer of WesternZagros and was responsible for Finance and Accounting and Contracts and Procurement. Mr. Kraljic has over 25 years of finance, accounting, and tax experience. He has held multiple roles with CEDA International Corporation, Western Oil Sands Inc., Shell Canada and Arthur Anderson LLP. Mr. Kraljic holds a Bachelor of Commerce degree from the University of British Columbia and is a member of the Institute of Chartered Professional Accountants of Alberta.

 

Albert Ma, P.Eng. — Vice President, Facilities and Engineering

 

Mr. Ma is the Senior Vice President, Facilities and Engineering of the Company. Mr. Ma was a Vice President of Engineering at GAC from December 2020 through April 2021, and served as Senior Facilities Engineer at GHOPCO from January 2020 through May 2020. From 2018 to 2019, Mr. Ma was a DCS specialist at GHOPCO. Prior to joining the predecessor companies, he was the Engineering Manager of Surface Systems at Petrospec Engineering for over 13 years. Mr. Ma graduated with a Bachelor of Science in Computer Engineering from the University of Alberta and he is a member of the Association of Professional Engineers and Geoscientists of Alberta.

 

Kevin Millar — Senior Vice President, Operations and Steam Chief

 

Mr. Millar is the Senior Vice President, Operations and Steam Chief of the Company. Mr. Millar was the Steam Chief of Greenfire Oil and Gas Ltd. and GHOPCO. Mr. Millar has over 30 years of experience managing in-situ oils and facilities ranging from 5,000 bbls/d such as Sunshine Oilsands to 30,000 bbls/d at Greenfire Hangingstone Expansion, with extensive expertise leading the commissioning and start-up for SAGD Corp., cogeneration and power plants for Connacher Oil and Gas Limited, Pembina Pipelines Corporation, Sunshine Oilsands Ltd., MEG Energy Corp. and Nexen Inc. Mr. Millar holds a First-Class Power Engineer designation from the Southern Alberta Institute of Technology.

 

Crystal Park — Senior Vice President, Corporate Development

 

Ms. Park is the Senior Vice President of Corporate Development of the Company. Ms. Park was the Vice President of Business Development at GAC from December 2020 through April 2021 and served as Senior Manager of Business Development at GHOPCO from December 2020 through September 2021. Ms. Park began her engineering career in facilities and production engineering at Crestar and Apache Canada and progressed into roles in corporate development and resource evaluations at AJM Deloitte, Enerplus, and Sunshine Oilsands. She has worked extensively in reserves, economic modelling, and consultant roles for Sproule, Pine Cliff Energy, and Devon Energy. Ms. Park graduated with a Bachelor of Science in Chemical Engineering from the University of Alberta and holds a Masters of Business Administration with a dual specialization in Finance and Global Energy Management from the University of Calgary. She is a member of the Association of Professional Engineers and Geoscientists of Alberta.

 

 

Directors

 

Jonathan Klesch

 

Mr. Klesch is the founder of Griffon Partners, an investment management company, with an emphasis on natural resources and infrastructure. Prior to founding Griffon Partners, Mr. Klesch spent over 20 years at the Klesch Group, which predominately owns and operates oil refineries. Mr. Klesch has extensive experience in commodities trading and structured finance transactions. Mr. Klesch holds a Bachelor of Arts in Finance from the School of Management at Boston University and has also received specialized training at Harvard Business School.

 

Julian McIntyre

 

Mr. McIntyre has been appointed as Chair of the Company Board. Mr. McIntyre is the founder of Arq Limited, an energy and chemicals technology business, which he started in 2015. Mr. McIntyre was also the founder of a large natural gas operator in the Rocky Mountains and founded Rift Petroleum, an African oil and gas exploration and production company that was sold to Tower Resources plc. Prior to that, in 2000, Mr. McIntyre founded Gateway Communications, a pan-African telecoms company that dealt with the provision of satellite and terrestrial private networks for multinationals operating in Africa. Mr. McIntyre holds a Bachelor of Science in Computer Science from the Queen Mary College, University of London.

 

Venkat Siva

 

Mr. Siva was the Chief Financial Officer of Arq Limited, an energy and chemicals technology business, founded in 2015, until its reorganization and sale transaction in February 2023. Mr. Siva has managed McIntyre Partners’ liquid/illiquids portfolio since 2009. At McIntyre Partners, he leads the due-diligence, deal execution and investment management efforts across several transactions in the energy, bulk commodities and infrastructure sectors. Prior to joining McIntyre Partners, Mr. Siva worked as a corporate finance banker within Goldman Sachs’ mergers and acquisition team. Mr. Siva holds a Post Graduate Diploma in Management from the Indian Institute of Management of Bangalore.

 

Matthew Perkal

 

Prior to the Business Combination, Matthew Perkal served as MBSC’s Chief Executive Officer and as Executive Vice President of MBSC. Mr. Perkal continues to serve as a member of the management team for Brigade-M3 European Acquisition Corporation and as a Partner and Head of Special Situations and SPACs at Brigade. Mr. Perkal has led MBSC’s industry coverage for various sectors including retail, consumer, gaming and lodging, and has structured and led many of the firm’s successful deals in the private credit space including Barney’s and Sears. Mr. Perkal currently serves on Guitar Center Inc.’s board of directors. Prior to joining Brigade, Mr. Perkal worked at Deutsche Bank as an Analyst in the Leveraged Finance Group. In that capacity, Mr. Perkal also spent time on the Leveraged Debt Capital Markets Desk, selling both bank and bond deals. Mr. Perkal received a BS in Economics with a concentration in Finance and Accounting from the University of Pennsylvania’s Wharton School.

 

W. Derek Aylesworth

 

W. Derek Aylesworth has over 30 years of experience in the Canadian oil and gas industry. He has served as the Chief Financial Officer of Seven Generations Energy Ltd., an oil and gas producer operating in western Canada, between March 2018 to April 2021. He has previously served as the CFO of Baytex Energy Corp. (NYSE:and TSX: BTE) between November 2005 until June 2014. Mr. Aylesworth holds a Bachelor of Commerce degree and is a chartered accountant with expertise in taxation and has experience as a tax advisor in both the oil and gas industry and public practice in Calgary.

 

Other Public Company Board Positions

 

The following directors of the Company are presently directors of other companies that are “reporting issuers” in a jurisdiction of Canada or the equivalent in another jurisdiction:

 

Name		Name of Public Company
Robert Logan		None
Jonathan Klesch		None
Julian McIntyre		Advanced Emissions Solutions, Inc. (Nasdaq: ADES)
Venkat Siva		None
Matthew Perkal		None
W. Derek Aylesworth		None

 

Family Relationships

 

There are no family relationships between any of the Company’s executive officers and directors.

 

 

Penalties or Sanctions, Individual Bankruptcies and Corporate Cease Trade Orders and Bankruptcies

 

None of the directors or executive officers of the Company, and to the best of the Company’s knowledge, no shareholder that, following completion of the Business Combination, is expected to hold a sufficient number of securities to affect materially the control of the Company, has been subject to any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority or has entered into a settlement agreement with a securities regulatory authority or been subject to any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor making an investment decision.

 

None of the directors or executive officers of the Company, and to the best of the Company’s knowledge, no shareholder that, following the completion of the Business Combination, is expected to hold a sufficient number of securities to affect materially the control of the Company, has, within the 10 years prior to the date of this prospectus, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or become subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold the assets of that individual.

 

Other than as disclosed below, none of the directors or executive officers of the Company, and to the best of the Company’s knowledge, no shareholder that, following the completion of the Business Combination, is expected to hold a sufficient number of securities to affect materially the control of the Company is, as at the date of this prospectus, or has been within the 10 years before the date of this prospectus: (a) a director, chief executive officer or chief financial officer of any company that was subject to an order that was issued while the director or executive officer was acting in the capacity as director, chief executive officer or chief financial officer; (b) was subject to an order that was issued after the director or executive officer ceased to be a director, chief executive officer or chief financial officer and which resulted from an event that occurred while that person was acting in the capacity as director, chief executive officer or chief financial officer; or (c) a director or executive officer of any company that, while that person was acting in that capacity, or within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets. For the purposes of this paragraph, “order” means a cease trade order, an order similar to a cease trade order or an order that denied the relevant company access to any exemption under securities legislation, in each case, that was in effect for a period of more than 30 consecutive days.

 

From 2016 to 2020, Mr. Logan was the President and a director of Greenfire Oil and Gas Ltd. and GHOPCO, which previously owned and operated the Demo Asset and entered into the NOI Proceedings in 2020. After the insolvency of GHOPCO, several private actions were commenced by former shareholders and creditors of GHOPCO, against certain directors and officers of GHOPCO, including Mr. Logan, alleging various claims with respect to their losses as shareholders and creditors of GHOPCO and seeking a derivative action

 

On August 25, 2023, a group of entities including, but not limited to, Griffon Partners Operation Corp. (“GPOC”) Griffon Partners Holding Corp. (“GPHC”) and Griffon Partners Capital Management Ltd. (“GPCM”), each filed Notices of Intention to Make a Proposal pursuant to the provisions of the Bankruptcy and Insolvency Act (Canada). As at December 31, 2023 Mr. Klesch was a director of each of GPOC, GPHC and GPCM.

 

Mr. Perkal was a director of Gymboree Group, Inc. (“Gymboree”) from September 29, 2017 through June 26, 2020. On January 16, 2019, Gymboree and 10 affiliated debtors each filed a voluntary petition for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Eastern District of Virginia (Richmond Division).

 

Greenfire Relationships and Related Party Transactions

 

For each of the fiscal years ended December 31, 2021, and December 31, 2022, Greenfire paid CAD$85,733 and CAD$276,063, respectively, in directors fees to each of Messrs. McIntyre, Siva, and Klesch.

 

There are no family relationships between any of the Company’s executive officers and directors or director nominees.

 

Investor Rights Agreement

 

Concurrently with the Closing, the Company entered into the Investor Rights Agreement with MBSC Sponsor and certain other holders named therein, pursuant to which, among other things, the Company agreed that, until the MBSC Sponsor and its affiliates own less than 3% of all outstanding Common Shares, as adjusted for stock splits, dividends, recapitalizations and similar changes, the MBSC Sponsor will have the right to designate one individual to be included in the slate of nominees recommended by the Company Board or duly constituted committee thereof for election as directors at each applicable annual meeting of the Company Board at which the term of the director nominated by the MBSC Sponsor would expire. If at any time the number of Common Shares, as may be adjusted as described above, owned by the MBSC Sponsor and its affiliates, in the aggregate, fall below 3% of all outstanding Common Shares and 50% of the number of Common Shares held by them as of the Closing, the director nominated by the MBSC Sponsor will resign as a member of the Company Board. The former Greenfire Shareholders party to the Investor Rights Agreement also agreed, for so long as the MBSC Sponsor has the right to designate a director to the Company Board, to vote all of their Common Shares in favor of the appointment of such designee. At the Closing, MBSC Sponsor appointed Matthew Perkal as its designee.

 

 

EXECUTIVE COMPENSATION

 

Compensation of the Company’s Executive Officers — Year Ended December 31, 2023

 

The following table sets forth information about certain compensation awarded to, earned by or paid to the Company’s: (i) President and Chief Executive Officer; (ii) Chief Financial Officer; (iii) and the next three highest compensated individuals (collectively referred to as the Company’s “NEOs”) for the year ended December 31, 2023.

 

								Short-term
(Dollar amounts in CAD$)				Salaries &				Benefits
Name		Title		Fees(1)				Other(2)(3)				Total
Robert Logan		President, Chief Executive Officer and Director		$	436,800.00			$	341,496.87			$	778,296.87
David Phung(4)		Chief Financial Officer		$	336,000.00			$	355,578.16			$	691,578.16
Tony Kraljic(4)		Chief Financial Officer		$	139,923.04			$	162,829.35			$	302,752.39
Albert Ma		Senior Vice President, Engineering		$	337,296.96			$	379,890.34			$	717,187.30
Kevin Millar		Senior Vice President, Operations		$	374,774.40			$	539,616.72			$	914,391.12
Darren Crawford		Vice President, Operations & Projects		$	307,315.06			$	313,059.63			$	620,374.69

 

(1)

“Salary and Fees” represents the actual salary amounts paid to executive officers in the fiscal year ending December 31, 2023, in CAD dollars.

 

(2)

“Other” represents bonuses earned by the executive officers for services in the fiscal year of 2023 and other fringe benefits provided to the executive officers, including vacation, retirement fund matching, flex spending accounts, camp and isolation allowance, travel allowance, health benefits, specialized technical designation compensation, life insurance, dependent life insurance, accidental death in CAD dollars & dismemberment, parking, executive medical assessments, health spending accounts, and additional Best Doctor’s coverage and loan settlements under the long term retention program in CAD dollars.

 

(3)

Mr. Phung resigned as Chief Financial Officer, and Mr. Kraljic was appointed as his successor, effective as of October 2023

 

(4)

Includes CAD$145,600 paid upon termination of Mr. Phung’s employment in accordance with his employment agreement.

 

Philosophy

 

The Company’s executive compensation program is designed to attract and retain high performing leaders and value creators. In efforts to continue the Company’s path for sustainable growth, the Company Board supports executive compensation that reinforces engagement, continuous improvement and optimizes corporate performance. The Company’s approach to executive compensation is competitive with peer Canadian oil and gas companies where there is substantial upside for high performance and downside for under performance.

 

The objectives of the program aim to provide competitive wages as compared to the Company’s peers, emphasize pay for performance through an annual short-term incentive program, and at-risk compensation that aligns executive and stakeholder’s interests for value creation. Through this executive compensation program, Greenfire has historically offered NEOs cash compensation in the form of base salary and discretionary bonuses. Greenfire’s NEOs have also historically participated in the Greenfire Equity Plan, pursuant to which they have been entitled to receive equity compensation in the form of Greenfire Performance Warrants upon the happening of certain pre-determined events. In addition to wages and incentive programs, NEOs also received health, dental and wellness benefits, which health, dental and wellness benefits are also provided to all employees of Greenfire.

 

Pursuant to the Amalgamation, the Greenfire Equity Plan was amended and restated by the Company Performance Warrant Plan. A portion of the Greenfire Performance Warrants outstanding prior to the Business Combination remained outstanding following Closing, and were converted into the Company Performance Warrants governed by the Company Performance Warrant Plan, which entitles the holders thereof to purchase Common Shares in lieu of Greenfire Common Shares. All the Company Performance Warrants were considered to be fully vested and exercisable following the Closing. No further Greenfire Performance Warrants will be granted pursuant to the Company Performance Warrant Plan.

 

 

In connection with the Business Combination, the Company adopted the Company Incentive Plan to facilitate the grant of the Company Awards to directors, employees (including executive officers) and consultants of the Company and certain of its affiliates and to enable the Company to obtain and retain the services of these individuals, which is essential to the Company’s long-term success.

 

Review and Governance

 

Historically, the Greenfire Board did not have a compensation committee or other committee responsible for establishing or making recommendations with respect to the compensation programs for the executive officers. The compensation of Greenfire’s CEO was set by the Greenfire Board and the compensation of Greenfire’s other NEOs was set by the CEO in consultation with the Greenfire Board.

 

Historical Elements of Executive Compensation

 

Historically, Greenfire strived to ensure that every employee understood how they contributed and impacted the results of the organization. Greenfire’s executive compensation framework included a combination of guaranteed and variable pay based on performance. There were three elements to executive officer total compensation with weighted emphasis on variable components of pay for performance and performance based equity compensation.

 

Greenfire’ compensation framework had three elements: (1) guaranteed pay, (2) incentive compensation, and (3) benefits and other compensation.

 

(1) Guaranteed Pay — Annual Base Salary

 

Base salary was the fixed component of total direct compensation for the NEOs, and is intended to attract and retain executives, providing a competitive amount of income certainty. These annual salaries were determined by analyzing similar sized oil and gas companies.

 

(2) Incentive Compensation — Annual Bonuses and Performance Based Equity Compensation

 

●

Short-Term Incentive — Annual Bonus

 

In consultation with Lane Caputo Compensation Inc. (“Lane Caputo”), in December 2023, the Company’s Board determined bonus target levels for the executive officers under a new short-term incentive program with the CEO eligible for a cash bonus of up to the full amount of his base salary, senior vice-presidents eligible for bonuses of up to two-thirds of their respective base salaries and vice-presidents eligible for bonuses of up to one-half of their respective base salaries. The actual amount of the bonuses up to the target level will be determined based on corporate and individual performance, with the amount of the bonuses for executive officers primarily based on corporate performance.

 

●

Long-Term Incentive — Equity based compensation — Company Incentive Plan

 

Executive officers historically participated in the Greenfire Equity Plan with all other employees. The purpose of the Greenfire Equity Plan was to provide an incentive to the directors, officers, employees, consultants and other personnel of Greenfire to achieve the longer-term objectives of Greenfire, to give suitable recognition to the ability and profession of such persons who contribute materially to the success of Greenfire, and to attract to and retain in the employ of Greenfire, persons of experience and ability, by providing them with the opportunity to acquire an increased proprietary interest in Greenfire. The Greenfire Performance Warrants contained both time vesting and performance vesting conditions in order to provide a retention incentive and an incentive for holders of the Greenfire Performance Warrants to work towards Greenfire achieving certain corporate performance targets.

 

(3) Benefits and Other Compensation

 

The Company provides executives with other compensation in the form of group health, dental and insurance benefits; sick leave (salary continuance) and long-term disability; business travel medical insurance; out of country medical insurance; parking benefits; health care spending account; employee assistance program and life Insurance. The Company offers these benefits consistent with local market practice. The Company also provides field based executives a camp and isolation allowance, travel allowances and compensation to reflect specialized technical designations.

 

 

Employment Agreements

 

Robert Logan, Employment Agreement

 

On January 28, 2021, Robert Logan entered into an executive employment agreement with GAC covering the terms and conditions of his employment as President and Chief Executive Officer. Pursuant to his employment agreement, if terminated without just cause, Mr. Logan would be entitled to severance payments including (i) six months of his salary plus one month of salary for each year of service to Greenfire, and (ii) a pro rata bonus for the severance period based on milestones achieved for the year of termination, as determined by the Greenfire Board. Such payments would be subject to Mr. Logan signing a release of any potential claims. Mr. Logan’s employment agreement contains customary confidentiality and proprietary information provisions, as well as employee and consultant non-solicitation covenants for one year post-termination.

 

David Phung, Employment Agreement

 

On January 28, 2021, David Phung entered into an executive employment agreement with GAC covering the terms and conditions of his employment as Chief Financial Officer. Pursuant to his employment agreement, if terminated without just cause, Mr. Phung would be entitled to severance payments including (i) six months of his salary plus one month of salary for each year of service to Greenfire, and (ii) a pro-rata bonus for the severance period based on milestones achieved for the year of termination, as determined by the Greenfire Board. Such payments would be subject to Mr. Phung signing a release of any potential claims. Mr. Phung’s employment agreement contains customary confidentiality and proprietary information provisions, as well as employee and consultant non-solicitation covenants for one year post-termination. Mr. Phung resigned as Chief Financial Officer, and Tony Kraljic was appointed as his successor, effective as of September 30, 2023.

 

Tony Kraljic, Employment Agreement

 

On September 30, 2023, Tony Kraljic entered into an executive employment agreement with Greenfire Resources Employment Corporation covering the terms and conditions of his employment as Chief Financial Officer. Pursuant to his employment agreement, if terminated without just cause, Mr. Kraljic would be entitled to severance payments including (i) six months of his salary plus one month of salary for each year of service to Greenfire, (ii) a pro rata bonus for the severance period based on milestones achieved for the year of termination, as determined by the Greenfire Board, and (iii) fifteen percent (15%) of the annual base salary as of the termination date to compensate for the loss of eligibility for benefits and perquisites of employment. Such payments would be subject to Mr. Kraljic signing a release of any potential claims. Mr. Kraljic’s employment agreement contains customary confidentiality and proprietary information provisions, as well as employee and consultant non-solicitation covenants for one year post-termination.

 

Albert Ma, Employment Agreement

 

Effective December 21, 2020, Albert Ma entered into an executive employment agreement with Greenfire Hangingstone Operating Corporation, which contract was assigned to Greenfire Resources Employment Corporation effective January 1, 2022, covering the terms and conditions of his employment as Vice President, Facilities and Engineering. Pursuant to his employment agreement, if terminated without just cause, Mr. Ma would be entitled to severance payments including four weeks of his salary, plus other entitlements as set out in the Employment Standards Code (Alberta) (the “Alberta Code”). Mr. Ma’s employment agreement contains customary confidentiality and proprietary information provisions.

 

Kevin Millar, Employment Agreement

 

Effective January 1, 2022, Kevin Millar entered into an executive employment agreement with Greenfire Resources Employment Corporation covering the terms and conditions of his employment as Senior Vice President, Operations. Pursuant to his employment agreement, if terminated without just cause, Mr. Millar would be entitled to severance payment in an amount equal to four weeks of the Average Wages (as defined in Mr. Millar’s employment agreement) as at the termination date for each full or partial year of employment. Such payment in excess of such minimum severance as set out in the Alberta Code would be subject to Mr. Millar signing a release of any potential claims. Mr. Millar’s employment agreement contains customary confidentiality and proprietary information provisions, as well as employee and consultant non-solicitation covenants for one year post-termination.

 

 

Darren Crawford, Employment Agreement

 

Effective January 1, 2022, Darren Crawford entered into an executive employment agreement with Greenfire Resources Employment Corporation covering the terms and conditions of his employment as Vice President, Operations & Projects. Pursuant to his employment agreement, if terminated without just cause, Mr. Crawford would be entitled to severance payment in an amount equal to four weeks of the Average Wages (as defined in Mr. Crawford’s employment agreement) as at the termination date for each full or partial year of employment between the Commencement Date (as defined in Mr. Crawford’s employment agreement) and the Termination Date. Such payment in excess of such minimum severance as set out in the Alberta Code would be subject to Mr. Crawford signing a release of any potential claims. Should Mr. Crawford fail to provide such release, Mr. Crawford shall only be entitled to severance as set out in the Alberta Code. Mr. Crawford’s employment agreement contains customary confidentiality and proprietary information provisions, as well as employee and consultant non-solicitation covenants for one year post-termination.

 

Compensation of the Company’s Directors — Year Ended December 31, 2023

 

The following table sets forth compensation paid to directors in respect of those positions for the fiscal year ended December 31, 2023.

 

Director		Annual compensation
Julian McIntyre		$	209,804.79
Venkat Siva		$	200,000.00
Jonathan Klesch		$	200,000.00
Matt Perkal(1)		$	56,027.40
W. Derek Aylesworth(1)		$	32,215.75
David Phung(2)(3)			–
Robert Logan(3)			–
Total		$	698,047.95

 

(1)

Messrs. Perkal and Aylesworth became directors of the Company upon the Closing of the Business Combination.

 

(2)

Mr. Phung served as a director of the Company prior to the Business Combination.

 

(3)

Please see disclosure under the heading “—Compensation of the Company’s Executive Officers — Year Ended December 31, 2023” for compensation paid to Messrs. Phung and Logan in their capacities as executive officers.

 

Equity Compensation

 

Pursuant to the Amalgamation, the Greenfire Equity Plan was amended and restated by the Company Performance Warrant Plan. A portion of the Greenfire Performance Warrants outstanding prior to the Business Combination remained outstanding following Closing and were converted into the Company Performance Warrants governed by the Company Performance Warrant Plan, which entitles the holders thereof to purchase the Common Shares in lieu of Greenfire Common Shares. All the Company Performance Warrants were considered to be fully vested and exercisable following the Closing. No further Company Performance Warrants will be granted pursuant to the Company Performance Warrant Plan.

 

In connection with the Business Combination, the Company adopted the Company Incentive Plan, to facilitate the grant of the Company Awards to directors, employees (including executive officers) and consultants of the Company and certain of its affiliates and to enable the Company to obtain and retain the services of these individuals, which is essential to the Company’s long-term success. The Company Incentive Plan is subject to applicable Laws and stock exchange rules.

 

 

DESCRIPTION OF THE COMPANY SECURITIES

 

This section of the prospectus includes a description of the material terms of the Company’s governing documents and applicable Canadian law. The following is intended as a summary only and does not constitute legal advice regarding those matters and should not be regarded as such. Unless stated otherwise, this description does not address any (proposed) provisions of Canadian law that have not become effective as per the date of this prospectus. The description is qualified in its entirety by reference to the complete text of the Company Articles and the Company Bylaws. We urge you to read the full text of the Company Articles and the Company Bylaws.

 

Authorized Share Capital

 

The authorized share capital of the Company consists of an unlimited number of the Common Shares and unlimited number of preferred shares (“The Company Preferred Shares”), issuable in series.

 

Share Terms

 

The Common Shares

 

Voting Rights

 

The holders of the Common Shares are entitled to receive notice of, to attend and to one vote per Common Share held at any meeting of shareholders of the Company, except meetings at which only holders of a different class or series of shares of the Company are entitled to vote.

 

Dividend Rights

 

Subject to the prior satisfaction of all preferential rights and privileges attached to any other class or series of shares of the Company ranking in priority to the Common Shares in respect of dividends, the holders of the Common Shares are entitled to receive dividends at such times and in such amounts as the Board may determine from time to time.

 

Liquidation

 

Subject to the prior satisfaction of all preferential rights and privileges attached to any other class or series of shares of the Company ranking in priority to the Common Shares in respect of return of capital on dissolution, upon the voluntary or involuntary liquidation, dissolution or winding-up of the Company or any other distribution of its assets among the shareholders of the Company for the purpose of winding up its affairs (such event, a “Distribution”), holders of the Common Shares shall be entitled to receive all declared but unpaid dividends thereon and thereafter to share rateably in such assets of the Company as are available with respect to such Distribution.

 

The Company Preferred Shares

 

Issuance in Series

 

The Board may: (a) at any time and from time to time issue Company Preferred Shares in one or more series, each series to consist of such number of shares as may, before the issuance thereof, be determined by the Board; and (b) from time to time fix, before issuance, the designation, rights, privileges, restrictions and conditions attaching to each series of the Company Preferred Shares including, without limiting the generality of the foregoing: the amount, if any, specified as being payable preferentially to such series on a Distribution; the extent, if any, of further participation on a Distribution; voting rights, if any; and dividend rights (including whether such dividends be preferential, or cumulative or non-cumulative), if any.

 

As of the date of this prospectus, no Company Preferred Shares are issued and outstanding.

 

Dividend Rights

 

The holders of each series of the Company Preferred Shares will be entitled, in priority to holders of the Common Shares and any other shares of the Company ranking junior to the Company Preferred Shares from time to time with respect to the payment of dividends, to be paid rateably with holders of each other series of the Company Preferred Shares, the amount of accumulated dividends, if any, specified as being payable preferentially to the holders of such series.

 

Liquidation

 

In the event of a Distribution, the holders of each series of the Company Preferred Shares will be entitled, in priority to holders of the Common Shares and any other shares of the Company ranking junior to the Company Preferred Shares from time to time with respect to payment on a Distribution, to be paid rateably with holders of each other series of the Company Preferred Shares the amount, if any, specified as being payable preferentially to the holders of such series on a Distribution.

 

 

Notices

 

The Company Bylaws provide that, if the Company is not a reporting issuer, a notice of the time and place of each meeting of shareholders of the Company will be sent not less than seven (7) days and not more than sixty (60) days before the meeting to each shareholder entitled to vote at the meeting. If the Company is a reporting issuer, the Company Bylaws require a notice of the time and place of each meeting of shareholders of the Company to be sent not less than twenty-one (21) days and not more than fifty (50) days before the meeting to each shareholder entitled to vote at the meeting. For the purposes of the ABCA, a “reporting issuer” means a corporation that is a reporting issuer as defined in the Securities Act (Alberta), or a corporation that is a reporting issuer or a substantially similar corporation under the laws of another jurisdiction in Canada.

 

For the purpose of determining shareholders of the Company entitled to receive notice of or to vote at a meeting of shareholders of the Company, the directors of the Company may fix in advance a date as the record date for such determination, but that record date will not precede by more than fifty (50) days or by less than twenty-one (21) days the date on which such meeting is to be held.

 

Amendment/Variation of Class Rights

 

Under the ABCA, certain fundamental changes, such as changes to a corporation’s articles, changes to authorized share capital, continuances out of province, certain amalgamations, sales, leases or other exchanges of all or substantially all of the property of a corporation (other than in the ordinary course of business of the corporation), certain liquidations, certain dissolutions, and certain arrangements are required to be approved by special resolution.

 

A special resolution under the ABCA is a resolution: (i) passed by a majority of not less than two-thirds of the votes cast by the shareholders who voted in respect of such resolution at a meeting duly called and held for that purpose; or (ii) signed by all shareholders entitled to vote on the resolution; provided that, pursuant to the ABCA, where a corporation is not a reporting issuer, a resolution (whether it is a special resolution or ordinary resolution) in writing signed by holders of at least two-thirds of the shares entitled to vote on that resolution is sufficient for such resolution to become effective.

 

In certain cases, an action that prejudices, adds restrictions to or interferes with rights or privileges attached to issued shares of a class or series of shares must be approved separately by the holders of the class or series of shares being affected by special resolution.

 

Company Directors — Appointment and Retirement

 

The Company Bylaws provide that, subject to the limitations and requirements provided in the Company Articles, the number of directors of the Company shall be determined from time to time by resolution of the shareholders of the Company or the Board. The Company Articles provide that the Company will have a board of directors consisting of a minimum of 1 director and a maximum of 13 directors. Pursuant to the ABCA, if the Company is a reporting issuer, the Board shall not have less than 3 directors.

 

Directors are generally elected by shareholders by ordinary resolution; however, the Company Articles also provide that the Board may, between annual general meetings of shareholders, appoint one or more additional directors to serve until the next annual general meeting, but the number of additional directors so appointed may not at any time exceed one-third of the number of directors who held office at the expiration of the previous annual general meeting.

 

The Company Bylaws provide that director nominees may be made at the discretion of the Board as well as by shareholders of the Company if made in accordance with the Advance Notice Provisions of the Company Bylaws. The Advance Notice Provisions in the Company Bylaws set forth the procedure requiring advance notice to the Company from a shareholder who intends to nominate a person for election as a director of the Company. Among other things, the Advance Notice Provisions provide for a deadline by which a shareholder must notify the Company of an intention to nominate directors prior to any meeting of shareholders at which directors are to be elected and specify the information that the nominating shareholder must include in such notice in order for the director nominees to be eligible for nomination and election at the meeting.

 

Company Directors — Voting

 

Questions arising at any meeting of the Board will be decided by a majority of votes. In the case of an equality of votes, the chair of the meeting will not have a second or casting vote. A resolution in writing signed by all the directors entitled to vote on that resolution at a meeting of directors or committee of directors is as valid as if it had been passed at a meeting of directors or committee of directors, as the case may be. A resolution in writing dealing with all matters required by the ABCA to be dealt with at a meeting of directors, and signed by all the directors entitled to vote at that meeting, satisfies all the requirements of the ABCA relating to meetings of directors.

 

 

Powers and Duties of Company Directors

 

Under the ABCA, the directors of the Company are charged with the management, or supervision of the management, of the business and affairs of the Company. In discharging their responsibilities and exercising their powers, the ABCA requires that the directors: (a) act honestly and in good faith with a view to the best interests of the corporation; and (b) exercise the care, diligence and skill that a reasonably prudent person would exercise in comparable circumstances. These duties are commonly referred to as the directors’ “fiduciary duties” of loyalty and care, respectively. Further, the directors’ responsibilities may not be delegated (or abdicated) to shareholders and include the obligation to consider the long-term best interests of the corporation and it may be appropriate for the directors to consider (and not unfairly disregard) a broad set of stakeholder interests including the interests of shareholders, employees, suppliers, creditors, consumers, government and the environment.

 

Directors’ and Officers’ Indemnity

 

Under subsection 124(1) of the ABCA, except in respect of an action by or on behalf of the Company to procure a judgment in the Company’s favor, the Company may indemnify a current or former director or officer or a person who acts or acted at the Company’s request as a director or officer of a body corporate of which the Company is or was a shareholder or creditor and the heirs and legal representatives of any such persons (collectively, “Indemnified Persons”) against all costs, charges and expenses, including an amount paid to settle an action or satisfy a judgment, reasonably incurred by any such Indemnified Person in respect of any civil, criminal or administrative, investigative or other actions or proceedings in which the Indemnified Person is involved by reason of being or having been director or officer of the Company, if (i) the Indemnified Person acted honestly and in good faith with a view to the best interests of the Company, and (ii) in the case of a criminal or administrative action or proceeding that is enforced by a monetary penalty, the Indemnified Person had reasonable grounds for believing that such Indemnified Person’s conduct was lawful (collectively, the “Discretionary Indemnification Conditions”).

 

Notwithstanding the foregoing, subsection 124(3) of the ABCA provides that an Indemnified Person is entitled to indemnity from the Company in respect of all costs, charges and expenses reasonably incurred by the Indemnified Person in connection with the defense of any civil, criminal, administrative, investigative or other action or proceeding in which the Indemnified Person is involved by reason of being or having been a director or officer of the Company, if the Indemnified Person (i) was not judged by a court or competent authority to have committed any fault or omitted to do anything that the person ought to have done, and (ii) fulfills the Discretionary Indemnification Conditions (collectively, the “Mandatory Indemnification Conditions”). Under subsection 124(3.1) of the ABCA, the Company may advance funds to an Indemnified Person in order to defray the costs, charges and expenses of such a proceeding; however, the Indemnified Person must repay the funds if the Indemnified Person does not fulfill the Mandatory Indemnification Conditions. The indemnification may be made in connection with a derivative action only with court approval and only if the Discretionary Indemnification Conditions are met.

 

Subject to the aforementioned prohibitions on indemnification, an Indemnified Person will be entitled to indemnity from the corporation in respect of all costs, charges and expenses reasonably incurred by such person in connection with the defense of any civil, criminal, administrative, investigative or other action or proceeding in which the Indemnified Person is involved by reason of being or having been a director or officer of the corporation or body corporate, if the person seeking indemnity: (i) was not judged by a court or competent authority to have committed any fault or omitted to do anything that the person ought to have done; and (ii) (a) the individual acted honestly and in good faith with a view to the best interests of the corporation; and (b) in the case of a criminal or administrative action or proceeding that is enforced by a monetary penalty, the individual had reasonable grounds for believing that the individual’s conduct was lawful.

 

As permitted by the ABCA, the Company’s Bylaws will require the Company to indemnify directors or officers of the Company, former directors or officers of the Company or other individuals who, at the Company’s request, act or acted as directors or officers or in a similar capacity of another entity of which the Company is or was a shareholder or creditor (and such individual’s respective heirs and personal representatives) to the extent permitted by the ABCA. Because the Company’s Bylaws will require that indemnification be subject to the ABCA, any indemnification that the Company provides is subject to the same restrictions set out in the ABCA which are summarized, in part, above.

 

The Company may also, pursuant to subsection 124(4) of the ABCA, purchase and maintain insurance, or pay or agree to pay a premium for insurance, for each person referred to in subsection 124(1) of the ABCA against any liability incurred by such person as a result of their holding office in the Company or a related body corporate.

 

Take Over Provisions

 

National Instrument 62-104 — Take Over Bids and Issuer Bids (“NI 62-104”) is applicable to the Company and provides that a takeover bid is triggered when a person makes an offer to acquire outstanding voting securities or equity securities of a class made to one or more persons, any of whom are in the local jurisdiction, where the securities subject to the offer to acquire, together with the offeror’s securities, constitute in the aggregate 20% or more of the outstanding securities of that class of securities at the date of the offer to acquire. When a takeover bid is triggered, an offeror must comply with certain requirements. These include making the offer of identical consideration to all holders of the class of security that is the subject of the bid, making a public announcement of the bid in a newspaper and sending out a bid circular to securityholders which explains the terms and conditions of the bid. Directors of an issuer whose securities are the subject of a takeover bid are required to evaluate the proposed bid and circulate a directors’ circular indicating whether they recommend to accept or reject the bid or state that they are unable to make, or are not making, a recommendation regarding the bid. Strict timelines must be adhered to. NI 62-104 also contains a number of exemptions to the takeover bid and issuer bid requirements.

 

 

Compulsory Acquisitions

 

Subsection 195(2) of the ABCA provides that, if within the time limited in a takeover bid for its acceptance or within 120 days after the date of a takeover bid, whichever period is shorter, the bid is accepted by the holders of not less than 90% of the shares of any class of shares of a corporation to which the takeover bid relates, other than shares of that class held at the date of the takeover bid by or on behalf of the offeror or an affiliate or associate of the offeror, the offeror is entitled, on the bid being so accepted and on complying with the ABCA, to acquire the shares of that class held by an offeree who does not accept the takeover bid.

 

Reporting Obligations under Canadian Securities Law

 

As of the date of this prospectus, the Company is not a reporting issuer in any Province of Canada. In the event that the Company does become a reporting issuer in a Province of Canada at any time in the future, by listing securities on a Canadian stock exchange, such as the Toronto Stock Exchange, or filing a final prospectus and receiving a receipt for such prospectus from the securities regulatory authority in any jurisdiction of Canada, the Company would become subject to continuous disclosure and other reporting obligations under applicable Canadian securities law. Among other things, these continuous disclosure obligations include the requirement for a reporting issuer to file annual and quarterly financial statements together with related management’s discussion and analysis, and prepare and file reports upon the occurrence of any “material change” (as defined under applicable Canadian securities law). In addition, a reporting issuer’s “reporting insiders” (as defined under applicable Canadian securities law) are required to file reports with respect to, among other things, their beneficial ownership of, or control or direction over, securities of the issuer and their interests in, and rights and obligations associated with, related financial instruments.

 

If the Company does not become a reporting issuer in a jurisdiction of Canada, any resale of any the Company Securities (including the Common Shares underlying the Company Warrants) by securityholders resident in any jurisdiction of Canada or otherwise subject to Canadian securities laws must be made in accordance with the prospectus requirements under applicable Canadian securities law or an applicable exemption in respect thereof.

 

Reporting Obligations under U.S. Securities Law

 

The Company is a “foreign private issuer” under the securities laws of the United States and the Listing Rules. Under the securities laws of the United States, “foreign private issuers” are subject to different disclosure requirements than U.S. registrants. The Company intends to take all actions necessary to maintain compliance as a foreign private issuer under the applicable corporate governance requirements of the Sarbanes-Oxley Act, the rules adopted by the SEC and the Listing Rules. Subject to certain exceptions, the Listing Rules permit a “foreign private issuer” to comply with its home country rules in lieu of the Listing Rules.

 

Additionally, because the Company qualifies as a “foreign private issuer” under the Exchange Act, it is exempt from certain provisions of the securities rules and regulations in the U.S. that are applicable to U.S. domestic issuers, including, among others: (i) the rules under the Exchange Act requiring the filing with the SEC of quarterly reports on Form 10-Q or current reports on Form 8-K; (ii) the sections of the Exchange Act regulating the solicitation of proxies, consents, or authorizations in respect of a security registered under the Exchange Act; (iii) the sections of the Exchange Act requiring insiders to file public reports of their share ownership and trading activities and liability for insiders who profit from trades made in a short period of time; and (iv) the selective disclosure rules by issuers of material non-public information under Regulation FD.

 

Listing of the Company Securities

 

The Common Shares have been listed for trading on the NYSE under the symbol “GFR” since September 21, 2023, and on the Toronto Stock Exchange (“TSX”) under the symbol “GFR” since February 8, 2024.

 

The Company Warrants are not, and are not expected to be, listed for trading on the NYSE or another national securities exchange.

 

Certain Insider Trading and Market Manipulation Laws

 

Canadian and U.S. law each contain rules intended to prevent insider trading and market manipulation. The following is a general description of those laws as such laws exist as of the date of this prospectus and should not be viewed as legal advice for specific circumstances.

 

The Company has adopted an insider trading policy that provides for, among other things, rules on transactions by members of the Company Board, the Company officers and the Company employees in respect of securities of the Company or financial instruments, the value of which is determined by the value of the Company securities.

 

 

United States

 

United States securities laws generally prohibit any person from trading in a security while in possession of material, non-public information or assisting someone who is engaged in doing the same. The insider trading laws cover not only those who trade based on material, non-public information, but also those who disclose material non-public information to others who might trade on the basis of that information (known as “tipping”). A “security” includes not just equity securities, but any security (e.g., derivatives). Thus, members of the Company Board, officers and other employees of the Company may not purchase or sell shares or other securities of the Company when he or she is in possession of material, non-public information about the Company (including the Company’s business, prospects or financial condition), nor may they tip any other person by disclosing material, non-public information about the Company.

 

Canada

 

Canadian securities laws prohibit any person or company in a special relationship with an issuer from purchasing or selling a security with the knowledge of a material fact or material change that has not been generally disclosed (known as “material, non-public information”). Further, Canadian securities laws also prohibit: (i) an issuer and any person or company in a special relationship with the issuer, other than when it is necessary in the course of business, from informing another person or company of a material fact or material change with respect to the issuer before the material fact or material change has been generally disclosed (known as “tipping”); and (ii) an issuer and any person or company in a special relationship with an issuer, with knowledge of a material fact or material change with respect to the issuer that has not been generally disclosed, from recommending or encouraging another person or company: (A) to purchase or sell a security of the issuer; or (B) to enter into a transaction involving a security the value of which is derived from or varies materially with the market price or value of a security of the issuer. A “security” includes not just equity securities, but any security (e.g., derivatives).

 

A person or company is in a special relationship with an issuer if: (a) the person or company is an insider, affiliate or associate of (i) the issuer, (ii) a person or company that is considering or evaluating whether to make a takeover bid, or a person or company that is proposing to make a takeover bid, for the securities of the issuer, or (iii) a person or company that is considering or evaluating whether, or a person or company that is proposing, (A) to become a party to a reorganization, amalgamation, merger or arrangement or a similar business combination with the issuer, or (B) to acquire a substantial portion of the property of the issuer; (b) the person or company has engaged, is engaging, is considering or evaluating whether to engage, or proposes to engage, in any business or professional activity with or on behalf of (i) the issuer, or (ii) a person or company described in clause (a)(ii) or (iii) above; (c) the person is a director, officer or employee of (i) the issuer, (ii) a subsidiary of the issuer, (iii) a person or company that controls the issuer, directly or indirectly, or (iv) a person or company described in clause (a)(ii) or (iii) or (b) above; (d) the person or company learned of material, non-public information about the issuer while the person or company was a person or company described in clause (a), (b) or (c) above; or (e) the person or company (i) learns of material, non-public information about the issuer from any other person or company described in this section, including a person or company described in this clause, and (ii) knows or ought reasonably to have known that the other person or company is a person or company in a special relationship with the issuer. Thus, directors, officers and employees of the Company may not purchase or sell the Common Shares or other securities of the Company when he or she is in possession of material, non-public information regarding the Company (including the Company’s business, prospects or financial condition), nor may they inform (or “tip”) anyone else of such material, non-public information regarding the Company.

 

Restrictions on Trading pursuant to Rule 144

 

Common Shares received in the Business Combination by persons who become affiliates of the Company for purposes of Rule 144 under the Securities Act may be resold by them only in transactions permitted by Rule 144, pursuant to an effective registration under the Securities Act, or as otherwise permitted under the Securities Act. Persons who may be deemed affiliates of the Company generally include individuals or entities that control, are controlled by or are under common control with, the Company and may include the directors and executive officers of the Company as well as its principal shareholders.

 

Restrictions on Trading pursuant to Canadian Securities Laws

 

If the Company does not become a reporting issuer in a jurisdiction of Canada, any resale of any the Company Securities (including the Common Shares underlying the Company Warrants) by securityholders resident in any jurisdiction of Canada or otherwise subject to Canadian securities laws must be made in accordance with the prospectus requirements under applicable Canadian securities law or an applicable exemption in respect thereof.

 

 

Registration Rights

 

Pursuant to the Investor Rights Agreement, among other matters provided for therein, the Company agreed to file, within 30 calendar days after Closing of the Business Combination, a Resale Registration Statement with the SEC (at the Company’s sole cost and expense) and to use its commercially reasonable efforts to cause the Resale Registration Statement to become effective by the SEC as soon as reasonably practicable after the initial filing thereof. The Resale Registration Statement was declared effective by the SEC on February 6, 2024. Among other things, in certain circumstances, the holders of “Registrable Securities” (as defined in the Investor Rights Agreement) can demand the Company’s assistance with underwritten offerings and block trades. The holders will also be entitled to customary piggyback registration rights. 

 

Company Warrants

 

Each of the Company Warrants is subject to substantially the same terms and conditions (including exercisability terms) as were applicable to the MBSC Private Placement Warrants prior to the Business Combination, except to the extent such terms or conditions were rendered inoperative by the Business Combination. Accordingly, (A) each Company Warrant is exercisable solely for one Common Share; (B) the per share exercise price for the Common Shares issuable upon exercise of the Company Warrants is $11.50, subject to adjustment, on the terms and conditions set forth in the Warrant Agreements; and (C) each Company Warrant shall expire five years after the date of the Closing of the Business Combination.

 

The Company has not, and does not intend to, list the Company Warrants on the NYSE or another securities exchange.

 

Company Incentive Plan

 

The Company adopted the Company Incentive Plan which is designed to provide flexibility to the Company to grant equity-based incentive awards in the form of the Company Options, the Company Share Units and the Company DSUs under a single, streamlined plan. The Company Board expects to grant the Company Awards pursuant to the Company Incentive Plan to align the interests of the recipients thereof with the Company. The Company Incentive Plan is subject to applicable Laws and stock exchange rules.

 

Transfer Agent and Warrant Agent

 

The transfer agent for the Common Shares in the United States is Computershare Trust Company of Canada. Each person investing in the Common Shares to be held through Computershare must rely on the procedures thereof and on institutions that have accounts therewith to exercise any rights of a shareholder of the Company.

 

For as long as any the Common Shares are listed on the NYSE or on any other stock exchange operating in the United States, the laws of the State of New York will apply to the property law aspects of the Common Shares reflected in the register administered by the Company’s transfer agent.

 

The warrant agent for the Company Warrants is Computershare Trust Company, N.A.

 

 

BENEFICIAL OWNERSHIP OF THE COMPANY SECURITIES

 

The following table sets forth information regarding the beneficial ownership of the Common Shares as of the date hereof by:

 

●

each person who is, or is expected to be, the beneficial owner of more than 5% of outstanding the Common Shares;

 

●

each of the Company’s named executive officers and directors; and

 

●

all officers and directors of the Company, as a group.

 

Beneficial ownership is determined according to the rules of the SEC, which generally provide that a person has beneficial ownership of a security if he, she or it possesses sole or shared voting or investment power over that security. A person is also deemed to be a beneficial owner of securities that person has a right to acquire within 60 days including, without limitation, through the exercise of any option, warrant or other right or the conversion of any other security. Such securities, however, are deemed to be outstanding only for the purpose of computing the percentage beneficial ownership of that person but are not deemed to be outstanding for the purpose of computing the percentage beneficial ownership of any other person.

 

The beneficial ownership of the Company is based on 69,074,130 Common Shares issued and outstanding as of April 29, 2024.

 

Unless otherwise indicated, we believe that all persons named in the table below have sole voting and investment power with respect to all Common Shares beneficially owned by them.

 

Unless otherwise indicated, the address of each Company director and executive officer is c/o Greenfire Resources Ltd., 1900-205 5^th Avenue SW Calgary, Alberta T2P 2V7.

 

Name and Address of Beneficial Owners		Number of New Greenfire Common Shares				%  of total New Greenfire Common Shares
Five Percent Holders
M3-Brigade Sponsor III LP(1)			3,850,000				8.9	%(2)
Brigade Capital Management, LP(3)			5,866,647				8.8	%(4)
Modro Holdings LLC(5)			4,692,909				7.3	%(6)
Sona Asset Management (US) LLC(7)			4,966,102				7.2	%
Directors and Executive Officers of The Company
Robert Logan			3,467,943				7.4	%(8)
Tony Kraljic			—				—
Albert Ma			366,528					*
Kevin Millar			272,000					*
Jonathan Klesch(9)			757,809				1.7	%(10)
Julian McIntyre(11)			19,871,539				30.4	%(12)
Venkat Siva(13)			6,599,406				10.2	%(14)
Matthew Perkal(15)			—				—
William Derek Aylesworth			—				—
Crystal Park			110,095					*
All Directors and Executive Officers of the Company as a group (10 Individuals)			36,052,133				48.8	%

 

*

Less than 1%.

 

(1)

The business address is 1700 Broadway, 19th Floor, New York, NY 10019. M3-Brigade Sponsor III LP (MBSC Sponsor) is the record holder of the shares reported herein. The general partner of M3-Brigade Sponsor III LP is M3-Brigade Acquisition Partners III Corp. Mohsin Y. Meghji is the sole director of M3-Brigade Acquisition Partners III Corp. Mr. Meghji may be deemed to have beneficial ownership of the common stock held directly by M3-Brigade Sponsor III LP. The terms of a consulting agreement between the Company and the MBSC Sponsor are described herein under the heading “Certain Relationships and Related Transactions – Transactions Related to the Business Combination or MBSC Sponsor – MBSC Sponsor Consulting Agreement”.

 

(2)

Includes the Common Shares issuable upon exercise of 2,526,667 Company Warrants.

 

 

(3)

Brigade Capital Management, LP, a Delaware limited partnership (“Brigade CM”), Brigade Capital Management LLC, a Delaware limited liability company (“Brigade GP”) and Donald E. Morgan, III (collectively, the “Brigade Parties”) have shared voting and dispositive power with respect to 6,060,647 Common Shares (including 194,000 Common Shares issuable upon exercise of Company Warrants) which are held directly by private investment funds and accounts managed by Brigade CM. Brigade GP is the general partner of Brigade CM. Mr. Morgan is the managing member of Brigade GP. The business address of the Brigade Parties is 399 Park Avenue, 16th Floor, New York, NY 10022.

 

(4)

Includes the Common Shares issuable upon exercise of 194,000 Company Warrants.

 

(5)

The business address is 2283 San Ysidro Dr., Beverly Hills, CA 90210.

 

(6)

Includes the Common Shares issuable upon exchange of 372,000 Company Warrants.

 

(7)

As reported in a statement on Schedule 13G filed with the SEC on April 4, 2024: Sona Asset Management (US) LLC, a Delaware limited liability company (“Sona AM (US)”), which, together with Sona AM (UK)(as defined below) serves as an investment manager to certain funds, including with respect to the Common Shares held by those funds. Sona Asset Management (UK) LLP, a limited liability partnership formed under the laws of England and Wales (“Sona AM (UK)”) and, together with Sona AM (US), collectively, the “Sona Asset Managers”), which, together with Sona AM (US), serves as an investment manager to certain funds, including with respect to the Common Shares held by those funds. Sona Asset Management Limited, a private limited company incorporated under the laws of England and Wales (“SAML”), is the principal owner of each of the Sona Asset Managers. Sona Asset Management Cayman Limited, an exempted company incorporated in the Cayman Islands (“SAMCL” and, together with SAML, the “Sona Intermediate Companies”), is the principal owner of SAML. John Aylward is ultimately in control of the investment and voting decisions of the Sona Asset Managers and is the principal owner of SAMCL. The Sona Asset Managers are deemed to be the beneficial owners of the 4,966,102 Common Shares held by the investment funds due to their control over the voting and dispositive decisions of the funds.  The Sona Intermediate Companies are deemed to be the beneficial owners of the 4,966,102 Common Shares due to each of their direct or indirect ownership of the Sona Asset Managers.  Mr. Aylward is deemed to be the beneficial owner of the 4,966,102 Common Shares due to his control over the Sona Asset Managers and his direct or indirect ownership and control of the Sona Intermediate Companies. The address of the principal business office of Sona AM (US) is 800 3rd Avenue, Suite 1702, New York, NY 10022.  The address of the principal business office of Sona AM (UK), SAML and Mr. Aylward is Second Floor 19-21 St. James’s Street, London, United Kingdom SW1A 1ES.  The address of the principal business office of SAMCL is c/o Maples Corporate Services Limited, PO Box 309, Ugland House, Grand Cayman KY1-1104, Cayman Islands.

 

(8)

Includes the Common Shares issuable upon exchange of (i) 375,000 Company Warrants and (ii) 1,397,796 Company Performance Warrants.

 

(9)

Owned through Spicelo Limited, a company formed under the laws of Cyprus.

 

(10)

Includes the Common Shares issuable upon exchange of 435,938 Company Warrants.

 

(11)

Owned through Allard Services Limited, a company formed under the laws of the Isle of Man.

 

(12)

Includes the Common Shares issuable upon exchange of 1,575,187 Company Warrants.

 

(13)

Owned through Annapurna Limited, a company formed under the laws of the Isle of Man.

 

(14)

Includes the Common Shares issuable upon exchange of 523,125 Company Warrants.

 

(15)

Does not include any shares owned by this individual as a result of his membership interest in M3-Brigade Sponsor III LP.

 

 

COMMON SHARES ELIGIBLE FOR FUTURE SALE

 

The Company has an unlimited number of Common Shares authorized for issuance and 69,074,130 Common Shares issued and outstanding as of April 29, 2024. All of the Common Shares the Company issued in connection with the Business Combination are freely transferable in the United States by persons other than by the Company’s “affiliates” without restriction or further registration under the Securities Act, except 4,177,091 Common Shares issued to the PIPE Investors in a private placement. The registration statement of which this prospectus forms a part registers the resale of the Common Shares issued to the PIPE Investors such that, such shares will be freely transferable under the Securities Act for so long as the registration statement of which this prospectus forms a part is available for use. Sales of substantial amounts of Common Shares in the public market could adversely affect prevailing market prices of Common Shares.

 

Registration Rights

 

Investor Rights Agreement

 

Concurrently with the Closing, the Company entered into the Investor Rights Agreement with MBSC Sponsor and certain other holders named therein, pursuant to which the Company agreed that, within 30 calendar days following the Closing Date, the Company would file with the SEC (at the Company’s sole cost and expense) the registration statement of which this prospectus forms a part (the “Resale Registration Statement”), and the Company would use its commercially reasonable efforts to cause the Resale Registration Statement to be declared effective by the SEC as soon as reasonably practicable after the initial filing thereof. The Resale Registration Statement was declared effective by the SEC on February 6, 2024. Among other things, in certain circumstances, the holders of “Registrable Securities” (as defined in the Investor Rights Agreement) can demand the Company’s assistance with underwritten offerings and block trades. The holders will also be entitled to customary piggyback registration rights.

 

Lock-Up Agreement

 

As of the Closing Date, the MBSC Sponsor, and certain former Greenfire Shareholders were bound by a Lock-Up Agreement pursuant to which, among other things, each of the MBSC Sponsor and the former Greenfire Shareholders party thereto agreed, subject to certain customary exceptions, not to (i) sell or assign, offer to sell, contract or agree to sell, hypothecate, pledge, grant any option to purchase or otherwise dispose of or agree to dispose of, directly or indirectly, or establish or increase a put equivalent position or liquidation with respect to or decrease a call equivalent position within the meaning of Section 16 of the Exchange Act, and the rules and regulations of the SEC promulgated thereunder with respect to, any equity securities of the Company, (ii) enter into any swap or other arrangement that transfers to another, in whole or in part, any of the economic consequences of ownership of any equity securities of the Company, whether any such transaction is to be settled by delivery of such securities, in cash or otherwise or (iii) make any public announcement of any intention to effect any transaction specified in clause (i) or (ii) until the earliest of (a) the date that is 180 days after the Closing Date, (b) the date that the last reported closing price of a Common Share equals or exceeds $12.00 per share (as adjusted for share splits, share dividends, reorganizations, recapitalizations and the like) for any 20 trading days within any 30-day trading period commencing at least 75 days after the Closing Date, and (c) the date on which the Company completes a liquidation, merger, amalgamation, arrangement, share exchange, reorganization or other similar transaction that results in all the Company Shareholders having the right to exchange their shares of capital stock for cash, securities or other property. The restrictions in the Lock-Up Agreement expired on March 18, 2024.

 

Rule 144

 

Pursuant to Rule 144 under the Securities Act (“Rule 144”), commencing September 27, 2024, the date that is one year following the date on which the Company filed the information required by Form 20-F as contemplated by Rule 144, a person who has beneficially owned restricted Common Shares for at least six months would, subject to the restrictions noted in the section below, be entitled to sell their securities provided that (i) such person is not deemed to have been an affiliate of the Company at the time of, or at any time during the three months preceding, a sale and (ii) the Company has been subject to the Exchange Act periodic reporting requirements for at least three months before the sale and has filed all required reports under Section 13 or 15(d) of the Exchange Act during the twelve months (or such shorter period as the Company was required to file reports) preceding the sale.

 

Persons who have beneficially owned restricted Common Shares for at least six months but who are affiliates of the Company at the time of, or at any time during the three months preceding, a sale, would be subject to additional restrictions, by which such person would be entitled to sell within any three-month period only a number of securities that does not exceed the greater of:

 

●

1% of the total number of Common Shares then outstanding; or

 

●

the average weekly reported trading volume of the Common Shares during the four calendar weeks preceding the filing of a notice on Form 144 with respect to the sale.

 

Sales by affiliates of the Company under Rule 144 are also limited by manner of sale provisions and notice requirements and to the availability of current public information about the Company.

 

Canadian Securities Laws

 

Since February 8, 2024, the Common Shares have been listed on the TSX under the symbol “GFR”.

 

 

SELLING SECURITYHOLDERS

 

The Selling Securityholders may offer and sell, from time to time, any or all of the Common Shares or Company Warrants being offered for resale by this prospectus. In addition, this prospectus relates to the offer and sale of up to 5,625,456 Common Shares issuable upon exercise of the Company Warrants.

 

The term “Selling Securityholders” includes the securityholders listed in the table below and their permitted transferees.

 

Given the relatively lower purchase prices that certain Selling Securityholders paid to acquire Common Shares, these Selling Securityholders, in some instances, would earn a positive rate of return on their investment, which may be a significant positive rate of return, depending on the market price of the Common Shares at the time that such Selling Securityholders choose to sell their Common Shares, at prices where other of our securityholders may not experience a positive rate of return if they were to sell at the same prices. For example, as of the date of this prospectus, (a) the Greenfire Holders hold, in the aggregate, 32,577,645 Common Shares and 3,098,789 Company Warrants, which were acquired by those Selling Securityholders pursuant to the Business Combination in exchange for securities of Greenfire that had been issued to employees, investors and others through private placements, equity award grants and other sales for little or no cash consideration, and (b) MBSC Sponsor and certain other Selling Securityholders hold 4,250,000 Common Shares that they acquired pursuant to the Business Combination in exchange for MBSC Class B Common Shares originally issued in a private placement for a purchase price of approximately $0.0033 per share. For example, (a) the MBSC Sponsor received its 3,850,000 Common Shares in exchange for MBSC Class B Common Shares, which were originally purchased for a purchase price equivalent to approximately $0.0033 per share and (b) the Greenfire Holders received their Common Shares in exchange for securities of Greenfire for little or no cash. The last reported sales prices of the Common Shares on the NYSE and TSX on May 8, 2024 was $5.87 and CAD$7.97, respectively. The Company Warrants are not listed for trading on the NYSE or another national exchange. Even though the trading price of the Common Shares is currently significantly below the last reported sales price on the NYSE of $9.37 on the Closing Date of the Business Combination, all of such Selling Securityholders may have an incentive to sell their Common Shares because they acquired them in exchange for securities acquired for prices lower, and in some cases significantly lower, than the current trading price of the Common Shares and may profit, in some cases significantly so, even under circumstances in which our public shareholders would experience losses in connection with their investment. Based on the current trading price of the Common Shares, MBSC Sponsor and the Greenfire Holders could earn up to approximately $5.9597 and $5.96, respectively, in potential profit per share if they were to sell those Common Shares at the current trading price. Certain Greenfire Holders also hold, in the aggregate, 1,684,307 Company Performance Warrants, with exercise prices that range from CAD$2.14 to CAD$2.84 (US$1.56 to US$2.07, using an exchange rate of 1.00 USD to 1.37 CAD as of May 8, 2024) and could earn up to approximately US$4.40 in profit per share if they were to sell the Common Shares issuable upon exercise of those Company Performance Warrants at the current trading price. The PIPE Investors purchased their Common Shares at US$10.10 per share and would not earn a profit if they were to sell those shares at the current trading price. Investors who purchase the Common Shares on the NYSE following the Business Combination are unlikely to experience a similar rate of return on the Common Shares they purchase due to differences in the purchase prices originally paid by the Selling Securityholders and the current trading price that new investors would pay. In addition, sales by the Selling Securityholders may cause the trading prices of our securities to experience a decline. As a result, the Selling Securityholders may effect sales of Common Shares at prices significantly below the current market price, which could cause market prices to decline further. While certain Selling Securityholders may experience a positive rate of return based on the current trading price of our Common Shares, other Selling Securityholders may not. For example, the PIPE Investors acquired their Common Shares at a purchase price of $10.10 per Common Share, or approximately $4.23 greater than the closing price of the Common Shares on the NYSE on May 8, 2024.

 

The table below provides, as of April 29, 2024, information regarding the beneficial ownership of the Common Shares and Company Warrants of each Selling Securityholder, the number of Common Shares and number of Company Warrants that may be sold by each Selling Securityholder under this prospectus and that each Selling Securityholder will beneficially own after this offering. We have based percentage ownership on 69,074,130 Common Shares outstanding as of April 29, 2024. In computing the number of Common Shares beneficially owned by a person and the percentage ownership of such person, the Company deemed to be outstanding all Common Shares subject to Company Warrants and Company Performance Warrants, as those warrants are currently exercisable. The Company did not deem such shares outstanding, however, for the purpose of computing the percentage ownership of any other person.

 

Because each Selling Securityholder may dispose of all, none or some portion of their securities, no estimate can be given as to the number of securities that will be beneficially owned by a Selling Securityholder upon termination of this offering. For purposes of the table below, however, we have assumed that after termination of this offering none of the securities covered by this prospectus will be beneficially owned by the Selling Securityholder and further assumed that the Selling Securityholders will not acquire beneficial ownership of any additional securities during the offering. In addition, the Selling Securityholders may have sold, transferred or otherwise disposed of, or may sell, transfer or otherwise dispose of, at any time and from time to time, our securities in transactions exempt from the registration requirements of the Securities Act after the date on which the information in the table is presented.

 

 

		Securities beneficially owned prior to this offering												Securities to be sold in this offering								Securities beneficially owned after this offering
Name of Selling Securityholder		Common Shares(1)				%				Company Warrants				Common Shares(1)				Company Warrants				Common Shares(1)				%				Company Warrants
M3-Brigade Sponsor III LP(2)			6,376,667				8.9	%			2,526,667				6,376,667				2,526,667				–				–				–
Julian McIntyre(3)(4)			21,446,726				30.4	%			1,575,187				21,446,726				1,575,187				–				–				–
Venkat Siva(3)(5)			7,122,531				10.2	%			523,125				7,122,531				523,125				–				–				–
Jonathan Klesch(3)(6)			757,809				8.6	%			435,938				757,809				435,938				–				–				–
Robert Logan(3)(7)			4,995,065				7.2	%			264,199				3,597,258				375,000				1,397,796	(7)			2.0	%(7)			–
David Phung(3)(8)			1,509,026				2.2	%			89,790				1,222,515				112,501				286,511	(8)			*				–
Crystal Park(3)(9)			151,448				*				109,995				110,095				3,037				38,316	(9)			*
Albert Ma(3)(10)			478,509				*				366,428				366,528				8,225				103,756	(10)			*
Kevin Millar(3)(11)			359,933				*				271,900				272,000				6,458				81,475	(11)			*
Brigade Capital Management, LP(12)			6,060,647				8.8	%			194,000				2,088,548				–				3,972,099	(13)			5.8	%(13)			194,000
Trafigura Canada Limited(14)			2,680,060				3.9	%			–				1,670,833				–				1,009,227				1.5	%			–
Luxor Gibraltar, LP – Series I(15)			–				*				3,704				–				–				–				*				3,704
Luxor Capital Partners Offshore Master Fund, LP(15)			–				*				74,480				–				–				–				*				74,480
Luxor Capital Partners, LP(15)			–				*				112,816				–				–				–				*				112,816
Thebes Offshore Master Fund, LP(15)			1,788,126				2.2	%			111,000				122,823				–				1,665,303				2.4	%			111,000
HT Investments, LLC(16)			400,000				*				–				400,000				–				–				–				–

 

*

Less than 1.0%.

 

(1)

The number of Common Shares listed for each Selling Securityholder assumes the exercise of all of the Company Warrants beneficially owned by such Selling Securityholder.

 

(2)

The business address is 1700 Broadway, 19th Floor, New York, NY 10019.

 

(3)

The business address is Greenfire Resources Ltd., 1900 – 205 5th Avenue SW, Calgary, AB T2P 2V7.

 

(4)

Owned through Allard Services Limited, a company formed under the laws of the Isle of Man.

 

(5)

Owned through Annapurna Limited, a company formed under the laws of the Isle of Man.

 

(6)

Owned through Spicelo Limited, a company formed under the laws of Cyprus.

 

(7)

Includes Common Shares issuable upon exchange of 1,397,796 Company Performance Warrants and assumes those Common Shares will not be sold by the Selling Securityholder.

 

(8)

Includes Common Shares issuable upon exchange of 286,511 Company Performance Warrants and assumes those Common Shares will not be sold by the Selling Shareholder.

 

 

(9)	Includes Common Shares issuable upon exchange of 38,316 Company Performance Warrants and assumes those Common Shares will not be sold by the Selling Shareholder.
(10)	Includes Common Shares issuable upon exchange of 103,756 Company Performance Warrants and assumes those Common Shares will not be sold by the Selling Shareholder.
(11)	Includes Common Shares issuable upon exchange of 38,316 Company Performance Warrants and assumes those Common Shares will not be sold by the Selling Shareholder.
(12)	Brigade Capital Management, LP, a Delaware limited partnership (“Brigade CM”), Brigade Capital Management LLC, a Delaware limited liability company (“Brigade GP”) and Donald E. Morgan, III (collectively, the “Brigade Parties”) have shared voting and dispositive power with respect to 5,866,647 Common Shares (including 194,000 Common Shares issuable upon exercise of Company Warrants) which are held directly by private investment funds and accounts managed by Brigade CM. Brigade GP is the general partner of Brigade CM. Mr. Morgan is the managing member of Brigade GP. The business address of the Brigade Parties is 399 Park Avenue, 16th Floor, New York, NY 10022.
(13)	Includes Common Shares issuable upon exchange of 194,000 Company Warrants and assumes those Common Shares will not be sold by the Selling Shareholder.
(14)	The business address is K1700 400 3rd Avenue, SW, Calgary, Alberta T29 4H2, Canada. The holder and its affiliates have provided financing to predecessors to the Company, are the sole third-party petroleum marketer to the Company and source diluent for the Company’s operations.  The Petroleum Marketer was also a lender under a letter of credit facility with the Company that was terminated in November 2023. For a description of those relationships, see the discussion of relationships with the Petroleum Marketer under the headings “Business — Material Contracts, Liabilities and Indebtedness — Marketing Agreements.” “Business—Our History—Acquisition of the Demo Asset” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity”.
(15)	LCG Holdings, LLC (“LCG Holdings”), Luxor Capital Group, LP (“Luxor Capital Group”), Luxor Management, LLC (“Luxor Management”) and Christian Leone may be deemed to beneficially own the Common Shares and Company Warrants owned by Luxor Capital Partners, LP, Luxor Capital Partners Offshore Master Fund, LP, Thebes Offshore Master Fund, LP and Luxor Gibraltar, LP – Series I (collectively, the “Luxor Selling Securityholders”). LCG Holdings is the general partner of the Luxor Selling Securityholders. Luxor Capital Group is the investment manager of the Luxor Selling Securityholders. Luxor Management is the general partner of Luxor Capital Group. Mr. Leone is the managing member of Luxor Management. The principal business address of each of the Onshore Fund, the Gibraltar Fund, Luxor Capital Group, Luxor Management, LCG Holdings and Mr. Leone is 7 Times Square, 43rd Floor, New York, New York 10036. The principal business address of each of the Offshore Master Fund and the Thebes Master Fund is c/o Maples Corporate Services Limited, P.O. Box 309, Ugland House, Grand Cayman, KY1-1104, Cayman Islands. The business address is 7 Times Square, 43rd Floor, New York, New York 10036.
(16)	HT Investments, LLC is a Delaware limited liability company managed by Fortinbras Enterprises LP, a Delaware limited partnership (“Fortinbras Enterprises”). Fortinbras Enterprises Holdings LLC, a Delaware limited liability company (“Fortinbras HoldCo”) serves as the general partner of Fortinbras Enterprises. Benjamin E. Black is the sole member of Fortinbras HoldCo and as such may be deemed to have voting and dispositive control with respect to 400,000 Common Shares. The business address of HT Investments, LLC is 445 Park Avenue, Suite 1401, New York, NY 10022.

 

 

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

 

Greenfire Relationships and Related Party Transactions

 

For each of the fiscal years ended December 31, 2021, and December 31, 2022, Greenfire paid CAD$ 85,733 and CAD$276,063, respectively, in directors fees to each of Messrs. McIntyre, Siva, and Klesch.

 

Transactions Related to the Business Combination or MBSC Sponsor

 

Founder Shares

 

On April 12, 2021, the MBSC Sponsor purchased an aggregate of 11,500,000 MBSC Class B Common Shares for the aggregate purchase price of $25,000. On September 7, 2021, MBSC effected a reverse stock split of 0.625 of a share of MBSC Class B Common Shares for each outstanding MBSC Class B Common Share, resulting in the MBSC Sponsor holding 7,187,500 MBSC Founder Shares. On October 21, 2021, MBSC effected a stock dividend of .044 of an MBSC Class B Common Share for each outstanding MBSC Class B Common Share, resulting in MBSC Initial Stockholders holding an aggregate of 7,503,750 MBSC Founder Shares. On October 25, 2021, the MBSC Sponsor forfeited at no cost 3,750 shares of MBSC Class B Common Shares in connection with the determination by the underwriters of the MBSC IPO not to exercise in full the over-allotment option granted to them, resulting in MBSC Initial Stockholders holding 7,500,000 MBSC Founder Shares.

 

Pursuant to the MBSC Articles in effect prior to the Business Combination, the MBSC Sponsor was not entitled to redemption rights with respect to any MBSC Founder Shares held by it in connection with the consummation of the Business Combination.

 

Private Placement Warrants

 

On October 26, 2021, MBSC consummated the MBSC IPO of 30,000,000 MBSC Units, generating gross proceeds of $300,000,000. Each MBSC Unit consisted of one MBSC Class A Common Share and one-third of one MBSC Public Warrant. Each MBSC Public Warrant entitled the holder thereof to purchase one MBSC Class A Common Share at a price of $11.50 per share, subject to certain adjustments.

 

Concurrently with the completion of the MBSC IPO, the MBSC Sponsor and Cantor purchased an aggregate of 5,786,667 and 1,740,000 MBSC Private Placement Warrants at a price of $1.50 per warrant, respectively, or $11,290,000.50 in the aggregate.

 

Related Party Loans and Advances

 

On April 12, 2021, the MBSC Sponsor agreed to loan MBSC up to $250,000 to cover expenses related to the MBSC IPO pursuant to a promissory note. The promissory note provided that any loans thereunder would be non-interest bearing, unsecured and due on the earlier of December 31, 2021 or the closing of the MBSC IPO. No amounts were borrowed by MBSC under the promissory note.

 

An affiliate of the MBSC Sponsor advanced $192,374 to MBSC prior to the MBSC IPO to pay certain of the costs incurred by MBSC in connection with the MBSC IPO. Such advances were repaid by MBSC out of funds held outside the Trust Account.

 

Sponsor Support Agreement

 

In connection with the Business Combination Agreement, MBSC entered into the Sponsor Support Agreement with the MBSC Sponsor, the Company and Greenfire, pursuant to which, among other things, the MBSC Sponsor agreed to (i) waive the anti-dilution rights set forth in the MBSC Articles with respect to the MBSC Class A Common Shares held by it, (ii) vote all MBSC Founder Shares held by it and any MBSC Common Shares acquired thereafter in favor of the proposal to adopt and approve the Business Combination and the Transactions, (iii) not redeem any MBSC Founder Shares held by it or MBSC Common Shares acquired thereafter in connection with the MBSC Stockholders’ Meeting, and (iv) not transfer the MBSC Founder Shares or MBSC Private Placement Warrants held by it prior to the Closing. The MBSC Sponsor did not receive any separate consideration in exchange for its agreement to waive these redemption rights. In addition, the MBSC Sponsor agreed to certain vesting and forfeiture conditions immediately prior to the Merger with respect to the MBSC Founder Shares and MBSC Private Placement Warrants held by it.

 

MBSC Sponsor Consulting Agreement

 

In April 2024, the Company entered into a consulting agreement with MBSC Sponsor (the “MBSC Sponsor Consulting Agreement”) for the provision of consulting services to the Company relating to, among other things, the Company’s transition to being a public company, maximizing the value of the Company, and educating the market about the Company and its value. Matthew Perkal, a member of the Company Board who was nominated to the Company Board by MBSC Sponsor pursuant to its rights under the Investor Rights Agreement, is Head of SPACs and Special Situations at Brigade Capital Management, LP, an affiliate of MBSC Sponsor and, prior to the Business Combination, served as MBSC’s Chief Executive Officer. The term of the consulting agreement continues until the earlier of April 2029 and the date MBSC Sponsor no longer holds any “Registrable Securities” in the Company (as defined in the Investor Rights Agreement). As compensation for the consulting services, the Company has agreed to issue 500,000 Common Shares to MBSC Sponsor subject to the approval of the TSX. The terms of the MBSC Sponsor Consulting Agreement were reviewed and approved by the disinterested directors of the Company Board. The fair market value of the shares to be issued to MBSC Sponsor was CAD$4.36 million, based on a five-day weighted average price immediately preceding the date of the MBSC Sponsor Consulting Agreement.

 

 

MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS

 

The following is a discussion of the material U.S. federal income tax considerations for U.S. Holders (as defined below) with respect to the ownership and disposition of the Company’s Securities. This discussion applies only to the Company’s Securities that are held as “capital assets” within the meaning of Section 1221 of the Code for U.S. federal income tax purposes (generally, property held for investment). This discussion is based on the provisions of the Code, U.S. Treasury regulations (“Treasury Regulations”), administrative rulings, and judicial decisions, all as in effect on the date hereof, and all of which are subject to change and differing interpretations, possibly with retroactive effect. Any such change or differing interpretation could significantly alter the tax considerations described herein. The Company has not sought, nor does it intend to seek, any rulings from the IRS with respect to the statements made and the positions or conclusions described in this summary. Such statements, positions and conclusions are not free from doubt, and there can be no assurance that your tax advisor, the IRS, or a court will agree with such statements, positions, and conclusions.

 

The following discussion does not purport to be a complete analysis of all potential tax considerations relevant to the ownership or disposition of the Company’s Securities. In addition, this summary does not address the Medicare tax on certain investment income, U.S. federal estate or gift tax laws, any U.S. state or local or non-U.S. tax laws, any tax treaties or any other tax law. Furthermore, this discussion does not address all U.S. federal income tax considerations that may be relevant to particular U.S. Holders in light of their personal circumstances or that may be relevant to certain categories of U.S. Holders that may be subject to special treatment under the U.S. federal income tax laws, such as:

 

●

Holders of MBSC Class A Common Shares or Class B Common Shares or MBSC Private Placement Warrants prior to the Business Combination;

 

●

banks, insurance companies, or other financial institutions;

 

●

tax-exempt or governmental organizations;

 

●

dealers in securities or foreign currencies;

 

●

persons whose functional currency is not the U.S. dollar;

 

●

traders in securities that use the mark-to-market method of accounting for U.S. federal income tax purposes;

 

●

“controlled foreign corporations,” “passive foreign investment companies,” and corporations that accumulate earnings to avoid U.S. federal income tax;

 

●

regulated investment companies, real estate investment trusts and persons subject to the alternative minimum tax;

 

●

entities or arrangements treated as partnerships or other pass-through entities for U.S. federal income tax purposes or holders of interests therein;

 

●

persons deemed to sell the Company’s Securities under the constructive sale provisions of the Code;

 

●

persons that acquired the Company’s Securities through the exercise of employee stock options or otherwise as compensation or through a tax-qualified retirement plan;

 

●

persons that hold the Company’s Securities as part of a straddle, appreciated financial position, synthetic security, hedge, conversion transaction, or other integrated investment or risk reduction transaction;

 

●

certain former citizens or long-term residents of the United States;

 

●

persons that actually or constructively own 10% or more (by vote or value) of any class of shares of the Company;

 

●

the Company’s officers or directors; and

 

●

persons who are not U.S. Holders.

 

 

If a partnership (including an entity or arrangement treated as a partnership for U.S. federal income tax purposes) holds the Company’s Securities, the tax treatment of a partner in such partnership generally will depend upon the status of the partner, upon the activities of the partnership and upon certain determinations made at the partner level. Accordingly, partners in partnerships (including entities or arrangements treated as partnerships for U.S. federal income tax purposes) holding the Company’s Securities are urged to consult with and rely solely upon their own tax advisors regarding the U.S. federal income tax consequences to them relating to the matters discussed below.

 

ALL HOLDERS SHOULD CONSULT WITH AND RELY SOLELY UPON THEIR OWN TAX ADVISORS WITH RESPECT TO THE APPLICATION OF THE U.S. FEDERAL INCOME TAX LAWS (INCLUDING ANY POTENTIAL FUTURE CHANGES THERETO) TO THEIR PARTICULAR SITUATIONS, AS WELL AS ANY TAX CONSEQUENCES ARISING UNDER ANY OTHER TAX LAWS, INCLUDING U.S. FEDERAL ESTATE OR GIFT TAX LAWS OR ANY U.S. STATE OR LOCAL OR NON-U.S. TAX LAWS, OR UNDER ANY APPLICABLE INCOME TAX TREATY.

 

U.S. Holder Defined

 

For purposes of this discussion, a “U.S. Holder” is a beneficial owner of the Company’s Securities, for U.S. federal income tax purposes that is either:

 

●

an individual who is a citizen or resident of the United States;

 

●

a corporation (or other entity treated as a corporation for U.S. federal income tax purposes) created or organized in or under the laws of the United States, any state thereof, or the District of Columbia;

 

●

an estate the income of which is subject to U.S. federal income tax regardless of its source; or

 

●

a trust (i) the administration of which is subject to the primary supervision of a U.S. court and which has one or more “United States persons” (within the meaning of Section 7701(a)(30) of the Code) who have the authority to control all substantial decisions of the trust or (ii) that has made a valid election under applicable Treasury Regulations to be treated as a United States person.

 

Tax Characterization of Distributions with Respect to Common Shares

 

Subject to the PFIC rules discussed below, if the Company pays distributions of cash or other property to U.S. Holders of Common Shares, the gross amount of such distributions (without reduction for any Canadian income tax withheld from such distribution) generally will constitute dividends for U.S. federal income tax purposes to the extent paid from the Company’s current or accumulated earnings and profits, as determined under U.S. federal income tax principles, and will be treated as described in the section entitled “-Distributions Treated as Dividends” below. Distributions in excess of the Company’s current and accumulated earnings and profits will be treated as a non-taxable return of capital to the extent of the U.S. Holder’s adjusted tax basis in its Common Shares, that will be applied against and reduce (but not below zero) the U.S. Holder’s adjusted tax basis in its Common Shares. Any remaining portion of the distribution will be treated as gain from the sale or exchange of Common Shares and will be treated as described in the section entitled “-Gain or Loss on Sale or Other Taxable Exchange or Disposition of Common Shares and Warrants” below. However, the Company does not expect to maintain calculations of its earnings and profits in accordance with U.S. federal income tax accounting principles. A U.S. Holder should therefore assume that any distribution by the Company with respect to Common Shares will be reported as dividend income. U.S. Holders are urged to consult with and rely solely upon their own tax advisors with respect to the appropriate U.S. federal income tax treatment of any distribution received from the Company.

 

Possible Constructive Distributions with Respect to Warrants

 

The terms of the Company Warrants provide for an adjustment to the number of Common Shares for which Company Warrants may be exercised or to the exercise price of the Company Warrants in certain events. An adjustment which has the effect of preventing dilution generally should not be taxable. U.S. Holders of the Company Warrants would, however, be treated as receiving a constructive distribution from the Company if, for example, the adjustment increases the warrant holders’ proportionate interest in the Company’s assets or earnings and profits (e.g., through an increase in the number of Common Shares that would be obtained upon exercise or through a decrease in the exercise price of the Company Warrants) as a result of a distribution of cash or other property to the Holders of Common Shares. Any such constructive distribution would be treated in the same manner as if U.S. Holders of Company Warrants received a cash distribution from the Company generally equal to the fair market value of the increased interest and would be taxed in a manner similar to distributions to U.S. Holders of Common Shares described herein. See the section entitled “-Tax Characterization of Distributions with Respect to Common Shares” above. For certain information reporting purposes, the Company is required to determine the date and amount of any such constructive distributions. Proposed Treasury Regulations, which the Company may rely on prior to the issuance of final Treasury Regulations, specify how the date and amount of any such constructive distributions are determined.

 

 

Distributions Treated as Dividends

 

Dividends paid by the Company will be taxable to a corporate U.S. Holder at regular rates and will not be eligible for the dividends-received deduction generally allowed to domestic corporations in respect of dividends received from other domestic corporations. Dividends the Company pays to a non-corporate U.S. Holder generally will constitute “qualified dividends” that will be subject to U.S. federal income tax at the lower applicable long-term capital gains tax rate only if (i) Common Shares continue to be readily tradable on the Nasdaq or another established securities market in the United States or the Company is eligible for benefits of a comprehensive income tax treaty with the United States, and (ii) a certain holding period and other requirements are met, including that the Company is not classified as a PFIC during the taxable year in which the dividend is paid or a preceding taxable year with respect to such U.S. Holder. As discussed below, if a U.S. Holder held shares in the Company when it was classified as a PFIC, the Company would generally continue to be treated as a PFIC with respect to such U.S. Holder in a taxable year even if the Company is not classified as a PFIC in such taxable year. If such requirements are not satisfied, a non-corporate U.S. Holder may be subject to tax on the dividend at regular ordinary income tax rates instead of the preferential rate that applies to qualified dividend income. U.S. Holders should consult with and rely solely upon their own tax advisors regarding the availability of the lower preferential rate for qualified dividend income for any dividends paid with respect to Common Shares.

 

Dividends paid with respect to Common Shares will generally be treated as income from foreign sources for U.S. foreign tax credit purposes and will generally be treated as passive category income or, in the case of certain types of U.S. Holders, general category income for purposes of computing allowable foreign tax credits for U.S. foreign tax credit purposes. Depending on the U.S. Holder’s individual facts and circumstances, a U.S. Holder may be eligible, subject to a number of complex limitations, to claim a foreign tax credit not in excess of any applicable treaty rate in respect of any foreign withholding taxes imposed on dividends received on Common Shares. A U.S. Holder that does not elect to claim a foreign tax credit for foreign tax withheld may, generally, instead claim a deduction, for U.S. federal income tax purposes, in respect of such withholding, but only for a year in which such U.S. Holder elects to do so for all creditable foreign income taxes.

 

THE RULES GOVERNING THE FOREIGN TAX CREDIT ARE COMPLEX, AND THE OUTCOME OF THEIR APPLICATION DEPENDS IN LARGE PART ON THE U.S. HOLDER’S INDIVIDUAL FACTS AND CIRCUMSTANCES. ACCORDINGLY, U.S. HOLDERS ARE URGED TO CONSULT WITH AND RELY SOLELY UPON THEIR OWN TAX ADVISORS REGARDING THE AVAILABILITY OF THE FOREIGN TAX CREDIT IN THEIR PARTICULAR CIRCUMSTANCES.

 

Gain or Loss on Sale or Other Taxable Exchange or Disposition of Common Shares and Company Warrants

 

Subject to the PFIC rules discussed below, upon a sale or other taxable disposition of Common Shares or Warrants, a U.S. Holder generally will recognize capital gain or loss in an amount equal to the difference between (i) the sum of the amount of cash and the fair market value of any property received in such disposition and (ii) the U.S. Holder’s adjusted tax basis in the Common Shares or Company Warrants. A U.S. Holder’s adjusted tax basis in its Common Shares or Company Warrants generally will equal the U.S. Holder’s acquisition cost of its Common Shares or Company Warrants or, as discussed below, the U.S. Holder’s initial basis for the Common Shares received upon exercise of Company Warrants, less, in the case of Common Shares, any prior distributions paid to such U.S. Holder that were treated as a return of capital for U.S. federal income tax purposes (as discussed below).

 

Any such capital gain or loss generally will be long-term capital gain or loss if the U.S. Holder’s holding period for the Common Shares or Company Warrants, as applicable, so disposed of exceeds one year. If the one-year holding period requirement is not satisfied, any gain on a sale or other taxable disposition of the Common Shares or Company Warrants, as applicable, would be subject to short-term capital gain treatment and would be taxed at regular ordinary income tax rates. Long-term capital gains recognized by non-corporate U.S. Holders may be eligible to be taxed at reduced rates. The deductibility of capital losses is subject to limitations.

 

Cash Exercise of a Company Warrant

 

Subject to the PFIC rules discussed below, a U.S. Holder generally will not recognize gain or loss on the acquisition of Common Shares upon the exercise of a Company Warrant for cash. The U.S. Holder’s adjusted tax basis in its Common Shares received upon exercise of a Company Warrant generally will be an amount equal to the sum of the U.S. Holder’s adjusted tax basis in such Company Warrant and the exercise price of such Company Warrant. It is unclear whether a U.S. Holder’s holding period for the Common Shares received upon exercise of the Company Warrant will commence on the date of exercise of the Company Warrant or the immediately following date. In either case, the holding period will not include the period during which the U.S. Holder held the Company Warrant.

 

 

Cashless Exercise of a Company Warrant

 

The tax characterization of a cashless exercise of a Company Warrant is not clear under current U.S. federal tax law. Due to the absence of authority on the U.S. federal income tax treatment of a cashless exercise, there can be no assurance which, if any, of the alternative tax characterizations and resultant tax consequences would be adopted by the IRS or upheld by a court of law. Accordingly, U.S. Holders should consult with and rely solely upon their own tax advisors regarding the tax consequences of a cashless exercise.

 

Subject to the PFIC rules discussed below, a cashless exercise could potentially be characterized as any of the following for U.S. federal income tax purposes: (i) not a realization event and thus tax-deferred, (ii) a realization event that qualifies as a tax-deferred “recapitalization,” or (iii) a taxable realization event. While not free from doubt, the Company intends to treat any cashless exercise of a Company Warrant occurring after its giving notice of an intention to redeem the Company Warrant for cash, as will be permitted under the terms of the Warrant Agreement, as if the Company redeemed such Company Warrant for shares in a cashless exchange qualifying as a tax-deferred recapitalization. However, there is some uncertainty regarding the Company’s intended tax treatment, and it is possible that a cashless exercise could be characterized differently by the IRS or a court. Accordingly, the tax consequences of all three characterizations are generally described below. U.S. Holders should consult with and rely solely upon their own tax advisors regarding the tax consequences of a cashless exercise.

 

If a cashless exercise were characterized as either not a realization event or as a realization event that qualifies as a recapitalization, a U.S. Holder would not recognize any gain or loss on the exchange of Company Warrants for Common Shares. A U.S. Holder’s basis in the Common Shares received would generally equal the U.S. Holder’s aggregate basis in the exchanged Company Warrants. If the cashless exercise were not a realization event, it is unclear whether a U.S. Holder’s holding period in the Common Shares would be treated as commencing on the date of exchange of the Company Warrants or on the immediately following date, but the holding period would not include the holding period of the Company Warrants exercised therefor. On the other hand, if the cashless exercise were characterized as a realization event that qualifies as a recapitalization, the holding period of the Common Shares would include the holding period of the Company Warrants exercised therefor.

 

If the cashless exercise were treated as a realization event that does not qualify as a recapitalization, the cashless exercise could be treated in whole or in part as a taxable exchange in which gain or loss would be recognized by the U.S. Holder. Under this characterization, a portion of the Company Warrants to be exercised on a “cashless basis” would be deemed to have been surrendered in payment of the exercise price of the remaining portion of such Company Warrants, which would be deemed to be exercised. In such a case, a U.S. Holder would effectively be deemed to have sold a number of Company Warrants having an aggregate value equal to the exercise price of the remaining Company Warrants deemed exercised. Subject to the PFIC rules described below, the U.S. Holder would recognize capital gain or loss in an amount generally equal to the difference between the value of the portion of the Company Warrants deemed sold and its adjusted tax basis in such Company Warrants (generally in the manner described in the section entitled “-Gain or Loss on Sale or Other Taxable Exchange or Disposition of Common Shares and Company Warrants” above), and the U.S. Holder’s adjusted tax basis in the Common Shares received would generally equal the sum of the U.S. Holder’s adjusted tax basis in the remaining Company Warrants deemed exercised and the exercise price of such Company Warrants. It is unclear whether a U.S. Holder’s holding period for the Common Shares would commence on the date of exercise of the Company Warrants or on the date following the date of exercise of the Company Warrants, but the holding period would not include the period during which the U.S. Holder held the Company Warrants. U.S. Holders should consult with and rely solely upon their own tax advisors regarding the tax consequences of a cashless exercise.

 

Redemption or Repurchase of Warrants for Cash

 

Subject to the PFIC rules discussed below, if the Company redeems the Company Warrants for cash as will be permitted under the terms of the Warrant Agreement or if the Company repurchases Company Warrants in an open market transaction, such redemption or repurchase generally will be treated as a taxable disposition to the U.S. Holder, taxed as described in the section entitled “-Gain or Loss on Sale or Other Taxable Exchange or Disposition of Common Shares and Warrants” above.

 

Expiration of a Warrant

 

If a Company Warrant is allowed to expire unexercised, a U.S. Holder generally will recognize a capital loss equal to such U.S. Holder’s adjusted tax basis in the Company Warrant. The deductibility of capital losses is subject to certain limitations for U.S. federal income tax purposes.

 

 

Receipt of Non-U.S. Currency

 

The gross amount of any dividend distribution that a U.S. Holder must include in income will be the U.S. dollar amount of the payments made in a currency other than U.S. dollars, calculated by reference to the exchange rate in effect on the day such U.S. Holder actually or constructively receives the payment in accordance with its regular method of accounting for U.S. federal income tax purposes regardless of whether the payment is in fact converted into U.S. dollars at that time. If the foreign currency is converted into U.S. dollars on the date of the payment, the U.S. Holder should not be required to recognize any foreign currency gain or loss with respect to the receipt of foreign currency. If, instead, the foreign currency is converted at a later date, any currency gains or losses resulting from the conversion of the foreign currency will be treated as U.S. source ordinary income or loss for U.S. foreign tax credit purposes, and will not be eligible for the special tax rate applicable to qualified dividend income. U.S. Holders are urged to consult their own tax advisors regarding the U.S. federal income tax consequences of receiving, owning, and disposing of foreign currency.

 

Passive Foreign Investment Company Rules

 

Adverse U.S. federal income tax rules apply to United States persons that hold, or are treated as holding, shares in a foreign (i.e., non-U.S.) corporation classified as a “passive foreign investment company” (a “PFIC”) for U.S. federal income tax purposes.

 

In general, the Company will be treated as a PFIC with respect to a U.S. Holder in any taxable year in which, after applying certain look-through rules, either:

 

●

at least 75% of its gross income for such taxable year consists of passive income (e.g., dividends, interest, rents (other than rents derived from the active conduct of a trade or business), and gains from the disposition of passive assets); or

 

●

the average percentage (ordinarily averaged quarterly over the year) by value of its assets during such taxable year that produce or are held for the production of passive income is at least 50%.

 

Because the revenue production of the Company is uncertain, and because PFIC status is based on income, assets and activities for an entire taxable year, there can be no assurance that the Company will not be treated as a PFIC under the income or asset test for the current taxable year or any future taxable year. For purposes of determining whether the Company is a PFIC, the Company will be treated as earning and owning its proportionate share of the income and assets, respectively, of any of its subsidiary corporations in which it owns at least 25% of the value of the subsidiary’s stock. The Company may hold, directly or indirectly, interests in other entities that are PFICs (“Subsidiary PFICs”). If the Company is a PFIC, each U.S. Holder will be treated as owning its pro rata share by value of the stock of any such Subsidiary PFICs.

 

Although PFIC status is determined annually, an initial determination that the Company is a PFIC for a taxable year will generally apply for subsequent years to a U.S. Holder who held (or is deemed to have held) Common Shares or Company Warrants during a tax year in which the Company was a PFIC, whether or not the Company is classified as a PFIC in those subsequent years. As discussed more fully below, if the Company were to be treated as a PFIC for any taxable year in which a U.S. Holder holds Common Shares or Company Warrants (regardless of whether the Company remains a PFIC for subsequent taxable years), a U.S. Holder would be subject to different tax rules depending on whether the U.S. Holder makes an election to treat the Company as a “qualified electing fund” (a “QEF Election”). As an alternative to making a QEF Election, a U.S. Holder should be able to make a “mark-to-market” election with respect to its Common Shares (but not with respect to Company Warrants), as discussed below. If the Company is a PFIC, a U.S. Holder will be subject to the PFIC rules described herein with respect to any of the Company’s Subsidiary PFICs. However, the mark-to-market election discussed below will likely not be available with respect to shares of such Subsidiary PFICs. In addition, if a U.S. Holder owns Common Shares during any taxable year that the Company is a PFIC, such U.S. Holder must file an annual report with the IRS reflecting such ownership, regardless of whether a QEF Election or a mark-to-market election had been made.

 

Taxation of U.S. Holders Making a Timely QEF Election. In general, if the Company is treated as a PFIC, a U.S. Holder may be able to avoid the PFIC tax consequences described below in respect of its Common Shares (but not its Company Warrants) by making a timely and valid QEF Election (if eligible to do so) in the first taxable year in which such U.S. Holder held (or was deemed to hold) Common Shares and the Company is classified as a PFIC. Generally, a QEF Election should be made on or before the due date for filing such U.S. Holder’s U.S. federal income tax return for such taxable year.

 

If a U.S. Holder timely makes a QEF Election with respect to its Common Shares (such electing U.S. Holder, an “Electing Holder”), each year the Electing Holder will be required to include in its income its pro rata share of the Company’s (and any of the Company’s subsidiaries that are PFIC Subsidiaries) ordinary earnings (as ordinary income) and net capital gains (as long-term capital gain), if any, for the Company’s taxable year that ends with or within the taxable year of the Electing Holder, regardless of whether the Company makes distributions to the Electing Holder (although an Electing Holder generally may make a separate election to defer the payment of taxes on undistributed income inclusions under the qualified electing fund rules, but if deferred, any such taxes will be subject to an interest charge). The Electing Holder’s adjusted tax basis in the shares of the Company would be increased to reflect taxed but undistributed earnings and profits. Distributions of earnings and profits that had been previously taxed would result in a corresponding reduction in the adjusted tax basis in the Electing Holder’s Common Shares and would not be taxed again once distributed. An Electing Holder would generally recognize capital gain or loss on the sale, exchange, or other disposition of its Common Shares, and no additional tax will be imposed under the PFIC rules.

 

 

A U.S. Holder would make a QEF Election with respect to any year that the Company and any Subsidiary PFICs are treated as PFICs by filing IRS Form 8621 (Information Return by a Shareholder of a Passive Foreign Investment Company or Qualified Electing Fund) with its U.S. federal income tax return for such year. Once made, the QEF Election will apply to all subsequent taxable years of the Electing Holder during which it holds Common Shares, unless the Company ceases to be a PFIC or such election is revoked by the Electing Holder with the consent of the IRS. In order to comply with the QEF Election requirements, an Electing Holder must receive a PFIC annual information statement from the Company. There can be no assurance that the Company will provide to a U.S. Holder such information as the IRS may require, including a PFIC annual information statement, in order to enable such U.S. Holder to make and maintain a QEF Election. There is also no assurance that the Company will have timely knowledge of its status as a PFIC in the future or of the required information to be provided.

 

It is not entirely clear how various aspects of the PFIC rules apply to the Company Warrants, and U.S. Holders are strongly urged to consult with and rely solely upon their own tax advisors regarding the application of such rules to their Warrants in their particular circumstances. A U.S. Holder may not make a QEF Election with respect to its Company Warrants. As a result, if a U.S. Holder sells or otherwise disposes of Company Warrants (other than upon exercise of such Warrants), currently proposed Treasury Regulations relating to the treatment of options with respect to PFICs were finalized (or the principles therein were deemed self-executing) in their current form, and the Company were treated as a PFIC at any time during the U.S. Holder’s holding period of such Company Warrants, then any gain recognized by such U.S. Holder upon a sale or other disposition of such Company Warrants (other than upon exercise of such Warrants) may be treated as an excess distribution, taxed as described below. If a U.S. Holder that exercises its Company Warrants properly makes a QEF Election with respect to the newly acquired Common Shares (or has previously made a QEF Election with respect to Common Shares), the QEF Election will apply to the newly acquired Common Shares. Notwithstanding such QEF Election, the adverse tax consequences relating to PFIC shares, adjusted to take into account the current income inclusions resulting from the QEF Election, generally will continue to apply with respect to such newly acquired Common Shares (which generally will be deemed to have a holding period for purposes of the PFIC rules that includes the period the U.S. Holder held the Company Warrants), unless the U.S. Holder makes a purging election under the PFIC rules. Under one type of purging election, the U.S. Holder will be deemed to have sold such shares at their fair market value, and any gain recognized on such deemed sale will be treated as an excess distribution, as described below. As a result of such purging election, the U.S. Holder will have additional basis (to the extent of any gain recognized on the deemed sale) and, solely for purposes of the PFIC rules, a new holding period in the Common Shares acquired upon the exercise of the Company Warrants. The application of the rules related to purging elections described above to a U.S. Holder of Company Warrants that already owns Common Shares is not entirely clear. U.S. Holders are strongly urged to consult with and rely solely upon their own tax advisors regarding the application of the rules governing purging elections to their particular circumstances.

 

Taxation of U.S. Holders Making a “Mark-to-Market” Election. Alternatively, if the Company is treated as a PFIC for any taxable year and, as the Company anticipates, Common Shares are treated as “marketable stock,” a U.S. Holder that holds Common Shares at the close of such U.S. Holder’s taxable year may make a “mark-to-market” election with respect to such shares, provided the U.S. Holder completes and files IRS Form 8621 in accordance with the relevant instructions and related Treasury Regulations. If made, a mark-to-market election would be effective for the taxable year for which the election is made and for all subsequent taxable years, unless Common Shares cease to qualify as “marketable stock” for purposes of the PFIC rules or the IRS consents to the revocation of the election.

 

If the U.S. Holder makes a valid mark-to-market election for the first taxable year of the U.S. Holder in which the U.S. Holder holds (or is deemed to hold) Common Shares and in which the Company is treated as a PFIC, such U.S. Holder generally will not be subject to the PFIC rules described below in respect of its Common Shares. Instead, in general, such U.S. Holder would include as ordinary income in each taxable year the excess, if any, of the fair market value of its Common Shares at the end of the taxable year over such U.S. Holder’s adjusted tax basis in its Common Shares. These amounts of ordinary income would not be eligible for the favorable tax rates applicable to qualified dividend income or long-term capital gains. Such U.S. Holder also would be permitted an ordinary loss in respect of the excess, if any, of its adjusted tax basis in its Common Shares over the fair market value of its Common Shares at the end of the taxable year, but only to the extent of the net amount previously included in income as a result of the mark-to-market election. Such U.S. Holder’s tax basis in its Common Shares would be adjusted to reflect any such income or loss amounts. Any gain recognized by such U.S. Holder on the sale, exchange, or other disposition of its Common Shares would be treated as ordinary income, and any loss recognized on the sale, exchange, or other disposition of its Common Shares would be treated as ordinary loss to the extent that such loss does not exceed the net mark-to-market gains previously included in income by the U.S. Holder. A mark-to-market election under the PFIC rules with respect to Common Shares would not apply to a Subsidiary PFIC, and a U.S. Holder would not be able to make such a mark-to-market election in respect of its indirect ownership interest in that Subsidiary PFIC. Consequently, U.S. Holders of Common Shares could be subject to the PFIC rules with respect to income of Subsidiary PFICs, the value of which already had been taken into account indirectly via mark-to-market adjustments. Special rules may apply if a U.S. Holder makes a mark-to-market election for a taxable year after the first taxable year in which the U.S. Holder holds (or is deemed to hold) its Common Shares. Currently, a mark-to-market election may not be made with respect to Warrants.

 

 

Taxation of U.S. Holders Not Making a Timely QEF or Mark-to-Market Election. Finally, if the Company were treated as a PFIC for any taxable year, a U.S. Holder who does not make either a QEF Election (including a late QEF Election with a purging election described below) or a mark-to-market election for that year (a “Non-Electing Holder”) would be subject to special rules with respect to (i) any “excess distribution” (generally, the portion of any distributions received by the Non-Electing Holder on its Common Shares during a taxable year in excess of 125% of the average annual distributions received by the Non-Electing Holder during the three preceding taxable years, or, if shorter, the Non-Electing Holder’s holding period for its Common Shares) and (ii) any gain realized on the sale, exchange, or other disposition of its Common Shares. Under these special rules:

 

●

the Non-Electing Holder’s excess distribution or gain would be allocated ratably over the Non-Electing Holder’s aggregate holding period for its Common Shares or Company Warrants;

 

●

the amount allocated to the Non-Electing Holder’s taxable year in which the Non-Electing Holder received the excess distribution or realized the gain, or to the portion of the Non-Electing Holder’s holding period prior to the first day of the Company’s taxable year for which the Company was a PFIC, would be taxed as ordinary income; and

 

●

the amount allocated to each of the other taxable years (or portions thereof) of the Non-Electing Holder would be subject to tax at the highest rate of tax in effect for the Non-Electing Holder for that year, and an interest charge for the deemed deferral benefit would be imposed with respect to the resulting tax attributable to each such other taxable year (or portion thereof).

 

If a U.S. Holder held Common Shares during a period when the Company was treated as a PFIC, but the U.S. Holder did not have a QEF Election in effect with respect to the Company (or held Company Warrants during a period when the Company was treated as a PFIC that were subsequently exercised for Common Shares), then in the event that the Company did not qualify as a PFIC for a subsequent taxable year, the U.S. Holder could elect to cease to be subject to the rules described above with respect to those shares by making a “deemed sale” election with respect to its Common Shares. If the U.S. Holder makes a deemed sale election, the U.S. Holder will be treated, for purposes of applying the rules described in the preceding paragraph, as having disposed of its Common Shares for their fair market value on the last day of the last taxable year for which the Company qualified as a PFIC (the “termination date”). The U.S. Holder would increase its basis in such Common Shares by the amount of the gain on the deemed sale described in the preceding sentence, and the amount of gain would be taxed as an excess distribution. Following a deemed sale election, the U.S. Holder would not be treated, for purposes of the PFIC rules, as having owned Common Shares during a period prior to the termination date when the Company qualified as a PFIC and would not be treated as owning PFIC stock thereafter unless the Company later qualifies as a PFIC. The holding period for such stock would begin the day after the termination date for purposes of the PFIC rules.

 

THE PFIC RULES (INCLUDING THE RULES WITH RESPECT TO THE QEF ELECTION AND THE MARK-TO-MARKET ELECTION) ARE VERY COMPLEX, ARE AFFECTED BY VARIOUS FACTORS IN ADDITION TO THOSE DESCRIBED ABOVE, AND THEIR APPLICATION IS UNCERTAIN. U.S. HOLDERS ARE STRONGLY URGED TO CONSULT WITH AND RELY SOLELY UPON THEIR OWN TAX ADVISORS TO DETERMINE THE APPLICATION OF THE PFIC RULES TO THEM IN THEIR PARTICULAR CIRCUMSTANCES AND ANY RESULTING TAX CONSEQUENCES.

 

Information Reporting and Backup Withholding

 

Dividends paid to U.S. Holders with respect to Common Shares and proceeds from the sale, exchange, or redemption of the Company’s Securities may be subject, under certain circumstances, to information reporting and backup withholding. Backup withholding will not apply, however, to a U.S. Holder that (i) is a corporation or entity that is otherwise exempt from backup withholding (which, when required, certifies as to its exempt status) or (ii) furnishes a correct taxpayer identification number and makes any other required certification on IRS Form W-9 (Request for Taxpayer Identification Number and Certification). Backup withholding is not an additional tax. Rather, the U.S. federal income tax liability (if any) of persons subject to backup withholding will be reduced by the amount of tax withheld. If backup withholding results in an overpayment of taxes, a refund generally may be obtained, provided that the required information is timely furnished to the IRS.

 

Certain U.S. Holders may be required to file an IRS Form 926 (Return by a U.S. Transferor of Property to a Foreign Corporation) to report a transfer of property (including stock, securities, or cash) to the Company. Substantial penalties may be imposed on a U.S. Holder that fails to comply with this reporting requirement, and the period of limitations on assessment and collection of U.S. federal income taxes will be extended in the event of a failure to comply. Furthermore, certain U.S. Holders who are individuals and certain entities will be required to report information with respect to such U.S. Holder’s investment in “specified foreign financial assets” on IRS Form 8938 (Statement of Specified Foreign Financial Assets), subject to certain exceptions. An interest in the Company constitutes a specified foreign financial asset for these purposes. Persons who are required to report specified foreign financial assets and fail to do so may be subject to substantial penalties, and the period of limitations on assessment and collection of U.S. federal income taxes will be extended in the event of a failure to comply. U.S. Holders are urged to consult with and rely solely upon their own tax advisors regarding the foreign financial asset and other reporting obligations and their application to their ownership of the Company’s Securities.

 

THE FOREGOING DISCUSSION IS NOT A COMPREHENSIVE DISCUSSION OF ALL OF THE U.S. FEDERAL INCOME TAX CONSEQUENCES TO HOLDERS OF THE COMPANY’S SECURITIES. SUCH HOLDERS SHOULD CONSULT WITH AND RELY SOLELY UPON THEIR OWN TAX ADVISORS TO DETERMINE THE SPECIFIC TAX CONSEQUENCES TO THEM OF OWNING THE COMPANY’S SECURITIES, INCLUDING THE APPLICABILITY AND EFFECT (AND ANY POTENTIAL FUTURE CHANGES THERETO) OF ANY U.S. FEDERAL, STATE OR LOCAL OR NON-U.S. TAX LAWS AND ANY INCOME TAX TREATIES.

 

 

MATERIAL CANADIAN FEDERAL INCOME TAX CONSIDERATIONS

 

The following summary describes the principal Canadian federal income tax considerations generally applicable to beneficial owners of Company Securities with respect to the ownership and disposition of such Company Securities and who, at all relevant times, for purposes of the ITA (i) is not, and is not deemed to be, resident in Canada, (ii) deals at arm’s length with the Company, (iii) is not affiliated with the Company, (iv) holds Company Securities as capital property, (v) does not use or hold, and is not deemed to use or hold, Company Securities in a business carried on in Canada, (vi) does not have a “permanent establishment” or “fixed base” in Canada, (vii) has not entered into, with respect to Company Securities, a “derivative forward agreement” or a “dividend rental agreement” each as defined in the ITA (“Non-Canadian Holder”). This summary does not apply to a beneficial owner of Company Securities that is an insurer carrying on an insurance business in Canada and elsewhere.

 

This summary does not address the Canadian tax treatment of any other transactions occurring in connection with the Business Combination, including, but not limited to, the Amalgamation and the Merger. This summary assumes Common Shares will be listed on a designated stock exchange (which currently includes the NYSE) at all relevant times. Additional specific considerations related to the “foreign affiliate dumping” rules in section 212.3 of the ITA, may be applicable and are not discussed herein. Holders should consult their tax advisors with respect to these rules and particular consequences.

 

This summary is based on the current provisions of the ITA and an understanding of the current administrative policies and assessing practices of the CRA published in writing prior to the date hereof. This summary takes into account all specific proposals to amend the ITA and the Canada-United States Tax Convention (1980) as amended (the “Treaty”) publicly announced by or on behalf of the Minister of Finance (Canada) prior to the date hereof (the “Proposed Amendments”) and assumes the Proposed Amendments will be enacted in the form proposed. However, no assurances can be given that the Proposed Amendments will be enacted in the form proposed, or at all. This summary does not otherwise take into account or anticipate any changes in the law or administrative policy or assessing practice, whether by legislative, administrative, or judicial action, nor does it take into account tax legislation or considerations of any province, territory, or foreign jurisdiction, which may differ from those discussed herein.

 

The summary is of a general nature only and is not, and is not intended to be, nor should it be construed as, legal or tax advice to any particular holder. This summary is not exhaustive of all Canadian federal income tax considerations. The relevant tax considerations applicable to the acquiring, holding and disposing of the Common Shares may vary according to the status of the holder, the jurisdiction in which the holder resides or carries on business, and the holder’s own particular circumstances. Accordingly, holders should consult with their own tax advisors having regard to their own particular circumstances.

 

Currency Conversion

 

Generally, for purposes of the ITA, all amounts relating to the acquisition, holding, or disposition of Company Securities must be converted into Canadian dollars based on the exchange rates as determined in accordance with the ITA. The amount of dividends required to be included in the income of, and capital gains or capital losses realized by, a Non-Canadian Holder may be affected by fluctuations in the exchange rates.

 

 

Taxation of Non-Canadian Holders of Common Shares and Company Warrants

 

Exercise of Company Warrants

 

Generally, a Non-Canadian Holder will not recognize a gain or loss on the acquisition of Common Shares upon the exercise of a Company Warrant in accordance with the terms of the Warrant Agreement.

 

Dividends on the Common Shares

 

Dividends paid or credited, or deemed to be paid or credited, on the Common Shares to a Non-Canadian Holder will be subject to Canadian withholding tax at the rate of 25% subject to any reduction in the rate of withholding to which the Non-Canadian Holder is entitled under any applicable income tax convention. For example, under the Treaty, where the dividends on the Common Shares are considered to be paid to, or derived by, a Non-Canadian Holder that is the beneficial owner of the dividends and is a U.S. resident for the purposes of, and is entitled to benefits of, the Treaty, the applicable rate of Canadian withholding tax is generally reduced to 15%.

 

Non-Canadian Holders are urged to consult their own tax advisors to determine their entitlement to relief under an applicable income tax treaty or convention.

 

Disposition of the Common Shares and Company Warrants

 

On a disposition of a Common Share (other than to the Company, unless purchased by the Company in the open market in the manner in which shares are normally purchased by any member of the public in the open market) a Non-Canadian Holder will not be subject to tax under the ITA in respect of any capital gain realized by such Non-Canadian Holder, unless the Common Shares constitute “taxable Canadian property” (as defined in the ITA) of the Non-Canadian Holder at the time of disposition and the Non-Canadian Holder is not entitled to relief under an applicable income tax convention.

 

On a disposition of a Company Warrant (including on a disposition to the Company, whether purchased by the Company pursuant to the terms of the Warrant Agreement or in the open market in the manner in which shares are normally purchased by any member of the public in the open market), a Non-Canadian Holder will not be subject to tax under the ITA in respect of any capital gain realized by such Non-Canadian Holder, unless the Company Warrants constitute “taxable Canadian property” (as defined in the ITA) of the Non-Canadian Holder at the time of disposition and the Non-Canadian Holder is not entitled to relief under an applicable income tax convention.

 

Generally, provided the Common Shares and Company Warrants, as applicable, are listed on a designated stock exchange (which currently includes the NYSE) at the time of the disposition by a Non-Canadian Holder, the Common Shares and Company Warrants will not constitute taxable Canadian property of such Non-Canadian Holder at such time unless, at any time during the 60-month period immediately preceding the disposition of either Common Shares or Company Warrants, the following conditions are satisfied concurrently: (i) (a) the Non-Canadian Holder, (b) persons with whom the Non-Canadian Holder did not deal at arm’s length, (c) partnerships in which the Non-Canadian Holder or a person described in (b) holds a membership interest directly or indirectly through one or more partnerships, or (d) any combination of the persons and partnerships described in (a) through (c), owned 25% or more of the issued shares of any class or series of the capital stock of the Company, and (ii) more than 50% of the fair market value of the Common Shares was derived directly or indirectly from one or any combination of real or immovable property situated in Canada, “Canadian resource properties” (as defined in the ITA), “timber resource properties” (as defined in the ITA), and options in respect of, or interests in or for civil law rights in, any such properties whether or not the properties exist. Common Shares and Company Warrants may also be deemed to be taxable Canadian property in certain other circumstances.

 

A Non-Canadian Holder that disposes of, or is deemed to have disposed of, a Common Share or Company Warrant that constitutes “taxable Canadian property” and is not entitled to relief under an applicable income tax convention will generally be subject to capital gain or capital loss consequences in Canada.

 

Generally, one-half of any capital gain (a “taxable capital gain”) realized by a Non-Canadian Holder in a taxation year must be included in the Non-Canadian Holder’s income for the year, and one-half of any capital loss (an “allowable capital loss”) realized by a Non-Canadian Holder in a taxation year must be deducted from taxable capital gains realized by the Non-Canadian Holder in that year. Allowable capital losses in excess of taxable capital gains realized in a taxation year generally may be carried back and deducted in any of the three preceding taxation years or carried forward and deducted in any subsequent taxation year against net taxable capital gains realized in such years, to the extent and under the circumstances described in the ITA.

 

A Non-Canadian Holder contemplating a disposition of the Common Shares or Company Warrants that may constitute taxable Canadian property should consult a tax advisor prior to such disposition.

 

 

PLAN OF DISTRIBUTION

 

We have registered the offer and sale from time to time by the Selling Securityholders of:

 

●

up to 4,177,091 Common Shares of certain Selling Securityholders who purchased MBSC Class A Common Shares in a private placement pursuant to the PIPE Financing consummated in connection with the Business Combination for a purchase price of $10.10 per share, which shares were converted into Common Shares on a one-for-one basis as part of the Business Combination;

 

●

up to 4,250,000 Common Shares issued to the MBSC Sponsor and its transferees in exchange for their MBSC Class B Common Shares on a one-for-one basis (after giving effect to certain forfeitures of MBSC Class B Common Shares) pursuant to the Business Combination, which MBSC Class B Common Shares were originally issued in private placements by MBSC (as defined below) for a purchase price of approximately $0.01 per share;

 

●

37,184,458 Common Shares and 3,098,789 Company Warrants issued to the Greenfire Holders pursuant to the Business Combination in exchange for their securities of Greenfire acquired by them in their capacities as employees, executives and founders that in most cases were issued for nominal consideration or pursuant to grants to such executives under Greenfire’s equity incentive plans;

 

●

2,526,667 Company Warrants issued to the MBSC Sponsor in exchange for its MBSC Private Placement Warrants on a one-for-one basis (after giving effect to certain forfeitures of MBSC Private Placement Warrants) pursuant to the Business Combination, which MBSC Private Placement Warrants were originally purchased in a private placement in connection with the MBSC IPO for a purchase price of $1.50 per warrant; and

 

●

up to 5,625,456 Common Shares issuable upon exercise of the Company Warrants of MBSC Sponsor and the Greenfire Holders.

 

The Selling Securityholders, which as used here includes donees, pledgees, transferees or other successors-in-interest selling Company Warrants, Common Shares or interests therein received after the date of this prospectus from a Selling Securityholder as a gift, pledge, partnership distribution or other transfer, may, from time to time, sell, transfer or otherwise dispose of any or all of their Company Warrants, Common Shares or interests therein on any stock exchange, market or trading facility on which the Company Warrants or Common Shares are traded or in private transactions. These dispositions may be at fixed prices, at prevailing market prices at the time of sale, at prices related to the prevailing market price, at varying prices determined at the time of sale, or at negotiated prices.

 

The Selling Securityholders may use any one or more of the following methods when disposing of Company Warrants, Common Shares or interests therein:

 

●

ordinary brokerage transactions and transactions in which the broker-dealer solicits purchasers;

 

●

block trades in which the broker-dealer will attempt to sell the shares as agent, but may position and resell a portion of the block as principal to facilitate the transaction;

 

●

purchases by a broker-dealer as principal and resale by the broker-dealer for their account;

 

●

an exchange distribution in accordance with the rules of the applicable exchange;

 

●

privately negotiated transactions;

 

 

●

short sales effected after the date the registration statement of which this prospectus forms a part was originally declared effective by the SEC;

 

●

through the writing or settlement of options or other hedging transactions, whether through an options exchange or otherwise;

 

●

broker-dealers may agree with the Selling Securityholders to sell a specified number of such shares at a stipulated price per share;

 

●

a combination of any such methods of sale; and

 

●

any other method permitted by applicable law.

 

The Selling Securityholders may, from time to time, pledge or grant a security interest in some or all of the Company Warrants or Common Shares owned by them and, if they default in the performance of their secured obligations, the pledgees or secured parties may offer and sell the Company Warrants or Common Shares, from time to time, under this prospectus, or under an amendment to this prospectus under Rule 424(b)(3) or other applicable provision of the Securities Act amending the list of Selling Securityholders to include the pledgee, transferee or other successors in interest as Selling Securityholders under this prospectus. The Selling Securityholders also may transfer the Company Warrants or Common Shares in other circumstances, in which case the transferees, pledgees or other successors in interest will be the selling beneficial owners for purposes of this prospectus.

 

In connection with the sale of our Company Warrants, Common Shares or interests therein, the Selling Securityholders may enter into hedging transactions with broker-dealers or other financial institutions, which may in tum engage in short sales of the Company Warrants or Common Shares in the course of hedging the positions they assume. The Selling Securityholders may also sell Company Warrants or Common Shares short and deliver these securities to close out their short positions, or loan or pledge the Company Warrants or Common Shares to broker-dealers that in tum may sell these securities. The Selling Securityholders may also enter into option or other transactions with broker-dealers or other financial institutions or the creation of one or more derivative securities which require the delivery to such broker-dealer or other financial institution of Company Warrants or Common Shares offered by this prospectus, which Company Warrants or Common Shares such broker-dealer or other financial institution may resell pursuant to this prospectus (as supplemented or amended to reflect such transaction).

 

Each of the Selling Securityholders reserves the right to accept and, together with their agents from time to time, to reject, in whole or in part, any proposed purchase of Company Warrants or Common Shares to be made directly or through agents. We will not receive any of the proceeds from this offering. Upon any exercise of the Company Warrants by payment of cash, however, we will receive the exercise price of the Company Warrants.

 

The Selling Securityholders and any underwriters, broker-dealers or agents that participate in the sale of the Common Shares or interests therein may be “underwriters” within the meaning of Section 2(11) of the Securities Act.

 

Any discounts, commissions, concessions or profit they earn on any resale of the Common Shares may be underwriting discounts and commissions under the Securities Act. Selling securityholders who are “underwriters” within the meaning of Section 2(11) of the Securities Act will be subject to the prospectus delivery requirements of the Securities Act.

 

In addition, a Selling Securityholder that is an entity may elect to make a pro rata in-kind distribution of securities to its members, partners or stockholders pursuant to the registration statement by delivering a prospectus with a plan of distribution. Such members, partners or stockholders would thereby receive freely tradeable securities pursuant to the distribution through a registration statement.

 

To the extent required, the Company Warrants or Common Shares to be sold, the names of the Selling Securityholders, the respective purchase prices and public offering prices, the names of any agents, dealer or underwriter, any applicable commissions or discounts with respect to a particular offer will be set forth in an accompanying prospectus supplement or, if appropriate, a post-effective amendment to the registration statement.

 

In order to comply with the securities laws of some states, if applicable, the Company Warrants or Common Shares may be sold in these jurisdictions only through registered or licensed brokers or dealers. In addition, in some states the Company Warrants or Common Shares may not be sold unless they have been registered or qualified for sale or an exemption from registration or qualification requirements is available and is complied with.

 

 

We have advised the Selling Securityholders that the anti-manipulation rules of Regulation M under the Exchange Act may apply to sales of Company Warrants or Common Shares in the market and to the activities of the Selling Securityholders and their affiliates. In addition, to the extent applicable we will make copies of this prospectus (as it may be supplemented or amended from time to time) available to the Selling Securityholders for the purpose of satisfying the prospectus delivery requirements of the Securities Act. The Selling Securityholders may indemnify any broker-dealer that participates in transactions involving the sale of the shares against certain liabilities, including liabilities arising under the Securities Act.

 

We have agreed to indemnify the Selling Securityholders against liabilities, including liabilities under the Securities Act and state securities laws, relating to the registration of the Company Warrants or Common Shares offered by this prospectus.

 

We have agreed with the Selling Securityholders to keep the registration statement effective until all of the shares covered by this prospectus have been disposed of pursuant to and in accordance with the registration statement or the securities have been withdrawn.

 

Restrictions to Sell

 

Pursuant to the Lock-Up Agreement, each of the MBSC Sponsor and the former Greenfire Shareholders party thereto agreed, subject to certain customary exceptions, not to (i) sell or assign, offer to sell, contract or agree to sell, hypothecate, pledge, grant any option to purchase or otherwise dispose of or agree to dispose of, directly or indirectly, or establish or increase a put equivalent position or liquidation with respect to or decrease a call equivalent position within the meaning of Section 16 of the Exchange Act, and the rules and regulations of the SEC promulgated thereunder with respect to, any equity securities of the Company, (ii) enter into any swap or other arrangement that transfers to another, in whole or in part, any of the economic consequences of ownership of any equity securities of the Company, whether any such transaction is to be settled by delivery of such securities, in cash or otherwise or (iii) make any public announcement of any intention to effect any transaction specified in clause (i) or (ii) until the earliest of (a) the date that is 180 days after the Closing Date, (b) the date that the last reported closing price of the Common Share equals or exceeds $12.00 per share (as adjusted for share splits, share dividends, reorganizations, recapitalizations and the like) for any 20 trading days within any 30-day trading period commencing at least 75 days after the Closing Date, and (c) the date on which the Company completes a liquidation, merger, amalgamation, arrangement, share exchange, reorganization or other similar transaction that results in all Company Shareholders having the right to exchange their shares of capital stock for cash, securities or other property. See “Risk Factors—Risks Related to Ownership of the Company’s Securities-A significant portion of the Company’s total outstanding securities may be sold into the market in the near future. This could cause the market price of the Common Shares and the Company Warrants to drop significantly, even if the Company’s business is performing well”. The Common Shares and Company Warrants held by Spicelo Limited are subject to a Limited Recourse Guarantee and Securities Pledge Agreement dated July 21, 2022 entered into by Spicelo Limited in favour of certain lenders to a group of entities unrelated to Greenfire that are, together with Spicelo, currently undergoing insolvency proceedings in Canada. In such insolvency proceedings, such lenders have sought to enforce against, and seize, the Common Shares and Company Warrants held by Spicelo Limited. Such lenders have taken the position that if the Common Shares and Company Warrants held by Spicelo Limited are transferred to the lenders such lenders will not be bound by the terms of the Lock-Up Agreement.

 

EXPENSES RELATED TO THE OFFERING

 

Set forth below is an itemization of the total expenses that are expected to be incurred by us in connection with the offer and sale of the Common Shares and Company Warrants by the Selling Securityholders. With the exception of the SEC registration fee, all amounts are estimates.

 

		U.S. Dollar
SEC Registration Fee		$	47,796.43
Legal Fees and Expenses		$	150,000.00
Accounting Fees and Expenses		$	20,000.00
Printing Expenses		$	10,000.00
Miscellaneous Expenses		$	40,000.00
Total		$	267,796.43

 

 

LEGAL MATTERS

 

Burnet, Duckworth & Palmer LLP, Canadian counsel to the Company, has provided a legal opinion for the Company regarding the validity of the Common Shares offered by this prospectus. Certain legal matters relating to U.S. law will be passed upon for the Company by Carter Ledyard & Milburn LLP. 

 

EXPERTS

 

The financial statements of the Company as of December 31, 2023 and 2022, and for each of the three years in the period ended December 31, 2023, included in this prospectus have been audited by Deloitte LLP, an independent registered public accounting firm, as stated in their report. Such financial statements are included in reliance upon the report of such firm given their authority as experts in accounting and auditing.

 

The financial statements of JACOS as of September 17, 2021, December 31, 2020 and January 1, 2020 and for the period ended September 17, 2021, and the year ended December 31, 2020, included in this prospectus have been audited by Deloitte LLP, an independent registered public accounting firm, as stated in their report. Such financial statements are included in reliance upon the report of such firm given their authority as experts in accounting and auditing.

 

Deloitte LLP, 850-2^nd Street SW #700, Calgary, Alberta, T2P 0R8, Canada, are the auditors of the Company.

 

McDaniel & Associates Consultants Ltd. is the independent qualified reserves evaluator of the Company. McDaniel & Associates Consultants Ltd. prepared three reports as to the reserves of the Company as of December 31, 2023, 2022 and 2021, which were prepared in accordance with guidelines specified in Item 1202(a)(8) of Regulation S-K and in conformity with Rule 4-10(a) of Regulation S-X, and are to be used for inclusion in certain filings of the SEC; such reports are filed as Exhibits 99.1, 99.2 and 99.3 to the registration statement of which this prospectus forms a part.

 

SERVICE OF PROCESS AND ENFORCEABILITY OF CIVIL LIABILITIES
UNDER U.S. SECURITIES LAWS

 

The Company is a corporation incorporated under the laws of the Province of Alberta. Other than Matthew Perkal, all of the Company’s directors and executive officers, as of the date of this prospectus, reside outside the United States. The majority of the Company’s assets and the assets of those non-resident persons are located outside the United States. As a result, it may not be possible for investors to effect service of process within the United States upon the Company or those persons or to enforce against the Company or them, either inside or outside the United States, judgments obtained in U.S. courts, or to enforce in U.S. courts, judgments obtained against them in courts in jurisdictions outside the United States, in any action predicated upon civil liability provisions of the federal securities laws of the United States or other laws of the United States.

 

The Company has appointed Puglisi & Associates as its agent upon whom process may be served in any action brought against the Company under the laws of the United States arising out of this offering or any purchase or sale of securities in connection with this offering. In addition, investors should not assume that the courts of Canada would enforce (i) judgments of U.S. courts obtained in actions against the Company, its officers or directors, or other said persons, predicated upon the civil liability provisions of the federal securities laws of the United States or other laws of the United States or (ii) in original actions, liabilities against the Company or such directors, officers or experts predicated upon the federal securities laws of the United States or other laws of the United States. In addition, there is doubt as to the applicability of the civil liability provisions of federal securities laws of the United States to original actions instituted in Canada. It may be difficult for an investor, or any other person or entity, to assert U.S. securities laws claims in original actions instituted in Canada.

 

 

WHERE YOU CAN FIND MORE INFORMATION

 

We have filed with the SEC a registration statement (including amendments and exhibits to the registration statement) on Form F-1 under the Securities Act. For purposes of this section, the term registration statement means the original registration statement and any and all amendments including the schedules and exhibits to the original registration statement or any amendment. This prospectus, which is part of the registration statement, does not contain all of the information set forth in the registration statement and the exhibits and schedules to the registration statement. For further information, we refer you to the registration statement and the exhibits and schedules filed as part of the registration statement. If a document has been filed as an exhibit to the registration statement, we refer you to the copy of the document that has been filed. Each statement in this prospectus relating to a document filed as an exhibit is qualified in all respects by the filed exhibit.

 

We are subject to the informational requirements of the Exchange Act applicable to foreign private issuers. Accordingly, we will be required to file reports and other information with the SEC, including annual reports on Form 20-F and reports on Form 6-K. The SEC maintains an internet website that contains reports and other information about issuers, like us, that file electronically with the SEC. The address of that website is www.sec.gov.

 

As a foreign private issuer, we are exempt under the Exchange Act from, among other things, the rules prescribing the furnishing and content of proxy statements, and our officers, directors and principal shareholders are exempt from the reporting and short-swing profit recovery provisions contained in Section 16 of the Exchange Act with respect to their purchase and sale of our Common Shares. In addition, we will not be required under the Exchange Act to file periodic reports and financial statements with the SEC as frequently or as promptly as U.S. companies whose securities are registered under the Exchange Act.

 

We will send our transfer agent a copy of all notices of shareholders’ meetings and other reports, communications and information that are made generally available to shareholders. The transfer agent has agreed to mail to all shareholders a notice containing the information (or a summary of the information) contained in any notice of a meeting of our shareholders received by the transfer agent and will make available to all shareholders such notices and all such other reports and communications received by the transfer agent.

 

 

INDEX TO FINANCIAL STATEMENTS

 

		Page
Audited Financial Statements of Greenfire Resources Ltd.
Report of Independent Registered Public Accounting Firm (PCAOB ID: 1208)		F-2
Consolidated Balance Sheets as at December 31, 2023 and December 31, 2022.		F-3
Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2023, December 31, 2022 and December 31, 2021		F-4
Consolidated Statements of Changes in Stockholders’ Equity for the Years Ended December 31, 2023, December 31, 2022 and December 31, 2021		F-5
Consolidated Statements of Cash Flows for the Years Ended December 31, 2023, December 31, 2022 and December 31, 2021		F-6
Notes to Consolidated Financial Statements		F-7
Unaudited Supplementary Information for Greenfire Resources Ltd. – oil and gas.		F-36

 

Audited Financial Statements of Japan Canada Oil Sands Limited
Report of Independent Registered Public Accounting Firm		F-43
Balance Sheets as at September 17, 2021, December 31, 2020 and January 1, 2020		F-44
Statements of Comprehensive Income (Loss) for the period ended September 17, 2021 and for the year ended December 31, 2020		F-45
Statements of Changes in Shareholders’ Equity (Deficit) for the period ended September 17, 2021 and for the year ended December 31, 2020		F-46
Statements of Cash Flows for the period ended September 17, 2021 and for the year ended December 31, 2020		F-47
Notes to Financial Statements		F-48

 

 

Report of Independent Registered Public Accounting Firm

 

To the Shareholders and the Board of Directors of

Greenfire Resources Ltd.

 

Opinion on the Financial Statements

 

We have audited the accompanying consolidated balance sheets of Greenfire Resources Ltd. and subsidiaries (the “Company”) as at December 31, 2023 and 2022, the related consolidated statements of comprehensive income (loss), changes in shareholders’ equity and cash flows, for each of the three years in the period ended December 31, 2023, 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 at December 31, 2023 and 2022, and its financial performance and its cash flows for each of the three years in the period ended December 31, 2023, in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

 

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 internal 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/ Deloitte LLP

 

Chartered Professional Accountants

Calgary, Canada

March 20, 2024

We have served as the Company’s auditor since 2021.

 

 

 

Greenfire Resources Ltd.

 

Consolidated Balance Sheets

 

As at December 31
($CAD thousands)		note				2023				2022
Assets
Current assets
Cash and cash equivalents			7			$	109,525			$	35,363
Restricted cash			8				-				35,313
Accounts receivable			14				34,680				34,308
Inventories			9				13,863				14,568
Prepaid expenses and deposits							5,746				3,975
							163,814				123,527
Non-current assets
Property, plant and equipment			10				941,374				963,050
Deferred income tax asset			12				68,295				87,681
							1,009,669				1,050,731
							1,173,483				1,174,258
Liabilities
Current liabilities
Accounts payable and accrued liabilities			22				59,850				46,569
Current portion of long-term debt			15				44,321				63,250
Warrant liability			20				18,630				-
Taxes payable			5				1,063				-
Current portion of lease liabilities			11				6,002				98
Risk management contracts			14				417				27,004
							130,283				136,921
Non-current liabilities
Long-term debt			15				332,029				191,158
Lease liabilities			11				7,722				865
Decommissioning liabilities			13				8,449				7,543
							348,200				199,566
							478,483				336,487
Shareholders’ equity
Share capital			5,19				158,515				15
Contributed surplus			5,19				9,788				44,674
Retained earnings (deficit)							526,697				793,082
							695,000				837,771
						$	1,173,483			$	1,174,258

 

Commitments and contingencies (note 18)

See accompanying notes to the consolidated financial statements

These Consolidated Financial Statements were approved by the Board of Directors.

 

Robert Logan, Director		Derek Aylesworth, Director

 

 

 

Greenfire Resources Ltd.

 

Consolidated Statements of Comprehensive Income (Loss)

 

($CAD thousands, except per share amounts)		note				Year ended December 31, 2023				Year ended December 31, 2022				Year ended December 31, 2021
Revenues
Oil sales			16			$	675,970			$	998,849			$	270,674
Royalties			16				(23,706	)			(50,064	)			(9,543	)
Oil sales, net of royalties							652,264				948,785				261,131
Gain (loss) on risk management contracts			14				16,405				(121,478	)			(39,291	)
							668,669				827,307				221,840
Expenses
Diluent expense							304,740				368,015				94,623
Transportation and marketing							55,673				67,842				24,057
Operating expenses							148,965				160,826				59,710
General and administrative							11,536				9,836				3,285
Stock-based compensation							9,808				1,183				-
Financing and interest			17				110,214				77,074				25,050
Depletion and depreciation			10				68,054				68,027				27,071
Exploration and other expenses							3,852				1,825				350
Other (income) expenses							(2,905	)			(206	)			8,373
Transaction costs			5,6				12,172				2,769				10,318
Listing expense			5				106,542				-				-
Gain on revaluation of warrants			20				(34,973	)			-				-
Gain on acquisitions			6				-				-				(693,953	)
Foreign exchange (gain) loss							(8,724	)			26,099				1,512
Total expenses							784,954				783,290				(439,604	)
Net income (loss) before taxes							(116,285	)			44,017				661,444
Income tax recovery (expense)			12				(19,386	)			87,681				-
Net income (loss) and comprehensive income (loss)						$	(135,671	)		$	131,698			$	661,444
Net income (loss) per share
Basic1			19			$	(2.49	)		$	2.69			$	15.52
Diluted1			19			$	(2.49	)		$	1.88			$	13.75

 

1

For the years ended December 31, 2022 and 2021 the Company’s basic and diluted earnings per share is the net income per common share of Greenfire Resources Inc (see Note 1), and the weighted average common shares outstanding has been recast by the applicable exchange ratio following the completion of the De-Spac Transaction with MBSC (Note 5.)

 

See accompanying notes to the consolidated financial statements

 

 

 

Greenfire Resources Ltd.

 

Consolidated Statements of Changes in Shareholders’ Equity

 

($CAD Thousands, except per share amounts)		note				Year ended December 31, 2023				Year ended December 31, 2022				Year ended December 31, 2021
Share capital
Balance, beginning of year						$	15			$	15			$	-
Issuance on exercise of bond warrants			5,19				38,911				-				-
Issuance to MBSC shareholders			5,19				62,959				-				-
Issuance of shares for PIPE investment			5,19				56,630				-				-
Shares issued during year			19				-				-				15
Balance, end of year							158,515				15				15
Contributed surplus
Balance, beginning of year							44,674				43,491				-
Stock based compensation			19				9,808				1,183				-
Exercise of performance warrants			5,19				(1,203	)			-				-
Issuance and exercise of bond warrants			5,19				(43,491	)			-				43,491
Balance, end of year							9,788				44,674				43,491
Retained earnings (deficit)
Balance, beginning of year							793,082				661,384				(60	)
Common shares repurchased and cancelled			5,19				(41,464	)			-				-
Dividend on De-Spac transaction			5,19				(59,388	)			-				-
Exercise of bond warrants			5,19				4,580				-				-
Exercise of performance warrants			5,19				1,202				-				-
Issuance of warrants			20				(35,644	)			-				-
Net income (loss) and comprehensive (loss)							(135,671	)			131,698				661,444
Balance, end of year							526,697				793,082				661,384
Total shareholders’ equity						$	695,000			$	837,771			$	704,890

 

See accompanying notes to the consolidated financial statements

 

 

 

Greenfire Resources Ltd.

 

Consolidated Statements of Cash Flows

 

($CAD Thousands, except per share amounts)		note				Year ended December 31, 2023				Year ended December 31, 2022				Year ended December 31, 2021
Operating activities
Net income (loss)						$	(135,671	)		$	131,698			$	661,444
Items not affecting cash:
Deferred income taxes			12				19,386				(87,681	)			-
Gain on acquisitions			6				-				-				(693,953	)
Unrealized (gain) loss on risk management contracts			14				(26,587	)			(8,673	)			35,677
Foreign exchange (gain) loss							(8,967	)			26,099				1,512
Depletion and depreciation			10				67,893				67,868				27,996
Stock based compensation			19				9,808				1,183				-
Other non-cash expenses							68				66				3,769
Accretion			13				906				743				298
Amortization of debt issuance costs			17				43,478				29,854				2,152
Debt redemption premium			15,17				19,152				-				-
Gain on revaluation of warrants			20				(34,973	)			-				-
Listing expense			5				106,542				-				-
Change in non- cash working capital			24				25,513				3,570				(6,910	)
Cash provided by operating activities							86,548				164,727				31,985
Financing activities
Issuance of long-term debt net of issuance costs			15				382,454				-				365,591
Repayment of long-term debt			15				(294,647	)			(123,612	)			-
Debt redemption premium			15,17				(19,152	)			-				-
Issuance of common shares			19				67,115				-				15
Common shares repurchased			5,19				(41,464	)			-				-
Dividend on De-Spac transaction			5,19				(59,388	)			-				-
De-Spac transaction costs			5,19				(34,817	)			-				-
Payment of lease liabilities			11				(99	)			(26	)			-
Cash provided (used) by financing activities							2				(123,638	)			365,606
Investing activities
Property, plant and equipment expenditures			10				(33,428	)			(39,592	)			(4,594	)
Cash and cash equivalents acquired in acquisitions			6				-				-				6,918
Acquisitions			6				-				-				(366,454	)
Restricted cash			8				35,313				(26,613	)			(8,140	)
Change in non-cash working capital (accrued additions to PP&E)			24				(13,988	)			2,459				35,742
Cash used in investing activities							(12,103	)			(63,746	)			(336,528	)
Exchange rate impact on cash and cash equivalents held in foreign currency							(285	)			(2,849	)			(194	)
Change in cash and cash equivalents							74,162				(25,506	)			60,869
Cash and cash equivalents, beginning of year							35,363				60,869				-
Cash and cash equivalents, end of year						$	109,525			$	35,363			$	60,869

 

See accompanying notes to the consolidated financial statements

 

 

 

Greenfire Resources Ltd.

 

Notes to the Consolidated Financial Statements

 

1. CORPORATE INFORMATION

 

Greenfire Resources Ltd. (the “Company” or “Greenfire”) was incorporated under the laws of Alberta on December 9, 2022. On September 20, 2023, the Company participated in a De-Spac transaction involving a number of entities, including Greenfire Resources Inc. (“GRI”) and M3-Brigade Acquisition III Corp (“MBSC”) (the “De-Spac Transaction”). Refer to Note 5 De-Spac Transaction for additional information. These audited consolidated financial statements are comprised of the accounts of Greenfire and its wholly owned subsidiaries, GRI and MBSC. The prior period amounts presented are those of GRI, which continued as the operating entity, concurrent with recapitalization. As of January 1, 2024, GRI was amalgamated with Greenfire Resources Operation Corporation (“GROC”).

 

The Company and its subsidiaries are engaged in the exploration, development and operation of oil and gas properties, focused primarily in the Athabasca oil sands region of Alberta. The Company’s corporate head office is located at 1900, 205 5th Avenue SW, Calgary, AB T2P 2V7.

 

2. BASIS OF PRESENTATION AND STATEMENT OF COMPLIANCE

 

These consolidated financial statements have been prepared in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board (“IFRS”). In these consolidated financial statements, all dollars are expressed in Canadian dollars, which is the Company’s functional currency, unless otherwise indicated. These consolidated financial statements have been prepared on a historical cost basis, except for certain financial instruments which are measured at fair value. The consolidated financial statements were approved by the Board of Directors on March 20, 2024.

 

3. MATERIAL ACCOUNTING POLICIES

 

Principles of consolidation

 

These consolidated financial statements consist of financial records of the Company and its wholly owned subsidiaries. The Company has two direct subsidiaries, MBSC and GROC which are 100% wholly owned by the Company, as well as several indirect subsidiaries, including, Hangingstone Expansion Limited Partnership (“HELP”) and Hangingstone Demo Limited Partnership (“HDLP”), which were formed by GROC and their general partners Hangingstone Expansion General Partner (“HEGP”) and Hangingstone Demo General Partner (“HDGP”), respectively. The units of HELP and HDLP are allocated at 99.99% to GROC for both entities and 0.01% to HEGP and HDGP, respectively. HEGP and HDGP are wholly owned subsidiaries of GROC, along with Greenfire Resources Employment Corporation. Intercompany transactions and balances between the entities are eliminated upon consolidation.

 

Joint arrangements

 

The Company undertakes certain business activities through joint arrangements. Interests in joint arrangements have been classified as joint operations. Joint control exists for contractual arrangements governing the Company’s assets whereby Greenfire has less than 100 per cent working interest, all of the partners have control of the arrangement collectively, and spending on the project requires unanimous consent of all parties that collectively control the arrangement and share the associated risks. A joint operation is established when the Company has rights to the assets and obligations for the liabilities of the arrangement. The Company only recognizes its proportionate share in assets, liabilities, revenues and expenses associated with its joint operations.

 

 

 

Cash and cash equivalents

 

Cash and cash equivalents include cash-on-hand, deposits held with banks, and other short-term highly liquid investments such as bankers’ acceptances, commercial paper, money market deposits or similar instruments, with a maturity of 90 days or less.

 

Foreign currency translation

 

Foreign currency transactions are translated into Canadian Dollars at exchange rates prevailing at the dates of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated into the functional currency at the rate of exchange on the balance sheet date. Any resulting exchange differences are included in the Consolidated Statement of Comprehensive Income (Loss). Nonmonetary assets and liabilities denominated in a foreign currency are measured at historical cost and are translated into the functional currency using the rates of exchange as at the dates of the initial transactions.

 

Operating segments

 

The Company has one reportable operating segment which is made up of its oil sands operations based on geographic location (Athabasca oil sands region of Alberta, Canada), nature of the products sold and integration of facilities and operations. The chief operating decision maker is the President and CEO, who reviews operating results at this level to assess financial performance and make resource allocation decisions. The Company determines its operating segments based on the differences in the nature of operations, products sold, economic characteristics and regulatory environments and management. All of the Company’s non-current assets are located in and revenue is earned in Canada.

 

Financial instruments

 

Financial assets and financial liabilities are recognized in the Company’s balance sheet when the Company becomes a party to the contractual provisions of the instrument.

 

Financial assets and financial liabilities are initially measured at fair value, except for trade receivables that do not have a significant financing component which are measured at transaction price. Transaction costs that are directly attributable to the acquisition or issue of financial assets and financial liabilities (other than financial assets and financial liabilities at fair value through profit or loss) are added to or deducted from the fair value of the financial assets or financial liabilities, as appropriate, on initial recognition. Transaction costs directly attributable to the acquisition of financial assets or financial liabilities at fair value through profit or loss are recognized immediately in profit or loss.

 

Financial assets

 

All regular way purchases or sales of financial assets are recognized and derecognized on a trade date basis. Regular way purchases or sales of financial assets that require delivery of assets within the time frame established by regulation or convention in the marketplace.

 

All recognized financial assets are measured subsequently in their entirety at either amortized cost or fair value, depending on the classification of the financial assets.

 

Financial assets that meet the following conditions are measured subsequently at amortized cost:

 

●

the financial asset is held within a business model whose objective is to hold financial assets in order to collect contractual cash flows; and

 

●

the contractual terms of the financial asset give rise on specified dates to cash flows that are solely payments of principal and interest on the principal amount outstanding.

 

 

 

Financial assets that meet the following conditions are measured subsequently at fair value through other comprehensive income (FVTOCI):

 

●

the financial asset is held within a business model whose objective is achieved by both collecting contractual cash flows and selling the financial assets; and

 

●

the contractual terms of the financial asset give rise on specified dates to cash flows that are solely payments of principal and interest on the principal amount outstanding.

 

By default, all other financial assets are measured subsequently at fair value through profit or loss (FVTPL).

 

Classifications are not changed subsequent to initial recognition, except in limited circumstances.

 

Credit risk arises from the potential that the Company may incur a loss if a counterparty fails to meet its obligations in accordance with agreed terms. Financial assets are assessed at each reporting date to determine whether there is any evidence that credit losses are expected. Credit loss of financial assets is determined by assessing and measuring the expected credit losses of the instruments at each reporting period. The Company measures expected credit losses using a lifetime expected loss allowance model for all trade receivables and contract assets. The credit-loss model groups receivables based on similar credit risk characteristics and the number of days past due in order to estimate and recognize bad debt expenses. When measuring expected credit losses, the Company considers a variety of factors including: evidence of the debtor’s financial condition, history of collections, the term of the receivable and any recent and expected future changes in economic conditions. The Company has not experienced any write-offs of uncollectible receivables; as a result, there are no expected credit losses recognized as at December 31, 2023 (nil for 2022 and 2021).

 

Financial liabilities

 

On initial recognition, financial liabilities are classified at amortized cost or FVTPL. A financial liability is classified as FVTPL if it is classified as held-for-trading, is a derivative or is designated as such on initial recognition. Financial liabilities at FVTPL are measured at fair value and net gains and losses, including any interest expense, are recognized in profit or loss. Other financial liabilities are subsequently measured at amortized cost using the effective interest method. Interest expense and foreign exchange gains and losses are recognized in profit or loss. A financial liability is derecognized when its contractual obligations are discharged or canceled or expire. The Company also derecognizes a financial liability when its terms are modified and the cash flows of the modified liability are substantially different, in which case a new financial liability based on the modified terms is recognized at fair value. On derecognition of a financial liability, the difference between the carrying amount extinguished and the consideration paid (including any non-cash assets transferred or liabilities assumed) is recognized in profit or loss.

 

The Company may, from time to time, enter into certain financial derivative contracts to manage exposure from fluctuating commodity prices, interest rates or foreign exchange rates between the Canadian and US dollar. Such risk management contracts are not used for trading or speculative purposes. The Company has not designated its risk management contracts as effective hedges and has not applied hedge accounting even though the Company considers all financial derivate contracts to be economic hedges, as such all risk management contracts have been recorded at fair value with changes in fair value being recorded through profit or loss.

 

 

 

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company utilizes market data or assumptions that market participants who are independent, knowledgeable and willing and able to transact would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. The Company is able to classify fair value balances based on the observability of these inputs. The authoritative guidance for fair value measurements establishes three levels of the fair value hierarchy, defined as follows:

 

●

Level 1: Unadjusted, quoted prices for identical assets or liabilities in active markets;

 

	●	Level 2: Quoted prices in markets that are not considered to be active or financial instruments for which all significant inputs are observable, either directly or indirectly for substantially the full term of the asset or liability; and

●

Level 3: Significant, unobservable inputs for use when little or no market data exists, requiring a significant degree of judgment.

 

The following table summarizes the method by which the Company measures its financial instruments on the consolidated balance sheets and the corresponding hierarchy rating for their derived fair value estimates:

 

Financial Instrument		Classification & Measurement
Cash and cash equivalents		Amortized cost
Restricted cash		Amortized cost
Accounts receivable		Amortized cost
Risk management contracts		FVTPL
Accounts payable and accrued liabilities		Amortized cost
Warrant liability		FVTPL
Long-term debt		Amortized cost

 

The carrying values of cash and cash equivalents, restricted cash, accounts receivable and accounts payable and accrued liabilities included on the consolidated balance sheets approximates the fair values of the respective assets and liabilities due to the short-term nature of those instruments.

 

The estimated fair value of long-term debt has been determined based on period-end trading prices of long-term borrowings on the secondary market (level 2), for further information please refer to Note 15.

 

The warrants issued were classified as financial liabilities due to a cashless exercise feature and are measured at fair value upon issuance and at each subsequent reporting period with the changes in fair value recorded in the consolidated statement of income (loss). The fair value of these warrants is determined using the Black-Scholes option valuation model.

 

 

 

Common shares are classified as shareholders’ equity. The Company may issue share purchase warrants as a part of debt and/or equity financings. These financial instruments are assessed at the date of issue, based on their underlying terms and conditions, as to whether they are an equity instrument or a derivative financial instrument and if determined to be an equity instrument they are initially recognized in shareholder’s equity at fair value on date of issue. Classifications are not changed after initial recognition and only reassessed when there is a modification in the terms and conditions of the underlying share purchase warrant. Incremental costs directly attributable to the issuance of equity instruments as a deduction from equity, net of any tax effects.

 

Revenue

 

Revenue is measured based on consideration to which the Company expects to be entitled in a contract with a customer. The Company recognizes revenue primarily from the sale of diluted and non- diluted bitumen. Revenue is recognized when its single performance obligation is satisfied. This occurs when the product is delivered, control of the product and title or risk of loss transfers to the customer at contractually specified transfer points. This transfer coincides with title passing to the customer and the customer taking physical possession of the commodity. The Company principally satisfies its single performance obligations at a point in time. Transaction prices are determined at inception of the contract and allocated to the performance obligations identified. Payment is generally received in the following month after the sale has occurred.

 

The Company sells its production pursuant to fixed and variable-priced contracts. The transaction price for variable-priced contracts is based on the commodity price, adjusted for quality, location, or other factors, whereby each component of the pricing formula can be either fixed or variable, depending on the contract terms. Revenue is recognized when a unit of production is delivered to the contract counterparty. The amount of revenue recognized is based on the agreed upon transaction. Royalty expenses are recognized as production occurs.

 

The Company has long-term marketing agreements with a single counterparty (“Sole Petroleum Marketer”), which has exclusive marketing rights over the Company’s production and diluent purchases at Hangingstone Expansion (“Expansion”), until October 2028 and at Hangingstone Demo (“Demo”), until April 2026. Fees paid to the Sole Petroleum Marketer as part of these agreements include marketing, incentive and royalty fees. These fees are expensed as incurred as transportation and marketing expenses. In addition, the Sole Petroleum Marketer provided letters of credit in support of the Company’s long-term transportation commitment until November 2023. As a result of these marketing agreements, the Company is exposed to concentration and credit risks, as all sales are to a single counterparty.

 

 

 

Inventories

 

Inventories consist of crude oil products and warehouse materials and supplies. The carrying value of inventory includes direct and indirect expenditures incurred in the normal course of business in bringing an item or product to its existing condition and location. The Company values inventories at the lower of cost and net realizable value on a weighted average cost basis. Net realizable value is the estimated selling price less applicable selling expenses. If the carrying value exceeds net realizable value, a write-down is recognized. A change in circumstances could result in a reversal of the write-down for the inventory that remains on hand in a subsequent period.

 

Property, plant and equipment (“PP&E”)

 

PP&E is measured at the cost to acquire, less accumulated depletion and depreciation, and net of any impairment losses. The Company begins capitalizing oil exploration costs after the right to explore has been obtained and includes land acquisition costs, geological and geophysical activities, drilling expenditures and costs incurred for the completion and testing of exploration wells. The Company capitalizes all subsequent investments attributable to the development of its oil assets if the expenditures are considered a betterment and provide a future benefit beyond one year. Costs of planned major inspections, overhaul and turnaround activities that maintain PP&E and benefit future years of operations are capitalized and depreciated on a straight-line basis over the period to the next turnaround. Recurring planned maintenance activities performed on shorter intervals are expensed. Replacements of equipment are capitalized when it is probable that future economic benefits will flow to the Company. The Company’s capitalized costs primarily consist of pad construction, drilling activities, completion activities, well equipment, processing facilities, gathering systems and pipelines. Borrowing costs attributable to long-term development projects are also capitalized.

 

Capitalized costs are classified as exploration and evaluation (“E&E”) assets if technical feasibility and commercial viability have not yet been established. Technical feasibility and commercial viability are generally deemed to exist when proved reserves are present and the Company has sanctioned the project for commercial development. Capitalized costs are classified as PP&E assets if they are attributable to the development of oil reserves after technical feasibility and commercial viability have been achieved. Once the technical feasibility and commercial viability of E&E assets have been established, the E&E assets are tested for impairment and reclassified to PP&E. The majority of the Company’s PP&E is depleted using the unit-of-production method relative to the Company’s estimated total recoverable proved plus probable (2P) reserves. The depletion base consists of the historical net book value of capitalized costs, plus the estimated future costs required to develop the Company’s estimated recoverable proved plus probable reserves. The depletion base excludes E&E and the cost of assets that are not yet available for use in the manner intended by Management. Corporate assets and other capitalized costs are depreciated over their estimated useful lives primarily using the declining-balance method.

 

There were no E&E costs as at December 31, 2023, 2022 and 2021.

 

 

 

Provisions and contingent liabilities

 

A provision is recognized if, as a result of a past event, the Company has a present legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation. The amount recognized as a provision is the best estimate of the consideration required to settle the present obligation at the statement of financial position date, taking into account the risks and uncertainties surrounding the obligation. Where a provision is measured using the cash flows estimated to settle the present obligation, its carrying amount is the present value of those cash flows. The Company’s provisions primarily consist of decommissioning liabilities associated with dismantling, decommissioning, and site disturbance remediation activities related to its oil assets.

 

At initial recognition, the Company recognizes a decommissioning asset and corresponding liability on the balance sheet. Decommissioning liabilities are measured at the present value of expected future cash outflows required to settle the obligations at the balance sheet date, using managements best estimate of expenditures required to settle the liability. Decommissioning liabilities are measured based on the estimated future inflation rate and then discounted to net present value using a credit adjusted risk-free discount rate. Any change in the present value, as a result of a change in discount rate or expected future costs, of the estimated obligation is reflected as an adjustment to the provision and the corresponding item of property, plant and equipment. The liability for decommissioning costs is increased each period through the unwinding of the discount, which is included in finance and interest costs in the consolidated statements of comprehensive income (loss). Decommissioning liabilities are remeasured at each reporting period primarily to account for any changes in estimates or discount rates. Actual expenditures incurred to settle the obligations reduce the liability.

 

Contingent liabilities reflect a possible obligation that may arise from past events and the existence of which can only be confirmed by the occurrence or non-occurrence of one or more uncertain future events, not wholly within the control of the Company. Contingent liabilities are not recognized on the balance sheet unless they can be measured reliably and the possibility of an outflow of economic benefits in respect of the contingent obligation is considered probable. Disclosure of contingent liabilities is provided when there is a less than probable, but more than remote, possibility of material loss to the Company.

 

Impairment of non-financial assets

 

For the purpose of estimating the asset’s recoverable amount, PP&E assets are grouped into Cash Generating Units (“CGU”). A CGU is the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets. The Company’s PP&E assets are currently held in two CGUs. Our Hangingstone Expansion and Demo assets represent our two CGU’s at December 31, 2023 and December 31, 2022.

 

PP&E assets are reviewed at each reporting date to determine whether there is any indication of impairment. If indicators of impairment exist, the recoverable amount of the asset or CGU is estimated as the greater of value-in-use (“VIU”) and fair value less costs of disposal (“FVLCOD”). VIU is estimated as the discounted present value of the expected future cash flows from continuing use of the asset or CGU. FVLCOD is the amount that would be realized from the disposition of an asset or CGU in an arm’s length transaction between knowledgeable and willing parties. An impairment loss is recognized in earnings or loss if the carrying amount of the asset or CGU exceeds its estimated recoverable amount.

 

At each reporting period, PP&E, E&E and right-of-use (“ROU”) assets are tested for impairment reversal at the CGU level when facts and circumstances suggest that the recoverable amount of the CGU may exceed the carrying value. Impairment reversal is limited to the carrying amount which would have been recorded had no historical impairment been recorded.

 

Business combinations

 

Business combinations are accounted for using the acquisition method of accounting in which identifiable assets acquired and liabilities assumed in a business combination are recognized and measured at their fair value at the date of the acquisition. If the cost of the acquisition is less than the fair value of the net asset acquired, the difference is recognized in net income (loss). If the cost of the acquisition is greater than the fair value of the net assets acquired, the difference is recognized as goodwill.

 

 

 

 

Leases

 

A contract is, or contains, a lease if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. A lease obligation and corresponding ROU asset are recognized at the commencement of the lease. Lease liabilities are initially measured at the present value of the unavoidable lease payments and discounted using the Company’s incremental borrowing rate when an implicit rate in the lease is not readily available. Interest expense is recognized on the lease obligations using the effective interest rate method. The ROU assets are recognized at the amount of the lease liabilities, adjusted for lease incentives received and initial direct costs, on commencement of the leases. ROU assets are depreciated on a straight-line basis over the lease term. The Company is required to make judgments and assumptions on incremental borrowing rates and lease terms. The carrying balance of the leased assets and lease liabilities, and related interest and depreciation expense, may differ due to changes in market conditions and expected lease terms. Short-term and low value leases have not been included in the measurement of lease liabilities.

 

Income taxes

 

Income tax is comprised of current and deferred tax. Income tax expense (recovery) is recognized in the consolidated statement of comprehensive income (loss) except to the extent that it relates to share capital, in which case it is recognized in equity. Current tax is the expected tax payable (receivable) on the taxable income (loss) for the period, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years.

 

Deferred tax is recognized using the balance sheet method, providing for temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. Deferred tax is not recognized on the initial recognition of assets or liabilities in a transaction that is not a business combination and does not affect profit, other than temporary differences that arise in shareholder’s equity. Deferred tax is measured at the tax rates that are expected to be applied to temporary differences when they reverse, based on the laws that have been enacted or substantively enacted at the reporting date.

 

Deferred tax assets and liabilities are offset on the consolidated balance sheet if there is a legally enforceable right to offset and they relate to income taxes levied by the same tax authority. A deferred tax asset is recognized for unused tax losses, tax credits and deductible temporary differences, to the extent that it is probable that future taxable profits will be available against which they can be utilized. Deferred tax assets are reviewed at each reporting date and are not recognized until such time that it is more likely than not that the related tax benefit will be realized.

 

Stock-based compensation

 

The Company’s stock-based compensation plans for employees consist of performance warrants. The Company’s stock-based compensation plans are accounted for as equity-settled share-based compensation plans. The fair values of the equity settled awards are initially measured at the date of issuance using the Black-Scholes model using an estimated forfeiture rate, volatility, dividend yield, risk-free rate and expected life. The fair value is recorded as stock-based compensation over the vesting period with a corresponding amount reflected in contributed surplus. When performance warrants are exercised, the cash proceeds along with the amount previously recorded as contributed surplus are recorded as share capital.

 

Per share information

 

Basic per share information is calculated using the weighted average number of common shares outstanding during the year. Diluted per share information is calculated using the basic weighted average number of common shares outstanding during the year, adjusted for the number of shares that could have had a dilutive effect on net income during the year had in the-money and outstanding equity compensation units been exercised.

 

 

 

New and amended IFRS Accounting Standards that are effective for the current year

 

In the current year, the Company has applied a number of amendments to IFRS that are mandatorily effective as of January 1, 2023. These adopted amendments are as follows, with their adoption having no significant impact on the Company’s consolidated financial statements.

 

Amendments to IAS 1 – Presentation of Financial Statements

 

The amendments change the requirements in IAS 1 with regard to disclosure of accounting policies. The amendments replace all instances of the term ‘significant accounting policies’ with ‘material accounting policy information’. Accounting policy information is material if, when considered together with other information included in an entity’s financial statements, it can reasonably be expected to influence decisions that the primary users of general purpose financial statements make on the basis of those financial statements.

 

Amendments to IAS 12 – Income Taxes

 

The amendments introduce a further exception from the initial recognition exemption. Under the amendments, an entity does not apply the initial recognition exemption for transactions that give rise to equal taxable and deductible temporary differences. Depending on the applicable tax law, equal taxable and deductible temporary differences may arise on initial recognition of an asset and liability in a transaction that is not a business combination and affects neither accounting profit nor taxable profit.

 

Future accounting pronouncements

 

The Company plans to adopt the following amendments that are effective for annual periods beginning on or after January 1, 2024. The pronouncements will be adopted on their respective effective dates; however, each is not expected to have a material impact on the financial statements.

 

Amendments to IAS 1 – Presentation of Financial Statements - Classification of Liabilities as Current or Non-current

 

The amendments clarify that the classification of liabilities as current or non-current is based on rights that are in existence at the end of the reporting period, specify that classification is unaffected by expectations about whether an entity will exercise its right to defer settlement of a liability, explain that rights are in existence if covenants are complied with at the end of the reporting period, and introduce a definition of ‘settlement’ to make clear that settlement refers to the transfer to the counterparty of cash, equity instruments, other assets or services.

 

Amendments to IAS 1 – Presentation of Financial Statements - Classification of Liabilities as Current or Non-current

 

The amendments specify that only covenants that an entity is required to comply with on or before the end of the reporting period affect the entity’s right to defer settlement of a liability for at least twelve months after the reporting date (and therefore must be considered in assessing the classification of the liability as current or noncurrent). Such covenants affect whether the right exists at the end of the reporting period, even if compliance with the covenant is assessed only after the reporting date (e.g. a covenant based on the entity’s financial position at the reporting date that is assessed for compliance only after the reporting date).

 

4. ACCOUNTING JUDGEMENTS AND ESTIMATES

 

The timely preparation of the consolidated financial statements requires that management make estimates and assumptions and use judgement regarding the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during that period. Such estimates primarily relate to unsettled transactions and events as of the date of the consolidated financial statements. The estimated fair value of financial assets and liabilities are subject to measurement uncertainty. In addition, climate change and the evolving worldwide demand for alternative sources of energy that are not sourced from fossil fuels could result in a change in assumptions used in determining the recoverable amount and could affect the carrying value of the related assets. As these issues advance and regulations change, future financial performance may be impacted. This also presents uncertainty and risk with respect to the Company, its performance and estimates and assumptions. The timing in which global energy markets transition from carbon-based sources to alternative energy or when new regulatory practices may be implemented is highly uncertain.

 

The ongoing geopolitical risks and conflicts have resulted in significant commodity price volatility and increased the level of uncertainty in the Company’s future cash flow. The Company’s gains and losses from its commodity price risk management contracts is likely to be volatile in the current market environment and there is greater emphasis on ensuring operations is uninterrupted and production volumes are delivered to meet these obligations. Additionally, the higher degree of commodity price volatility may increase systemic risk to the global commodities trading and banking businesses, which in turn may increase the Company’s counterparty risk. The Company has not experienced impairment of its receivables and currently has no information that indicates there is elevated risk of impairment in the future.

 

Accordingly, actual results may differ materially from estimated amounts as future confirming events occur. Significant judgements, estimates and assumptions made by management in the preparation of these consolidated financial statements are outlined below.

 

 

 

 

Inventories

 

The Company evaluates the carrying value of its inventory at the lower of cost and net realizable value. The net realizable value is estimated based on current market prices that the Company would expect to receive from the sale of its inventory.

 

Decommissioning liabilities

 

The provision for decommissioning liabilities is based upon numerous assumptions including settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. Actual costs and cash outflows could differ from the estimates as a result of changes in any of the above noted assumptions.

 

Risk management contracts

 

The Company utilizes commodity risk management contracts to manage commodity price risk on oil sales and operating expenses. The Company may also utilize foreign exchange risk management contracts to reduce its exposure to foreign exchange risk associated with its interest payments on its US dollar denominated term debt. The calculated fair value of the risk management contracts relies on external observable market data including quoted forward commodity prices and foreign exchange rates. The resulting fair value estimates may not be indicative of the amounts realized at settlement and as such are subject to measurement uncertainty.

 

Deferred income taxes

 

The provision for income taxes is based on judgments in applying income tax law and estimates on the timing and likelihood of reversal of temporary differences between the accounting and tax bases of assets and liabilities. The provision for income taxes is based on the Company’s interpretation of the tax legislation and regulations which are also subject to change. The Company recognizes a tax provision when a payment to tax authorities is considered more likely than not. A deferred tax asset is recognized for unused tax losses, tax credits and deductible temporary differences, to the extent that it is probable that future taxable profits will be available against which they can be utilized. Income tax filings are subject to audits and reassessments and changes in facts, circumstances and interpretations of the standards which may result in a material increase or decrease in the Company’s provision for income taxes.

 

Long-term debt

 

The measurement of the current portion of long-term debt includes assumptions of expected excess cashflows that are based on management’s estimates.

 

Bitumen reserves

 

The estimation of reserves involves the exercise of judgment. Forecasts are based on engineering data, estimated future prices, expected future rates of production and the cost and timing of future capital expenditures, all of which are subject to many uncertainties and interpretations. The Company expects that over time its reserves estimates will be revised either upward or downward based on updated information such as the results of future drilling and production. Reserves estimates can have a significant impact on net earnings, as they are a key component in the calculation of depletion and for determining potential asset impairment.

 

Impairments

 

CGUs are defined as the lowest grouping of assets that generate identifiable cash inflows that are largely independent of the cash inflows of other assets or groups of assets. The classification of assets into CGUs requires significant judgment and interpretations with respect to the integration between assets, the existence of active markets, external users, shared infrastructures, and the way in which management monitors the Company’s operations. The recoverable amounts of CGUs and individual assets have been determined as the higher of the CGUs or the asset’s fair value less costs of disposal and its value in use. These calculations require the use of estimates and significant assumptions and are subject to changes as new information becomes available including information on future commodity prices, expected production volumes, quantity of proved and probable reserves and discount rates as well as future development and operating expenses. Changes in assumptions used in determining the recoverable amount could affect the carrying value of the related assets and CGUs.

 

 

 

 

Property, plant and equipment

 

Producing assets within PP&E are depleted using the unit-of-production method based on estimated total recoverable proved plus probable reserves and future costs required to develop those reserves. There are several inherent uncertainties associated with estimating reserves. By their nature, these estimates of reserves, including the estimates of future prices and costs, and related future cash flows are subject to measurement uncertainty, and the impact on the consolidated financial statements of future periods could be material.

 

Share purchase warrants

 

The Company has and may, from time to time, issue share purchase warrants (“warrants”) as a part of debt and or equity financings. These warrants may be initially classified as shareholders’ equity or a derivative financial liability based on the terms and conditions of the underlying agreement. The determination of fair value of the share purchase warrants are primarily derived from the fair value of the underlying common shares. The determination of which methodology is most appropriate to determine the fair value of these warrants involves judgement.

 

The estimation of fair value could be determined using the binomial model, the Black Scholes model, the residual method or a relative fair value method depending on the terms of the warrant. The inputs to any of these models require estimates related to share price, share price volatility, interest rates, cash flow multiples, dividend yields, and expected life, all subject to judgment and estimation uncertainty due to both internal and external market factors. Changes in assumptions can impact the fair value estimated for such warrants.

 

5. De-Spac Transaction

 

On September 20, 2023, Greenfire, GRI, MBSC, DE Greenfire Merger Sub Inc. (“DE Merger Sub”) and 2476276 Alberta ULC (“Canadian Merger Sub”), completed a De-Spac Transaction pursuant to a business combination agreement dated December 14, 2022, as amended (the “Business Combination Agreement”) with MBSC. DE Merger Sub and Canadian Merger Sub were incorporated in December 2022 for the purposes of completing the De-Spac Transaction.

 

Pursuant to the De-Spac Transaction (i) Canadian Merger Sub amalgamated with and into GRI pursuant to a statutory plan of arrangement (the “Plan of Arrangement”) under the Business Corporations Act (Alberta), with GRI continuing as the surviving corporation and becoming a direct, wholly-owned subsidiary of Greenfire and (ii) DE Merger Sub merged with and into MBSC pursuant to a Delaware statutory merger (the “Merger) with MBSC continuing as the surviving corporation and becoming a direct, wholly-owned subsidiary of Greenfire.

 

As a result of the De-Spac Transaction, the following occurred:

 

●

Of the GRI 8,937,518 common shares outstanding, 7,996,165 were converted to 43,690,534 common shares of Greenfire and 941,353 were cancelled in exchange for cash consideration of $70.8 million. Cash consideration was comprised of a dividend paid of $59.4 million and $11.4 million for shares repurchased and cancelled by the Company. The $70.8 million cash consideration was recorded as a reduction to retained earnings.

 

●

312,500 outstanding GRI bondholder warrants were exchanged for 3,225,810 GRI common shares of which 2,886,048 were converted to 15,769,183 common shares of Greenfire and 339,245 were cancelled in exchange for cash consideration of $25.5 million. This $25.5 million was recorded as a reduction to retained earnings. In conjunction with the share conversion and cancellation, $43.5 million was reclassified from contributed surplus to share capital ($38.9 million) and retained earnings ($4.6 million).

 

 

 

 

●

Of the 739,912 GRI performance warrants outstanding, 661,971 were converted into 3,617,016 Greenfire performance warrants and 77,941 were cancelled for cash consideration of $4.5 million, which was the fair value of the warrants. The $4.5 million was recorded as a reduction to retained earnings. In conjunction with the cancellation, $1.2 million was reclassified from contributed surplus to retained earnings.

 

●

Greenfire issued an additional 5,000,000 Greenfire warrants to former GRI shareholders, GRI bond warrant holders and performance warrant holders that entitle the holder of each warrant to purchase one common share of Greenfire. The warrants were recorded as a warrant liability on the consolidated balance sheet, see Note 20.

 

●

755,707 MBSC Class A common shares held by MBSC’s public shareholders were converted into 755,707 Greenfire common shares.

 

●

4,250,000 Class B MBSC common shares were converted into 4,250,000 Greenfire common shares.

 

●

2,526,667 MBSC private placements warrants were converted into 2,526,667 Greenfire warrants, which were recorded as a warrant liability on the consolidated balance sheet, see Note 20.

 

●

Concurrent with the execution of the Business Combination Agreement, the Company and MBSC had entered into subscription agreements with certain investors (the “PIPE Investors”) pursuant to which the PIPE Investors agreed to purchase Class A common shares of MBSC at a purchase price of US$10.10 per share. MBSC issued 4,177,091 Class A common shares to the PIPE Investors for proceeds of $56.6 million (US$42.2 million) which were converted into Greenfire common shares at the closing of the De-Spac Transaction.

 

Greenfire has been identified as the acquirer for accounting purposes. As MBSC does not meet the definition of a business under IFRS 3 Business Combinations, the transaction is accounted for pursuant to IFRS 2, Share Based Payment. On closing of the De-Spac Transaction, the Company accounted for the excess of the fair value of Greenfire common shares issued to MBSC shareholders as consideration, over the fair value of MBSC’s identifiable net assets at the date of closing, resulting in $106.5 million (US$79.4 million) being recognized as a listing expense. The fair value of MBSC Class B common shares exchanged for Greenfire common shares was measured at the market price of MBSC’s publicly traded Class A common shares on September 20, 2023, which was US$9.37 per share. The fair value of MBSC Class A common shares exchanged for Greenfire common shares was measured at the market price of MBSC’s publicly traded Class A common shares on September 20, 2023, which was US$9.37 per share. As part of the De-Spac Transaction, Greenfire acquired marketable securities held in trust, prepaid expenses, accrued liabilities, taxable payable, other liabilities, warrant liability and deferred underwriting fees. The following table reconciles the elements of the listing expense:

 

($ thousands)
Total fair value of consideration deemed to have been issued by Greenfire:
4,250,000 MBSC Class B common shares at US$9.37 per common share (US$39.8 million)		$	53,454
755,707 MBSC Class A common shares at US$9.37 per common share (US$7.1 million)		$	9,505
Less the following:
Fair value of identifiable net assets of MBSC
Marketable securities held in Trust Account			10,485
Prepaid expenses and deposits			8
Accounts payable and accrued liabilities			(16,262	)
Warrant liability			(17,960	)
Other liability			(5,369	)
Deferred underwriting fee			(13,422	)
Taxes payable			(1,063	)
Fair value of identifiable net assets of MBSC			(43,583	)
Total listing expense		$	106,542

 

The listing expense is presented in the Consolidated Statement of Comprehensive Income (Loss). For the year ended December 31, 2023, the Company expensed $12.2 million (2022 - $2.8 million) in transaction costs related to the De-Spac.

 

 

 

 

6. ACQUISITIONS

 

Acquisition		Acquisition date		Cash consideration ($thousands)
GHOPCO		April 5, 2021		$	19,721
JACOS		September 17, 2021			346,733
December 31, 2021				$	366,454

 

The Company acquired all the assets of GHOPCO on April 5, 2021 for total cash consideration of $19.7 million. The assets acquired from GHOPCO include oil sands property located in the Hangingstone area of the Athabasca region. The acquisition has been accounted for as a business combination using the acquisition method of accounting. The assets and liabilities assumed are recorded at the estimated fair value on the acquisition date of April 5, 2021.

 

The Company acquired all the issued and outstanding common shares of JACOS on September 17, 2021 for total cash consideration of $346.7 million. The assets acquired from JACOS include various oil sands properties located in the Hangingstone area of the Athabasca region, which contain various working interest participants. One of the properties acquired, which is a developed and producing oil sands property and generates all of the acquired revenues, includes a 75% interest in a joint operation. The acquisition has been accounted for as a business combination using the acquisition method of accounting. The assets and liabilities assumed are recorded at the estimated fair value on the acquisition date of September 17, 2021.

 

Both acquisitions were undertaken to increase the Company’s production and reserve base in the Athabasca region, which is its core focus area.

 

The net assets acquired is based on the estimated fair value of the underlying assets and liabilities acquired as follows:

 

($ thousands)		GHOPCO Amount				JACOS Amount				Total
Net assets acquired:
PP&E		$	159,000			$	851,389			$	1,010,389
Deferred tax asset			-				32,435				32,435
Cash and cash equivalents			2,507				4,412				6,919
Accounts receivable			188				56,671				56,859
Inventories			-				8,992				8,992
Other current assets			1,111				7,846				8,957
Accounts payable and accrued liabilities			(1,847	)			(27,221	)			(29,068	)
Other current liabilities			-				(684	)			(684	)
Decommissioning liabilities			(217	)			(1,740	)			(1,957	)
Deferred tax liability			(32,435	)			-				(32,435	)
Net assets acquired			128,307				932,100				1,060,407
Less: Gain on acquisitions			108,586				585,367				693,953
Total cash purchase consideration		$	19,721			$	346,733			$	366,454

 

There was $10.3 million of acquisition transaction costs incurred by the Company and expensed through earnings in the year ended December 31, 2021.

 

 

 

 

A gain of $108.6 million was recognized on the acquisition of GHOPCO and a gain of $585.4 million was recognized on the acquisition of JACOS. These gains were driven by an increase in oil prices between the offer and closing dates, and optimized views on production and proved and probable reserves. In addition, the market was distressed from low oil prices due to volatility associated with the COVID-19 pandemic at the time of the acquisition.

 

The estimated proved and probable oil reserves and related cash flows were discounted at a rate based on what a market participant would have paid, which was based on market metrics on recent market transactions at the date of acquisition.

 

7. CASH AND CASH EQUIVALENTS

 

As at December 31, 2023, the Company held cash and cash equivalents of $109.5 million (December 31, 2022- $35.4 million). The credit risk associated with the Company’s cash and cash equivalents was considered low as the Company’s balances were held with large Canadian chartered banks.

 

8. RESTRICTED CASH AND CREDIT FACILITY

 

During the year ended December 31, 2023, the Company had a $46.8 million credit facility with its Petroleum Marketer (“Credit Facility”), used for issuing letters of credit related to long-term pipeline transportation agreements. The terms required the Company to contribute cash to a cash-collateral account (“Reserve Account”) over 24 months, starting in October 2021. As at December 31, 2022, the Company held $35.3 million in restricted cash. During the year ended December 31, 2023, the Company contributed $8.0 million in restricted cash to the Reserve Account. On November 8, 2023 $43.3 million of restricted cash was released. This release was due to entering a letter of credit facility guaranteed by Export Development Canada (“EDC Facility”), leading to the termination of both the Credit and Demand Facility (see Note 15).

 

9. INVENTORIES

 

As at December 31 ($ thousands)		2023				2022
Oil inventories		$	6,183			$	7,560
Warehouse materials and supplies			7,680				7,008
Inventories		$	13,863			$	14,568

 

During the year ended December 31, 2023, approximately $567.1 million (December 31, 2022 - $559.8 million. 2021 -$149.8 million) of inventory was recorded within the respective cost components, which are composed of operating expenses, diluent expense, transportation expense and depletion and depreciation in the consolidated statements of comprehensive income (loss). For the years ended December 31, 2023, 2022 and 2021 the Company had no inventory write downs.

 

 

 

 

10. PROPERTY, PLANT AND EQUIPMENT (“PP&E”)

 

($ thousands)		Developed and producing				Right-of-use assets				Corporate assets				Total
Cost
Balance as at December 31, 2020		$	-			$	-			$	-			$	-
Acquisitions			1,010,014				-				375				1,010,389
Expenditures on PP&E			4,507				-				87				4,594
Change in decommissioning liabilities			2,133				-				-				2,133
Balance as at December 31, 2021			1,016,654				-				462				1,017,116
Additions			39,425				-				167				39,592
Right-of-use asset additions			-				969				-				969
Change in decommissioning liabilities			1,237				-				-				1,237
Balance as at December 31, 2022			1,057,316				969				629				1,058,914
Expenditures on PP&E			33,439				-				(11	)			33,428
Right-of-use asset additions			-				12,789				-				12,789
Balance as at December 31, 2023			1,090,755				13,758				618				1,105,131
Accumulated Depletion, Depreciation and Amortization
Balance as at December 31, 2020			-				-				-				-
Depletion and depreciation (1)			27,949				-				47				27,996
Balance as at December 31, 2021			27,949				-				47				27,996
Depletion and depreciation (1)			67,623				60				185				67,868
Balance as at December 31, 2022			95,572				60				232				95,864
Depletion and depreciation (1)			67,580				183				130				67,893
Balance as at December 31, 2023			163,152				243				362				163,757
Net book Value
Balance at December 31, 2022			961,744				909				397				963,050
Balance at December 31, 2023		$	927,603			$	13,515			$	256			$	941,374

 

(1)

As at December 31, 2023 $161 of DD&A was capitalized to inventory (December 31, 2022- $766 and 2021 - 925).

 

No indicators of impairment were identified at December 31, 2023 and 2022, and as such no impairment test was performed.

 

 

 

 

11. LEASE LIABILITIES

 

The Company has recognized the following leases:

 

($ thousands)		2023				2022				2021
Balance, beginning of year		$	963			$	-			$	-
Additions			12,789				970				-
Interest expense			71				19				-
Payments			(99	)			(26	)			-
Balance, end of year		$	13,724			$	963			$	-
Current portion		$	6,002			$	98			$	-
Non-current portion		$	7,722			$	865			$	-

 

The Company’s minimum lease payments are as follows:

 

As at December 31 ($ thousands)		2023				2022
Within 1 year		$	6,002			$	98
Within 2 to 5 years			9,252				581
Later than 5 years			1,015				492
Minimum lease payments			16,269				1,171
Amounts representing finance charges			(2,545	)			(208	)
Present value of net minimum lease payments		$	13,724			$	963

 

During the year ended December 31, 2022, the Company entered into a 7-year term finance lease for new office space, which has been recognized as a right-of-use asset and lease liability at inception in the consolidated balance sheets. During the year ended December 31, 2023, the initial 7-year lease was extended an additional 3 years. The liability was measured at the present value of the remaining lease payments discounted at the Company’s estimated incremental borrowing rate.

 

During the year ended December 31, 2023, the Company entered into a 2-year drilling contract under which the Company has committed to drill 550 days over 2 years. The lease liability was measured at the present value of the day rate payments discounted at the Company’s estimated incremental borrowing rate.

 

 

 

 

12. INCOME TAXES

 

The following table reconciles the expected income tax expense (recovery) calculated at the Canadian statutory rate of 23% (2022 and 2021 – 23%) to the actual income tax expense (recovery).

 

($ thousands)		Year ended December 31, 2023				Year ended December 31, 2022				Year ended December 31, 2021
Income (loss) before taxes		$	(116,285	)		$	44,017			$	661,444
Expected statutory income tax rate			23.00	%			23.00	%			23.00	%
Expected income tax expense (recovery)			(26,746	)			10,124				152,132
Gain on business combination			-				-				(159,609	)
Permanent differences			24,149				7,327				15,401
Unrecognized deferred income tax (asset) liability			21,983				(105,132	)			(7,924	)
Deferred income tax expense (recovery)		$	19,386			$	(87,681	)		$	-

 

($ thousands)		Year ended December 31, 2023				Year ended December 31, 2022				Year ended December 31, 2021
Deferred tax asset (liability) related to:
Oil producing assets related to property, plant & equipment		$	(135,800	)		$	(145,838	)		$	(157,900	)
Resource related pools			10,647				11,478				9,815
Corporate non-capital losses carried forward			285,325				291,078				329,650
Corporate capital tax losses carried forward			2,609				3,211				270
Unrealized loss (gain) on financial derivatives			96				6,211				8,206
Share issuance costs			2,594				683				-
Senior secured debenture			6,793				1,792				(3,052	)
Deferred tax asset not recognized			(103,969	)			(80,934	)			(186,989	)
Deferred tax asset		$	68,295			$	87,681			$	-

 

The Company has approximately $1.8 billion in tax pools and loss carry forwards in the year ended December 31, 2023 (December 31, 2022 – $1.8 billion) including approximately $1.4 billion in non-capital losses available for immediate deduction against future income. The Company’s non-capital losses have an expiry profile between 2033 and 2043.

 

 

 

 

As at December 31, 2023 the Company had the following federal income tax pools, which may be used to reduce taxable income in future years, limited to the applicable rates of utilization:

 

($ thousands)		Rate of Utilization (%)				Amount
Undepreciated capital cost			7-100			$	328,682
Canadian oil and gas property expenditures			10				10,230
Canadian development expenditures			30				34,632
Federal income tax losses carried forward(1) (2)			100				1,376,813
Other(3)			Various				90,103
						$	1,840,460

 

(1)

Federal income tax losses carried forward expire in the following years 2033 - $4.3 million; 2034 - $58.7 million; 2035 - $30.0 million; 2037 - $36.2 million; 2038 - $8.3 million; 2039 - $1,238.0 million; 2042 - $2.9 million; 2043 - $3.6 million.

 

(2)

Provincial income tax losses carry forward is $985.0 million which is lower than the federal income tax losses carried forward due to differences in historical claims at the provincial level.

 

(3)

Other includes $27.6 million in capital losses that have been recognized at the full amount as at December 31, 2023.

 

As at December 31, 2023, the Company has $27.6 million (December 31, 2022 – $2.8 million) of capital losses carried forward that can only be claimed against taxable capital gains.

 

13. DECOMMISSIONING LIABILITIES

 

The Company’s decommissioning liabilities result from net ownership interests in oil assets including well sites, gathering systems and processing facilities. The Company estimates the total undiscounted escalated amount of cash flows required to settle its decommissioning liabilities to be approximately $206.5 million (December 31, 2022- $206.5 million). A credit-adjusted discount rate of 12% (December 31, 2022-12%) and an inflation rate of 2.0% (December 31, 2022- 2.0%) were used to calculate the decommissioning liabilities. A 1.0% change in the credit-adjusted discount rate would impact the discounted value of the decommissioning liabilities by approximately $1.1 million with a corresponding adjustment to PP&E or net income (loss). The decommissioning liabilities are estimated to be settled in periods up to year 2071.

 

A reconciliation of the decommissioning liabilities is provided below:

 

As at December 31 ($ thousands)		2023				2022				2021
Balance, beginning of year		$	7,543			$	5,517			$	-
Initial recognition			-				-				1,957
Change in estimated future costs			-				1,283				3,262
Accretion expense			906				743				298
Balance, end of year		$	8,449			$	7,543			$	5,517

 

 

 

 

14. FINANCIAL INSTRUMENTS, FAIR VALUES AND RISK MANAGEMENT

 

a)

Fair Values of Financial Instruments

 

As at December 31		2023								2022
($ thousands)		Fair Value				Carrying Value				Fair Value				Carrying Value
Financial assets at amortized cost:
Cash			109,475				109,475				35,363				35,363
Restricted cash			50				50				35,313				35,313
Accounts receivable			34,680				34,680				34,308				34,308
Financial liabilities at amortized cost:
Accounts payable and accrued liabilities			59,850				59,850				46,569				46,569
Long-term debt (Note 15)			394,082				396,780				315,718				295,173
Financial liabilities at fair value through profit or loss
Risk management contracts			417				417				27,004				27,004
Warrant liability			18,630				18,630				-				-

 

The fair value of long-term debt was determined based on estimates as at December 31, 2023 and 2022 and is expected to fluctuate given the volatility in the debt markets.

 

Risk management contracts are level 2 in the fair value hierarchy. The estimated fair value of risk management contracts is derived using third-party valuation models which require assumptions concerning the amount and timing of future cash flows and discount rates. Management’s assumptions rely on external observable market data including forward prices for commodities. The observable inputs may be adjusted using certain methods, which include extrapolation to the end of the term of the contract.

 

Warrant liabilities are a level 3 in the fair value hierarchy is calculated using a Black-Scholes calculation.

 

 

 

 

b)

Commodity Risk Management

 

The Company is exposed to commodity price risk on its oil sales due to fluctuations in market prices. The Company continues to execute a consistent risk management program that is primarily designed to reduce the volatility of revenue and cash flow, generate sufficient cash flows to service debt obligations, and fund the Company’s operations. The Company’s risk management liabilities may consist of hedging instruments such as fixed price swaps and option structures, including costless collars on WTI, WCS differentials, condensate differential, natural gas and electricity swaps. The Company does not use financial derivatives for speculative purposes.

 

During the year ended December 31, 2023, the Company’s obligations under its New Notes (see note 15) includes a requirement to implement a 12-month forward commodity price risk management program encompassing not less than 50% of the hydrocarbon output under the proved developed producing reserves (“PDP”) forecast in the Company’s most recent reserves report, as determined by a qualified and independent reserves evaluator. This requirement is assessed on a monthly basis for the duration of time that the New Notes remain outstanding.

 

The Company’s commodity price risk management program does not involve margin accounts that require posting of margin with increased volatility in underlying commodity prices. Financial risk management contracts are measured at fair value, with gains and losses on re-measurement included in the consolidated statements of comprehensive income (loss) in the period in which they arise.

 

The Company’s financial risk management contracts are subject to master netting agreements that create the legal right to settle the instruments on a net basis. The following table summarizes the gross asset and liability positions of the Company’s individual risk management contracts that are offset in the consolidated balance sheets:

 

As at December 31		2023								2022
($ thousands)		Asset				Liability				Asset				Liability
Gross amount		$	-			$	(417	)		$	21,375			$	(48,379	)
Amount offset			-				-				(21,375	)			21,375
Risk Management contracts		$	-			$	(417	)		$	-			$	(27,004	)

 

The following table summarizes the financial commodity risk management gains and losses:

 

($ thousands)		Year ended December 31, 2023				Year ended December 31, 2022				Year ended December 31, 2021
Realized gain (loss) on risk management contracts		$	(10,182	)		$	(122,408	)		$	(3,614	)
Unrealized gain (loss) on risk management contracts			26,587				930				(35,677	)
Gain (loss) on risk management contracts		$	16,405			$	(121,478	)		$	(39,291	)

 

As at December 31, 2023, the following financial commodity risk management contracts were in place:

 

		WTI- Costless Collar												Natural Gas- Fixed Price Swaps
Term		Volume (Bbls)				Put Strike Price (US$/Bbl)				Call Strike Price ($US/Bbl)				Volume (GJ)				Swap Price ($/GJ)
Q1 2024			877,968			$	60.00			$	77.00				455,000			$	2.97
Q2 2024			877,968			$	60.00			$	74.55				-				-
Q3 2024			887,800			$	62.00			$	92.32				-				-
Q4 2024			887,800			$	59.46			$	87.58				-				-

 

 

 

 

Subsequent to December 31, 2023, Greenfire terminated the above WTI Costless Collar risk management contracts and entered into the following financial commodity risk management contracts:

 

		WTI- Costless Collar												WTI Fixed Price Swaps
Term		Volume (Bbls)				Put Strike Price (US$/Bbl)				Call Strike Price ($US/Bbl)				Volume (bbls/d)				Swap Price (US$/bbl))
Jan – Dec 2024			-				-				-				11,500			$	70.94
Q1 2025			640,700			$	57.97			$	84.22				-				-

 

The following table illustrates the potential impact of changes in commodity prices on the Company’s net income, before tax, based on the financial risk management contracts in place at December 31, 2023:

 

As at December 31, 2023		Change in WTI								Change in Natural Gas
($ thousands)		Increase of $5.00/bbl				Decrease of $5.00/bbl				Increase of $1.00/GJ				Decrease of $1.00/GJ
Increase (decrease) to fair value of commodity risk management contracts			-				-			$	455			$	(455	)

 

The Company’s commodity risk management contracts are held with two large reputable financial institution. As a result, the Company concluded that credit risk associated with its commodity risk management contracts is low.

 

c)

Credit Risk

 

As at December 31 ($ thousands)		2023				2022
Trade receivables		$	22,452			$	22,428
Joint interest receivables			12,228				11,880
Accounts receivable		$	34,680			$	34,308

 

Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its contractual obligations and arises principally from the Company’s accounts receivable. The Company is primarily exposed to credit risk from receivables associated with its oil sales. The Company manages its credit risk exposure by transacting with high-quality credit worthy counterparties and monitoring credit worthiness and/or credit ratings on an ongoing basis. Trade receivables from oil sales are generally collected on 25th day of the month following production. Joint interest receivables are typically collected within one to three months of the invoice being issued. The Company has not previously experienced any material credit losses on the collection of accounts receivable.

 

At December 31, 2023, and December 31, 2022 the Company was exposed to concentration risk associated with its outstanding trade receivables and joint interest receivables balances. Of the Company’s trade receivables at December 31, 2023, 100% was receivable from a single company each (December 31, 2022- 100% was receivable from two companies at approximately 64% and 36% each). At December 31, 2023, 100% of the Company’s joint interest receivables were held by a single company (December 31, 2022- 100% by a single company). Maximum exposure to credit risk is represented by the carrying amount of accounts receivable on the balance sheet. Subsequent to December 31, 2023, the Company has received $4.4 million from its joint interest partner, with the remaining outstanding balance expected to be paid within a reasonable time, as a result there are no material financial assets that the Company considers past due and no accounts have been written off.

 

 

 

 

d)

Liquidity Risk

 

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due. The Company’s objective in managing liquidity risk is to maintain sufficient available reserves to meet its financial obligations at any point in time. The Company expects to achieve this objective through prudent capital spending, an active commodity risk management program and through strategies such as continuously monitoring forecast and actual cash flows from operating, financing and investing activities, and available credit facilities. Management believes that future cash flows generated from these sources will be adequate to settle Greenfire’s financial liabilities.

 

The following table details the Company’s contractual maturities of its financial liabilities at December 31, 2023, and December 31. 2022:

 

		Year ended December 31, 2023								Year ended December 31, 2022
($ thousands)		Less than one year				Greater than one year				Less than one year				Greater than one year
Accounts payable and accrued liabilities		$	59,850			$	-			$	46,569			$	-
Risk management contracts(1)			417				-				27,004				-
Lease liabilities(1)			6,002				7,722				98				1,075
Long-term debt(2)			44,321				332,029				63,250				231,921
Total financial liabilities		$	110,590			$	339,751			$	136,921			$	232,996

 

(1)

Amounts represent the expected undiscounted cash payments.

 

(2)

Amounts represent undiscounted principal only and exclude accrued interest and transaction costs.

 

As at December 31, 2023 all material financial liabilities are current except for the long-term portion of the New Notes (Notes 15 and 21) and drilling contract (Note 11). In addition, the Company has provisions and other liabilities as disclosed in Note 20. The Company’s future unrecognized commitments are disclosed in Note 18.

 

e)

Foreign Currency Risk Management

 

Foreign currency risk is the risk that a variation in exchange rates between the Canadian dollar and foreign currencies will affect the fair value or future cash flows of the Corporation’s financial assets or liabilities. The Corporation has U.S. dollar denominated long-term debt as described in Note 15. As of December 31, 2023, a 10% change to the value of the Canadian dollar relative to the US dollar would result in a foreign exchange gain (loss) of approximately $39.7 million (December 31, 2022 - $29.3 million, December 31, 2021 - $39.6 million).

 

f)

Interest Rate Risk

 

Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. The Company is exposed to interest rate risk related to borrowings drawn under the Senior Credit Facility, as the interest charged on the credit facility fluctuates with floating interest rates, Currently no amounts are drawn on the Senior Credit Facility. The New Notes and letters of credit issued are subject to fixed interest rates and are not exposed to changes in interest rates.

 

15. LONG-TERM DEBT

 

Senior Secured Notes

 

On September 20, 2023 in conjunction with the closing of the De-Spac Transaction and the issuance of the New Notes as described below, GRI redeemed the outstanding balance of $294.6 million (US$217.9 million) on the US$312.5 million 12% senior notes that were issued on August 12, 2021 (the “2025 Notes”) at a redemption premium of 106.5%. The total premium paid as a result of the early redemption was $19.2 million (US$14.2 million) plus accrued interest of $3.4 million (US$2.5 million). Unamortized debt costs of $42.1 million were also expensed in conjunction with the extinguishment of the debt.

 

On September 20, 2023, Greenfire issued US$300 million of senior secured notes (the “New Notes”). The New Notes bear interest at the fixed rate of 12.00% per annum, payable semi-annually on April 1 and October 1 of each year commencing on April 1, 2024, and mature on October 1, 2028. The New Notes are secured by a first priority lien on substantially all the assets of the Company and its wholly owned subsidiaries. Subject to certain exceptions and qualifications, the indenture governing the New Notes contain certain covenants that limited the Company’s ability to, among other things, incur additional indebtedness, pay dividends, redeem stock, make certain restricted payments, and dispose and transfers of assets. The indenture governing the New Notes contains minimum hedging requirements of 50% of the forward 12 calendar month PDP forecasted production as prepared to the Canadian standard using NI 51-101 until principal debt is less than US$100 million and limit capital expenditures to CAD$100 million annually until the principal outstanding is less than US$150 million. The New Notes are not subject to any financial covenants.

 

 

 

 

Under the indenture governing the New Notes, the Company is required to redeem the New Notes at 105% of the principal amount plus accrued and unpaid interest with 75% of Excess Cash Flow (as defined in the New Notes Indenture) every six-months, with the first payment due by August 15, 2024. If consolidated indebtedness is less than US$150 million, the required redemption is reduced to 25% of Excess Cash Flow to be paid for every six-month period until the principal owing on the New Notes is US$100 million

 

The Company is exposed to foreign exchange rate fluctuations on the principal value and interest payments in respect of its New Notes. As of December 31, 2023, a 10% change to the value of the Canadian dollar relative to the US dollar would result in a foreign exchange gain (loss) of approximately $39.7 million (December 31, 2022 - $29.3 million, December 31, 2021 - $39.6 million).

 

The New Notes are subject to fixed interest rates and are not exposed to changes in interest rates.

 

As at December 31, 2023, the carrying value of the Company’s long-term debt was $376.48 million and the fair value was $394.1 million (December 31, 2022 carrying value – $254.4 million, fair value – $315.7 million).

 

As at December 31, 2023 the Company was compliant with all covenants.

 

As at December 31 ($ thousands)		2023				2022
US dollar denominated debt:
Redeemed 12.00% senior notes issued at 96.5% of par (US$217.9 million at December 31, 2022)(1)		$	-			$	295,173
Unamortized debt discount and debt issue costs			-				(40,765	)
New 12.00% senior notes issued at 98% of par (USD$300 million at December 31, 2023)(1)			396,780				-
Unamortized debt discount and debt issue costs			(20,430	)			-
Total term debt		$	376,350			$	254,408
Current portion of long-term debt			44,321				63,250
Long-term debt		$	332,029			$	191,158

 

(1)	The U.S. dollar denominated debt was translated into Canadian dollars as at period end exchange rates.

 

Greenfire may redeem some or all of the New Notes after October 1, 2025, at 100% of the principal amount of the notes being redeemed, plus accrued and unpaid interest plus a “make whole” premium, as set out in the table below. In addition, at any time before October 1, 2025, the Company may redeem up to 40% of the aggregate principal amount of the notes using the net proceeds from certain equity issuances as a redemption price equal to 112% of the principal amount plus accrued and unpaid interest.

 

The following table discloses the redemption amount including the “make whole” premium on redemption of the New Notes:

 

		US$300 million 12.00% senior notes
On or after October 1, 2025 to October 1, 2026			106.0
On or after October 1, 2026 to October 1, 2027			103.0
On or after October 1, 2027			100.0

 

 

 

 

Senior Credit Facility

 

On September 20, 2023, Greenfire entered into a reserve-based credit facility (the “Senior Credit Facility”) comprised of an operating facility and a syndicate facility. Total credit available under the Facility is $50 million comprising of $20 million operating facility and $30 million syndicated facility.

 

The Senior Credit Facility is a committed facility available on a revolving basis until September 20, 2024, at which point in time it may be extended at the lender’s option. If the revolving period is not extended, the undrawn portion of the facility will be cancelled and any amounts outstanding would be repayable at the end of the non-revolving term, being September 30, 2025. The Revolving Facility is subject to a semi-annual borrowing base review, occurring in May and November of each year. The borrowing base is determined based on the lender’s evaluation of the Company’s petroleum and natural gas reserves and their commodity price outlook at the time of each renewal.

 

The Senior Credit Facility is secured by a first priority security interest on substantially all the assets of the Corporation and is senior in priority to the New Notes. The Senior Credit Facility contains certain covenants that limit the Company’s ability to, among other things, incur additional indebtedness, create or permit liens to exist, make certain restricted payments, and dispose of or transfer assets. The Senior Credit Facility is not subject to any financial covenants.

 

As at December 31, 2023, amounts borrowed under the Senior Credit Facility bear interest at a floating rate based on the applicable Canadian prime rate, US base rate, secured overnight financing rate or bankers’ acceptance rate, plus a margin of 2.75% to 6.25% based on Debt to EBITDA ratio. A standby fee on the undrawn portion of the Senior Credit Facility ranges from 0.6875% to 1.5625% based on Debt to EBITDA ratio. As at December 31, 2023, the Company had no amounts drawn under the Senior Credit Facility.

 

Letter of Credit Facility

 

During the fourth quarter of 2023, Greenfire entered into an unsecured $55 million letter of credit facility with a Canadian bank that is supported by a performance security guarantee from the EDC Facility. The EDC Facility is available on a demand basis and letters of credit issued under this facility incur an issuance and performance guarantee fee of 4.25%. As at December 31, 2023, the Company had $54.3 million in letters of credit outstanding under the Letter of Credit Facility.

 

16. REVENUE FROM CONTRACTS WITH CUSTOMERS

 

The Company’s revenue from contracts with customers consists of diluted and non-diluted bitumen sales.

 

Greenfire’s oil sales include blended bitumen sales from the Expansion Asset and the Demo Asset as well as non-diluted bitumen sales trucked from the Demo Asset. At the Demo Asset, each barrel can be transported to several locations, including both pipeline and rail sales points, depending on the economics of each option at the time of sale. Greenfire’s oil sales are generally sold under variable price contracts and are based on the commodity market price, adjusted for quality, location or other factors. Greenfire is required to deliver nominated volumes of oil to the contract counterparty. Each barrel equivalent of commodity delivered is considered to be a distinct performance obligation. The amount of revenue recognized is based on the agreed transaction price and is recognized as performance obligations are satisfied, therefore resulting in revenue recognition in the same month as delivery. Revenues are typically collected on the 25th day of the month following production.

 

($ thousands)		Year ended December 31, 2023				Year ended December 31, 2022				Year ended December 31, 2021
Diluted bitumen sales		$	652,812			$	890,400			$	212,225
Bitumen sales			23,158				108,449				58,449
Oil sales		$	675,970			$	998,849			$	270,674

 

 

 

 

17. FINANCING AND INTEREST

 

($ thousands)		Year ended December 31, 2023				Year ended December 31, 2022				Year ended December 31, 2021
Accretion on long-term debt		$	106,435			$	74,176			$	22,186
Other and cash interest			2,873				2,155				1,926
Accretion on decommissioning liabilities			906				743				298
Financing and interest expense		$	110,214			$	77,074			$	25,050

 

The total interest and finance expense of $108.3 million during the year ended December 31, 2023, included $42.1 million of accelerated unamortized debt related costs and $19.2 million of debt redemption premiums on the redemption of the 2025 Notes.

 

18. COMMITMENTS AND CONTINGENCIES

 

The following table summarizes the Company’s estimated future unrecognized commitments associated with firm transportation agreements as at December 31, 2023:

  

($ thousands)		Remaining 2024				2025				2026				2027				2028				Beyond 2028				Total
Transportation			31,880				30,561				28,956				29,044				29,170				203,198				352,809
Total		$	31,880			$	30,561			$	28,956			$	29,044			$	29,170			$	203,198			$	352,809

 

19. SHARE CAPITAL AND WARRANTS

 

Share capital

 

As at December 31, 2023 the Company’s authorized share capital consists of an unlimited number of common shares without a nominal or par value. The following table along with note 5 summarizes the changes to the Company’s common share capital:

 

		Number of shares				Amount($000’s)
Shares outstanding
Balance, December 31, 2021 and 2022			1			$	15
Issuance of new common shares per De-Spac Transaction			43,690,533				-
Issuance for exercise of bond warrants			15,769,183				38,911
Issuance to MBSC shareholders – Class A and Class B			5,005,707				62,959
Issuance of new common shares for PIPE investment			4,177,091				56,630
Balance, December 31, 2023			68,642,515			$	158,515

 

Bondholder warrants

 

As at December 31, 2022, GFI had 312,500 bondholder warrants outstanding which entitled the holders of these warrants, in aggregate, the right to purchase 25% of GFI’s issued and outstanding common shares commencing October 18, 2021 at $0.01 per shares. As at December 31, 2022, the bondholders had the right to acquire 2,983,866 common shares of GRI at $0.01 per share based on an exchange ratio of 9.55.

 

On September 20, 2023, with the closing of the De-Spac Transaction the 312,500 outstanding bondholder warrants were exchanged into 3,225,810 GRI common shares of which 2,886,565 were exchanged for 15,769,183 common shares of Greenfire and 339,245 were cancelled in exchange for cash consideration of $25.5 million.

 

As at December 31, 2023 there were no bondholder warrants remaining.

 

 

 

 

Per share amounts

 

The Company uses the treasury stock method to determine the dilutive effect of performance and bondholder warrants. Under this method, only “in-the-money” dilutive instruments impact the calculation of diluted income (loss) per share. Net income (loss) per share was calculated using the historical weighted average shares outstanding, scaled by the applicable exchange ratio following the completion of the De-Spac Transaction.

 

The following table summarizes the Company’s basic and diluted net income (loss) per share:

 

		Year ended December 31, 2023				Year ended December 31, 2022				Year ended December 31, 2021
Weighted average shares outstanding- basic			54,425,083				48,911,099				42,609,296
Dilutive effect of bond and performance warrants			-				21,019,068				5,488,834
Weighted average shares outstanding- diluted			54,425,083				69,930,167				48,098,130
Basic $ per share		$	(2.49	)		$	2.69			$	15.52
Diluted $ per share		$	(2.49	)		$	1.88			$	13.75

 

In computing the diluted net loss per share for the year ended December 31, 2023, the Company excluded the effect of 7,526,667 New Greenfire Warrants and 3,617,016 Performance Warrants as their effect in anti-dilutive. (December 31, 2022 and 2021 no warrants were excluded).

 

Performance warrants

 

In February 2022, the Company implemented a warrant plan (“Performance Warrants”) as part of the Company’s long-term incentive plan for employees and service providers. These Performance Warrants had both performance and time vesting criteria before there is the ability to exercise the option to purchase one common share of the Company for each Performance Warrant. On September 20, 2023 with the closing of the De-Spac Transaction there were 739,912 GRI performance warrants outstanding, 661,971 were converted into 3,617,016 Greenfire performance warrants and 77,941 were cancelled for cash consideration of $4.5 million.

 

The table below summarizes the outstanding warrants as if the warrant exchange ratio used to exchange GRI common shares into Greenfire common shares had occurred on January 1, 2022 and equates to the total common shares issuable to performance warrant holders:

 

		Year ended December 31, 2023								Year ended December 31, 2022
		Number of Warrants				Weighted Average Exercise Price $US				Number of Warrants				Weighted Average Exercise Price $US
Performance Warrants outstanding
Balance, beginning of period			3,895,449			$	2.89				-			$	-
Performance warrants issued			186,257				8.35				4,159,546				2.91
Performance warrants forfeited			(38,820	)			3.34				(264,097	)			3.13
Performance warrants cancelled			(425,870	)			3.15				-				-
Balance, end of period			3,617,016			$	3.15				3,895,449			$	2.89
Common shares issuable on exchange			3,617,016				-				3,895,449				-

 

 

 

 

The fair market value of the performance warrants was $11.0 million on the date of issuance. The exchange of the GRI performance warrants to Greenfire performance warrants did not result in an increase to the fair value of the warrants, therefore no additional expense was recorded. The fair value of each performance warrant was estimated on its grant date using the Black Scholes Merton valuation model with the following assumptions:

 

		2023 Assumptions				2022 Assumptions
Average risk-free interest rate			4.2	%			1.46	%
Average expected dividend yield			-				-
Average expected volatility1			70	%			60	%
Average expected life (years)			2-5				3-5

 

1	Expected volatility has been based on historical share volatility of similar market participants

 

The performance warrants expire 10 years after the issuance date. On September 20, 2023, with the closing of the De-Spac Transaction, all outstanding performance warrants vested and became exercisable. As a result, the remaining unrecognized fair market value of the performance warrants was immediately recorded as stock-based compensation, and a total of $9.2 million was expensed. For the year ended December 31, 2023, the Company recorded $9.8 million (2022-$1.2 million, 2021 -$nil) of stock-based compensation related to the performance warrant plan.

 

20. WARRANT LIABILITY

 

On September 20, 2023, Greenfire issued 5,000,000 warrants to GRI common shareholders, bond warrant holders and performance warrant holders (the “New Greenfire Warrants”). The New Greenfire Warrants expire 5 years after issuance and entitle the holder of each warrant to purchase one common share of Greenfire at a price of US$11.50. Greenfire, can at its option, require the holder of the New Greenfire Warrants to exercise on a cashless basis. The 5,000,000 New Greenfire Warrants issued to the former GRI common shareholders and bondholders are to be treated as a derivative financial liability in accordance with IFRS 9 – Financial Instruments and were measured at fair value in accordance with IFRS 13 – Fair Value Measurement. These New Greenfire Warrants had a fair value of $35.6 million at the date of issuance and were recorded as a liability with a corresponding amount booked to retained earnings. The New Greenfire Warrants will be reassessed at the end of each reporting period with subsequent changes in fair value being recognized through the statement of comprehensive income (loss).

 

In addition, Greenfire as part of the De-Spac Transaction assumed and exchanged 2,526,667 MBSC Class B Private Warrants for 2,526,667 New Greenfire Warrants. The New Greenfire Warrants issued to the MBSC Class B warrant holders were deemed to be an exchange of two financial liabilities at fair value. The fair value of the MBSC Class B Private Warrants was $18.0 million. Both sets of warrants have an exercise price of US$11.50 with both underlying securities trading at or valued at a similar price. As both sets of warrants are deemed to be economically equivalent, no gain or loss was recorded on the exchange. The exchanged warrants will be reassessed at the end of each reporting period with subsequent changes in fair value being recognized through the statement of comprehensive income (loss).

 

On December 31, 2023, the 7,526,667 outstanding New Greenfire Warrants were revalued based on the closing share price of US$4.86 per common share of Greenfire During the year ended December 31, 2023, the fair value of the warrant liability decreased by $35.0 million. The following table reconciles the warrant liability.

 

		Year ended December 31, 2023								Year ended December 31, 2022
($ thousands)		Number of Warrants				Amount				Number of Warrants				Amount
Balance, beginning of year			-			$	-				-			$	-
Warrants issued			5,000,000				35,644				-				-
MBSC warrants converted			2,526,667				17,959
Change in fair value			-				(34,973	)			-				-
Balance, end of period			7,526,667			$	18,630				-			$	-
Common shares issuable on exercise			7,526,667				-				-				-

 

 

 

 

The fair value of each warrant was estimated on its grant date using the Black Scholes Merton valuation model with the following assumptions:

 

		2023 Assumptions
Average risk-free interest rate			4.2	%
Average expected dividend yield			-
Average expected volatility (1)			70	%
Average expected life (years)			5

 

(1)	Expected volatility has been based on historical share volatility of similar market participants

 

21. CAPITAL MANAGEMENT

 

The Company’s net managed capital consists primarily of cash and cash equivalents, long-term debt and shareholders’ equity. The current priorities for managing liquidity risk include managing working capital to ensure interest and debt repayment, and to fund the Company’s operations and the capital program. In the current commodity price environment and in conjunction with the Company’s commodity price risk management program, management believes its current capital resources and cash flow will allow the Company to meet its current and future obligations over the next 12 months. Capital expenditures and debt repayment are expected to be funded by cash-on-hand and out of cash flow. The Company’s capital structure consists of the following:

 

As at December 31 ($ thousands)		2023				2022
Face value of term debt (Note 15)		$	396,780			$	295,173
Shareholders’ equity			712,940				837,771
Working capital, excluding current portion of term debt, warrant liability and risk management contracts			(96,899	)			(76,860	)
Net managed capital		$	1,012,821			$	1,056,084

 

Net managed capital is not a standardized measure and may not be comparable with the calculation of similar measures by other companies.

 

 

 

 

22. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

 

The components of accounts payable and accrued liabilities were:

 

As at December 31 ($ thousands)		2023				2022
Trade payables		$	6,303			$	3,367
Accrued payables			35,994				30,401
Accrued employee annual incentive plans			4,435				4,463
Accrued interest payable			13,118				8,338
Accounts payable and accrued liabilities		$	59,850			$	46,569

 

23. RELATED PARTY TRANSACTIONS

 

The Company’s related parties primarily consist of key management personnel. The Company considers directors and officers of Greenfire Resources Ltd. as key management personnel.

 

($ thousands)		Year ended December 31, 2023				Year ended December 31, 2022				Year ended December 31, 2021
Salaries, benefits, and director fees		$	3,808			$	1,978			$	873

 

24. SUPPLEMENTAL CASH FLOW INFORMATION

 

The following table reconciles the net changes in non-cash working capital and other liabilities from the consolidated balance sheet to the consolidated statement of cash flows:

 

($ thousands)		Year ended December 31, 2023				Year ended December 31, 2022				Year ended December 31, 2021
Change in accounts receivable		$	(372	)		$	9,654			$	(43,962	)
Change in inventories			705				1,349				(15,917	)
Change in prepaid expenses and deposits			(1,763	)			6,537				(10,512	)
Change in accounts payable and accrued liabilities			13,048				(10,859	)			57,367
Working capital acquired (note 6)			-				-				41,856
			11,618				6,681				28,832
Other items impacting change in non-cash working capital: Unrealized foreign exchange loss in accounts payable			(93	)			(652	)			-
			11,525				6,029				28,832
Related to operating activities			25,513				3,570				(6,910	)
Related to investing activities (accrued additions to PP&E)			(13,988	)			2,459				35,742
Net change in non-cash working capital		$	11,525			$	6,029			$	28,832
Cash interest paid (included in operating activities)		$	(39,955	)		$	(51,129	)		$	(1,926	)
Cash interest received (included in operating activities)		$	2,976			$	620			$	21

 

 

Supplementary information for Greenfire Resources Ltd. – oil and gas (unaudited)

 

SUPPLEMENTARY INFORMATION FOR GREENFIRE RESOURCES LTD. – OIL AND GAS 

 

SUPPLEMENTARY OIL AND GAS INFORMATION FOR THE FISCAL YEAR ENDED
DECEMBER 31, 2023 (UNAUDITED)

 

This supplementary crude oil and natural information is provided in accordance with the United States Financial Accounting Standards Board (“FASB”) Topic 932- “Extractive Activities- Oil and Gas” and where applicable, financial information is prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”).

 

The information set out herein is unaudited and is presented on a consolidated basis net of the Company’s share. For the purposes of determining proved oil and natural gas reserves under SEC requirements as at December 31, 2023, 2022 and 2021, the Company used the 12-month average price, defined by the SEC as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period.

 

Reserve Information

 

The Company’s 2023, 2022 and 2021 year-end reserves evaluations were conducted by McDaniel & Associates Consultants Ltd. (“McDaniel”) with an effective date of December 31, 2023, December 31, 2022 and December 31, 2021, respectively. McDaniel evaluated 100% of the Company’s reserves located in Alberta, Canada.

 

Proved reserves.    Proved reserves are those quantities of bitumen, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

 

Developed reserves.    Developed reserves are reserves that can be expected to be recovered:

 

i.

Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

 

ii.

Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

 

Undeveloped reserves.    Undeveloped reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

 

The Company cautions users of this information as the process of estimating reserves is subject to uncertainty. The reserves are based on economic and operating conditions. Therefore, changes can be made to future assessments as a result of a number of factors, which can include new technology, changing economic conditions and development activity. Net reserves presented in this section represent the Company’s working interest share of the gross remaining reserves, after deduction of any crown, freehold and overriding royalties. Such royalties are subject to change by legislation or regulation and can also vary depending on production rates, selling prices and timing of initial production.

 

 

Summary of Corporate Reserves

 

The following tables are summaries of the Company’s estimated proved reserves at December 31, 2023, 2022, and 2021 as reconciled between the three years:

 

Constant Prices and Costs (unaudited)		Bitumen(2) (mbbl)				Barrels of Oil Equivalent (mboe)
Net Proved Developed and Proved Undeveloped Reserves(1)
December 31, 2020
Developed			0				0
Undeveloped			0				0
Total – December 31, 2020			0				0
Extensions & Discoveries			0				0
Improved Recovery			0				0
Technical Revisions			0				0
Acquisitions			172,580				172,580
Dispositions			0.0				0.0
Production – 2021			(2,820	)			(2,820	)
December 31, 2021			169,760				169,760

 

(1)

Numbers may not add due to rounding.

(2)

Bitumen, as defined by the SEC, “is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis.” Under this definition, all of the Company’s thermal and primary heavy crude oil reserves have been classified as bitumen.

 

Constant Prices and Costs (unaudited)		Bitumen(2) (mbbl)				Barrels of Oil Equivalent (mboe)
Net Proved Developed and Proved Undeveloped Reserves(1)
December 31, 2021
Developed			37,792				37,792
Undeveloped			131,968				131,968
Total – December 31, 2021			169,720				169,720
Extensions & Discoveries			0.0				0.0
Improved Recovery			0.0				0.0
Technical Revisions			(16,431	)			(16,431	)
Acquisitions			0.0				0.0
Dispositions			0.0				0.0
Production – 2022			(7,117	)			(7,117	)
December 31, 2022			146,212				146,212

 

(1)

Numbers may not add due to rounding.

(2)

Bitumen, as defined by the SEC, “is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis.” Under this definition, all of the Company’s thermal and primary heavy crude oil reserves have been classified as bitumen.

 

 

Constant Prices and Costs (unaudited)		Bitumen(2) (mbbl)				Barrels of Oil Equivalent (mboe)
Net Proved Developed and Proved Undeveloped Reserves(1)
December 31, 2022
Developed			30,440				30,440
Undeveloped			115,773				115,773
Total – December 31, 2022			146,212				146,212
Extensions & Discoveries			5,297				5,297
Improved Recovery			0				0
Technical Revisions			7,282				7,282
Acquisitions			0				0
Dispositions			0				0
Production – 2023			(6,212	)			(6,212	)
December 31, 2023			152,579				152,579
December 31, 2023
Developed			27,598				27,598
Undeveloped			124,981				124,981
Total – December 31, 2023			152,579				152,579

 

(1)

Numbers may not add due to rounding.

(2)

Bitumen, as defined by the SEC, “is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis.” Under this definition, all of the Company’s thermal and primary heavy crude oil reserves have been classified as bitumen.

 

In 2021, the Company’s production, net of royalties, was 2.8 MMBOE after the acquisitions of the Demo Asset and Expansion Asset.

 

In 2021, the Company’s proved reserves increased by 172.6 MMBOE, which was the result of the acquisitions of the Demo Asset and Expansion Asset.

 

In 2022, the Company’s production, net of royalties, was 7.1 MMBOE.

 

In 2022, the Company’s proved reserves decreased by 16.4 MMBOE, which was the result of:

 

(i)

a decrease of 26.2 MMBOE resulting from higher prices used in 2022 causing higher royalty rates, which reduces net reserves volumes, offset by

 

(ii)

revisions, other than price, of 9.8 MMBOE, approximately 15% of which (1.5 MMBOE) attributed to positive performance revisions at the producing pads and approximately 85% of which (8.3 MMBOE) attributed to increased operating costs (non-energy and updates in the TIER regulatory costs) and capital costs during the reporting period (as capital costs increase, net reserves volumes increases because royalties decrease).

 

 

In 2023, the Company’s production, net of royalties, was 6.2 MMBOE.

 

In 2023, the Company’s proved reserves increased by 6.4 MMBOE, which was the result of:

 

(i)

increase of 5.3 MMBOE from extensions due to the inclusion of additional undeveloped wells at the Demo property that were not previously included in reserves.

 

(ii)

increase of 9.3 MMBOE due to lower realized prices causing lower royalty rates, which increases net reserves volumes, offset by

 

(iii)

revisions other than price of -2.0 MMBOE, where -2.7 MMBOE attributed to negative performance revisions at the producing pads and changes to the undeveloped development plan were partially offset by +0.7 MMBOE due to increased operating costs and capital costs during the reporting period (as capital and operating costs increase, net reserves volumes increases because royalties decrease).

 

Steam generation represents a large proportion of the Company’s capital and operating costs. Therefore, development plans anticipate that, in order to make the most efficient use of the Company’s steam generating and oil treating facilities, the drilling and steaming of new wells would take place over 30 years. Development of the Company’s proved undeveloped reserves will take place in an orderly manner as additional well pairs are drilled to use available steam when existing well pairs reach the end of their steam injection phase. The forecasted production of the Company’s proved reserves extends approximately 31 years. This approach means that it will take longer than five years to develop most of the Company’s proved undeveloped reserves.

 

Proved reserves are estimated based on the average first-day-of-month prices during the 12-month period for the respective year.

 

The average prices used to compute proved reserves at December 31, 2023 were WTI: $78.21 per bbl, WCS: CAD$79.89 per bbl, Edmonton C5+ CAD$104.16 per bbl, Henry Hub: $2.59 per MMBtu, and AECO Spot: CAD$2.84 per MMBtu.

 

The average prices used to compute proved reserves at December 31, 2022 were WTI: $94.14 per bbl, WCS: CAD$97.68 per bbl, Edmonton C5+ CAD$120.59 per bbl, Henry Hub: $6.25 per MMBtu, and AECO Spot: CAD$5.62 per MMBtu.

 

The average prices used to compute proved reserves at December 31, 2021 were WTI: $66.55 per bbl, WCS: CAD$66.43 per bbl, Edmonton C5+ CAD$83.96 per bbl, Henry Hub: $3.64 per MMBtu, and AECO Spot: CAD$3.57 per MMBtu. Prices for bitumen, oil, diluent and natural gas are inherently volatile.

 

Changes to the Company’s proved undeveloped reserves during 2021 are summarized in the table below:

 

		Barrels of Oil Equivalent (mboe)(1)
December 31, 2020			0
Extensions and discoveries			0
Technical revisions			0
Acquisitions			131,968.2
Conversions to developed			0
December 31, 2021			131,968.2

 

(1)

Numbers may not add due to rounding.

 

Changes to the Company’s proved undeveloped reserves during 2022 are summarized in the table below:

 

		Barrels of Oil Equivalent (mboe)(1)
December 31, 2021			131,968
Extensions and discoveries			0
Technical revisions			(16,196	)
Conversions to developed			0
December 31, 2022			115,773

 

(1)

Numbers may not add due to rounding.

 

 

Changes to the Company’s proved undeveloped reserves during 2023 are summarized in the table below:

 

		Barrels of Oil Equivalent (mboe)(1)
December 31, 2022			115,773
Extensions and discoveries			5,297
Technical revisions			6,998
Conversions to developed			(3,087	)
December 31, 2023			124,981

 

(1)

Numbers may not add due to rounding.

 

In 2021, the Company’s proved undeveloped reserves increased by approximately 132 MMBOE, which was the result of the acquisitions of the Demo Asset and the Expansion Assets.

 

In 2022, the Company’s proved undeveloped reserves decreased by 16.2 MMBOE, which was the result of:

 

(i)

A decrease of 23.8 MMBOE resulting from higher prices used in 2022 causing higher royalty rates, which reduces net reserves volumes, offset by

 

(ii)

Positive revisions, other than price, of 7.6 MMBOE attributed to increased operating costs (non-energy and updates in the TIER regulatory costs) and capital costs during the reporting period (as capital costs increase, net reserves volumes increases because royalties decrease).

 

In 2023, the Company’s proved undeveloped reserves increased by 9.2 MMBOE, which was the result of:

 

(i)

increase of 5.3 MMBOE from extensions due to the inclusion of additional undeveloped wells at the Demo property that were not previously included in reserves

 

(ii)

increase of 8.5 MMBOE resulting from lower realized prices causing lower royalty rates, offset by

 

(iii)

revisions other than price of -1.5 MMBOE, where -2.4 MMBOE attributed to negative performance revisions at the producing pads and changes to the undeveloped development plan were partially offset by +0.9 MMBOE due to increased operating costs and capital costs during the reporting period (as capital and operating costs increase, net reserves volumes increases because royalties decrease).

 

(iv)

movement of 3.1 MMBOE from undeveloped into proven developed producing due to eight Refill wells drilled in 2023

 

No changes to the reserve booking have been made as a result of the removal of uneconomic or undeveloped locations due to changes in a previously adopted development plan.

 

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves

 

The future net revenues and net present values presented in this summary were calculated using constant prices and costs based on the average first-day-of-the-month petroleum product prices for the 12 months of 2023, 2022 and 2021, with no inflation of operating or capital costs, and were presented in Canadian dollars. All of the future net revenues and net present value estimates in this summary are presented before income taxes. A 10% discount factor was applied to the future net cash flows. Future development costs used in the calculation of future net revenue includes the costs to settle the asset retirement obligations for each period presented. The future net revenues presented in this summary may not necessarily represent the fair market value of the reserves estimates. The Company’s management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves, and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated. The prescribed discount rate of 10% may not appropriately reflect interest rates.

 

 

The following table summarizes the standardized measure of discounted future net cash flows relating to proved reserves, for the years ended December 31, 2023, 2022 and 2021:

 

		For the year ended December 31,
(CAD$ in millions) (unaudited)		2023				2022				2021
Future cash inflows			8,072				10,276				7,168
Future production costs			2,771				3,491				2,448
Future development/abandonment costs			1,208				1,274				1,144
Deferred income taxes			774				1,053				361
Future net cash flows			3,320				4,458				3,215
Less 10% annual discount factor			(1,728	)			(2,361	)			(1,778	)
Standardized measure of discounted future net cash flows			1,592				2,097				1,437

 

The following table reconciles the changes in standardized measure of future net cash flows discounted at 10% per year relating to proved bitumen, heavy oil and natural gas producing reserves:

 

		For the year ended December 31,
(CAD$ in millions) (unaudited)		2023				2022				2021
Standardized measure of discounted future net cash flows at beginning of year			2,097				1,437				0
Oil and gas sales during period net of production costs and royalties(1)			(459	)			(726	)			(179	)
Changes due to prices(2)			(567	)			1,175				0
Development costs during the period(3)			33				39				5
Changes in forecast development costs(4)			(27	)			(149	)			(401	)
Changes resulting from extensions, infills and improved recovery(5)			94				0				0
Changes resulting from discoveries(2)			0				0				0
Changes resulting from acquisition of reserves(5)			0				0				1,486
Changes resulting from disposition of reserves(5)			0				0				0
Accretion of discount(6)			240				149				0
Net change in income tax(7)			253				(682	)			(209	)
Changes resulting from other changes and technical reserves revisions plus effects on timing(8)			(71	)			864				735
Standardized measure of discounted future net cash flows at end of year			1,592				2,097				1,437

 

(1)

Company actual before income taxes, excluding general and administrative expenses.

(2)

The impact of changes in prices and other economic factors on future net revenue.

(3)

Actual capital expenditures relating to the exploration, development and production of oil and gas reserves.

(4)

The change in forecast development costs.

(5)

End of period net present value of the related reserves.

(6)

Estimated as 10 percent of the beginning of period net present value.

(7)

The difference between forecast income taxes at beginning of period and the actual taxes for the period plus forecast income taxes at the end of the period

(8)

Includes changes due to revised production profiles, development timing, operating costs, royalty rates and actual prices received versus forecast, etc.

 

 

The following table summarizes net capitalized costs relating to petroleum and natural gas producing activities, as at December 31, 2023, 2022 and 2021:

 

		As of December 31,
(CAD$ in millions) (unaudited)		2023				2022				2021
Proved oil and gas properties			1,091				1,058				1,017
Unproved oil and gas properties			0				0				0
Total capitalized costs			1,091				1,058				1,017
Accumulated depletion and depreciation			(163	)			(96	)			(28	)
Net Capitalized Costs			928				962				989

 

The following table summarizes costs incurred in petroleum and natural gas property acquisitions, exploration and development activities, for the years ended December 31, 2023, 2022 and 2021:

		For the year ended December 31,
(CAD$ in millions) (unaudited)		2023				2022				2021
Property acquisition (disposition) costs
Proved oil and gas properties – acquisitions			0.0				0				1,010
Proved oil and gas properties – dispositions			0.0				0				0
Unproved oil and gas properties			0.0				0				0
Exploration costs			0.0				0				0
Development costs			33				41				7
Total Expenditures			33				41				1,017

 

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Board of Directors of Greenfire Resources Inc.

 

Opinion on the Financial Statements

 

We have audited the accompanying balance sheets of Japan Canada Oil Sands Limited (the “Company”) as at September 17, 2021, December 31, 2020 and January 1, 2020, the related statements of comprehensive income (loss), shareholders’ equity (deficit), and cash flows, for the period ended September 17, 2021 and the year ended December 31, 2020, 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 at September 17, 2021, December 31, 2020 and January 1, 2020, and its financial performance and its cash flows for the period ended September 17, 2021 and year ended December 31, 2020, in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

 

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 internal 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/ Deloitte LLP

 

Chartered Professional Accountants

Calgary, Canada

April 21, 2023

 

We have served as the Company’s auditor since 2022.

 

 

Japan Canada Oil Sands Limited
Balance Sheets

 

As at ($CAD 000’s)		note		September 17, 2021				December 31, 2020				January 1, 2020
Assets
Current assets
Cash and cash equivalents		6		$	4,412			$	46,743			$	159,591
Restricted cash					500				—				672
Accounts receivable		7			56,517				29,113				30,565
Inventories		8			7,438				7,440				18,550
Due from related parties					—				6				18
Prepaid expenses and deposits					4,285				2,594				2,446
					73,152				85,896				211,842
Non-current assets
Property, plant and equipment		9			298,457				292,855				640,757
Right of use asset		10			487				841				1,372
					298,944				293,696				642,129
Total assets				$	372,096			$	379,592			$	853,971
Liabilities
Current liabilities
Accounts payable and accrued liabilities					27,149				51,838				56,260
Current portion of long-term debt		16			—				76,392				77,928
Current portion of lease liability		10			521				544				493
Due to related parties					—				1,007				1,009
					27,670				129,781				135,690
Non-current liabilities
Long-term debt		16			—				608,249				698,144
Long-term lease liability		10			—				335				879
Decommissioning obligation		12			7,920				7,728				7,147
					7,920				616,312				706,170
Total liabilities					35,590				746,093				841,860
Shareholders’ equity
Share capital		22			1,609,045				1,010,871				1,010,871
Retained earnings (deficit)					(1,272,539	)			(1,377,372	)			(998,760	)
					336,506				(366,501	)			12,111
Total equity and liabilities				$	372,096			$	379,592			$	853,971

 

Commitments and contingencies (note 19)

Subsequent events (note 23)

 

See accompanying notes to the financial statements

 

These Financial Statements were approved by the Board of Directors.

 

Robert Logan, Director				David Phung, Director

 

 

Japan Canada Oil Sands Limited
Statements of Comprehensive Income (Loss)

 

($CAD 000’s, except per share amounts)		note		Period ended September 17, 2021				Year ended December 31, 2020
Revenues
Oil sales				$	382,635			$	279,248
Royalties					(7,178	)			(2,019	)
Oil sales, net of royalties					375,457				277,229
Interest income		13			43				925
Other income		13			985				1,684
					376,485				279,838
Expenses
Diluent expense		17			171,174				158,272
Transportation and marketing		17			27,853				39,368
Operating expenses		17			56,479				67,409
General and administrative					6,793				5,680
Financing and interest		18			11,154				21,602
Depletion and depreciation		9,10			78,267				108,379
Impairment (recovery)		9			(73,252	)			270,000
Exploration					(383	)			3,352
Foreign exchange gain					(6,433	)			(15,612	)
Total expenses					271,652				658,450
Net income (loss) and comprehensive income (loss)				$	104,833			$	(378,612	)
Net income (loss) per share
Basic		22		$	3.46			$	(12.50	)
Diluted		22		$	3.46			$	(12.50	)

 

See accompanying notes to the financial statements

 

 

Japan Canada Oil Sands Limited
Statements of Changes in Shareholders’ Equity (Deficit)

 

($CAD 000’s)		note		Period Ended September 17, 2021				Year Ended December 31, 2020
Share capital
Beginning balance		22		$	1,010,871			$	1,010,871
Capital contributions		22			645,674				—
Return of capital					(47,500	)
Ending balance					1,609,045				1,010,871
Deficit
Beginning balance					(1,377,372	)			(998,760	)
Net income (loss)					104,833				(378,612	)
Ending balance					(1,272,539	)			(1,377,372	)
Total shareholders’ equity				$	336,506			$	(366,501	)

 

See accompanying notes to the financial statements

 

 

Japan Canada Oil Sands Limited
Statements of Cash Flows

 

($CAD 000’s)		note		Period Ended September 17, 2021				Year ended December 31, 2020
Operating activities
Net income (loss)				$	104,833			$	(378,612	)
Items not affecting cash:
Depletion and depreciation		9,10			78,267				108,379
Impairment (recovery)		9			(73,252	)			270,000
Inventory markdown					(226	)			(438	)
Accretion		12			320				444
Unrealized foreign exchange gain					(6,238	)			(15,512	)
Amortization of debt issuance costs		16,18			2,887				321
Decommissioning obligation settlements					(52	)			(31	)
Other non-cash items					(76	)			(50	)
Change in non-cash working capital		21			(61,929	)			8,812
Cash generated from (used) by operating activities					44,534				(6,687	)
Financing activities
Repayment of long-term debt		16			(341,432	)			(79,086	)
Lease liability payments		10			(358	)			(493	)
Capital contributions		22			304,570				—
Return of capital					(47,500	)
Cash used by financing activities					(84,720	)			(79,579	)
Investing activities
Property, plant and equipment expenditures		9			(9,757	)			(27,478	)
Change in non-cash working capital (accrued additions to PP&E)					6,866				(2,622	)
Cash used in investing activities					(2,891	)			(30,100	)
Exchange rate impact on cash and cash equivalents held in foreign currency					1,246				2,846
Change in cash and cash equivalents		6			(41,831	)			(113,520	)
Cash and cash equivalents, beginning		6			46,743				160,263
Cash and cash equivalents, end		6		$	4,912			$	46,743

 

See accompanying notes to the financial statements

 

 

Japan Canada Oil Sands Limited
Notes to the Financial Statements

 

1.

CORPORATE INFORMATION

 

Japan Canada Oil Sands Limited (“JACOS” or the “Company”) is a corporation incorporated under the Canada Business Corporations Act. The Company is engaged in the exploration, development and operation of oil and gas properties, and focuses primarily in the Athabasca oil sands region of Alberta. The Company’s corporate head office was located at 2300, 639 5 Ave SW, Calgary, Alberta T2P 0M9. The Company was a wholly-owned subsidiary of Canada Oil Sands Co., Ltd. (“CANOS” or the “Parent Company”). The overall ownership structure of JACOS and related parties of JACOS is as follows:

 

Company Name		Relationship to JACOS		Purpose
Japan Petroleum Exploration Co Ltd (Japex)		Parent of CANOS		Debt guarantee fees
Canada Oil Sands Ltd (CANOS)		Parent of JACOS		Expat services and plant and equipment reimbursements
Japex Canada Ltd		Subsidiary of Japex		Administrative cost reimbursements for corporate filings
JGI Inc.		Subsidiary of Japex		Geological exploration services
Japex Montney Ltd		Subsidiary of Japex		Administrative cost reimbursement for payroll services

 

2.

BASIS OF PRESENTATION AND STATEMENT OF COMPLIANCE

 

The financial statements represent the Company’s initial presentation of its results and financial position under International Financial Reporting Standards as issued by the International Accounting Standards Board (“IFRS”). The financial statements were prepared in accordance with IFRS as issued by the IASB.

 

A summary of Company’s significant accounting policies under IFRS is presented in Note 3. These policies have been retrospectively and consistently applied except where specific exemptions permitted an alternative treatment upon transition to IFRS in accordance with IFRS 1 as disclosed in Note 5.

 

An explanation of how the transition to IFRS has affected the reported balance sheet, changes to shareholders’ equity, income and comprehensive income (loss), and cash flows of the Company is provided in Note 5.

 

On September 17, 2021 the Company was acquired by Greenfire Resources Inc. As a result, these financial statements present the Company’s financial position at September 17, 2021 and the results of its financial performance and changes in its financial position for the period then ended. Comparative information presented in these financial statements is for the twelve-month fiscal year which ended December 31, 2020. As such, certain amounts in the financial statements are not entirely comparable.

 

In these financial statements, all dollars are expressed in Canadian dollars, which is the Company’s functional currency, unless otherwise indicated. These financial statements have been prepared on a historical cost basis, except for certain financial instruments which are measured at their estimated fair value.

 

These financial statements were approved by the Board of Directors on April 19, 2023.

 

3.

SIGNIFICANT ACCOUNTING POLICIES

 

Joint arrangements

 

The Company undertakes certain business activities through joint arrangements. Interests in joint arrangements have been classified as joint operations. A joint operation is established when the Company has rights to the assets and obligations for the liabilities of the arrangement. The Company only recognizes its proportionate share in assets, liabilities, revenues and expenses associated with its joint operations.

 

 

Japan Canada Oil Sands Limited
Notes to the Financial Statements

 

3.

SIGNIFICANT ACCOUNTING POLICIES (cont.)

 

Foreign currency translation

 

Foreign currency transactions are translated into Canadian Dollars at exchange rates prevailing at the dates of the transaction. Monetary assets and liabilities that are denominated in foreign currencies are translated to the functional currency using the exchange rate as of the balance sheet date. The resulting translation differences arising from monetary assets and liabilities denominated in foreign currencies are included in the Statement of Comprehensive Income (Loss).

 

Operating segments

 

The Company determines its operating segments based on the differences in the nature of operations, products sold, economic characteristics and regulatory environments and management. As the Company only has operations in the Athabasca region, the Company has determined that the Company’s assets, liabilities and operating results for the development and production of bitumen from the oil sands located in the Athabasca region is the Company’s only operating segment.

 

Financial instruments and fair value measurement

 

Fair value is the price that would be received when selling an asset or paid to transfer a liability in an orderly transaction between market participants in its principal or most advantageous market at the measurement date.

 

All assets and liabilities for which fair value is measured or disclosed in the financial statements are further categorized using a three-level hierarchy that reflects the significance of the lowest level of inputs used in determining fair value:

 

●

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

 

●

Level 2 — Pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value, and volatility factors, which can be substantially observed or corroborated in the marketplace.

 

●

Level 3 — Valuations in this level are those with inputs for the asset or liability that are not based on observable market data.

 

At each reporting date, the Company determines whether transfers have occurred between levels in the hierarchy by reassessing the level of classification for each financial asset and financial liability measured or disclosed at fair value in the financial statements based on the lowest level of input that is significant to the fair value measurement as a whole. Assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy.

 

The following table summarizes the method by which the Company measures its financial instruments on the balance sheets and the corresponding hierarchy rating for their derived fair value estimates:

 

Financial Instrument		Fair Value Hierarchy		Classification & Measurement
Cash and cash equivalents		Level 1		Amortized cost
Restricted cash		Level 1		Amortized cost
Accounts receivable		Level 2		Amortized cost
Due from related parties		Level 2		Amortized cost
Accounts payable		Level 2		Amortized cost
Due to related parties		Level 2		Amortized cost
Long-term bank loans payable		Level 2		Amortized cost

 

 

Japan Canada Oil Sands Limited
Notes to the Financial Statements

 

3.

SIGNIFICANT ACCOUNTING POLICIES (cont.)

 

Financial Instruments

 

Classification and Measurement of Financial Instruments

 

JACOS’s financial assets and financial liabilities are classified into two categories: Amortized Cost and Fair Value through Profit and Loss (“FVTPL”). The classification of financial assets is determined by their context in the Company’s business model and by the characteristics of the financial asset’s contractual cash flows. The Company does not classify any of its financial instruments as Fair Value through Other Comprehensive Income.

 

Financial assets and financial liabilities are measured at fair value on initial recognition, which is typically the transaction price, unless a financial instrument contains a significant financing component. Subsequent measurement is dependent on the financial instrument’s classification.

 

●

Amortized Cost Cash and cash equivalents, accounts receivable, prepaid expenses, accounts payable and accrued liabilities, and long-term debt are measured at amortized cost. The contractual cash flows received from the financial assets are solely payments of principal and interest and are held within a business model whose objective is to collect the contractual cash flows. The financial assets and financial liabilities are subsequently measured at amortized cost using the effective interest method.

 

●

FVTPL Risk management contracts, all of which are derivatives, are measured initially at FVTPL and are subsequently measured at fair value with changes in fair value immediately charged to the statements of comprehensive income (the “statements of income”). The Company did not have any risk management contracts as at September 17, 2021, December 31, 2020 or January 1, 2020.

 

Impairment of Financial Assets

 

Impairment of financial assets carried at amortized cost is determined by measuring the assets’ expected credit loss (“ECL”). Accounts receivable are due within one year or less; therefore, these financial assets are not considered to have a significant financing component and a lifetime ECL is measured at the date of initial recognition of the accounts receivable. ECL allowances have not been recognized for cash and cash equivalents due to the virtual certainty associated with their collection.

 

The ECL pertaining to accounts receivable is assessed at initial recognition and this provision is re-assessed at each reporting date. ECLs are a probability-weighted estimate of possible default events related to the financial asset (over the lifetime or within 12 months after the reporting period, as applicable) and are measured as the difference between the present value of the cash flows due to JACOS and the cash flows the Company expects to receive, including cash flows expected from collateral and other credit enhancements that are a part of contractual terms. The carrying amounts of financial assets are reduced by the amount of the ECL through an allowance account and losses are recognized as an impairment of financial assets in the statements of income.

 

Based on industry experience, the Company considers its commodity sales and joint interest accounts receivable to be in default when the receivable is more than 90 days past due. Once the Company has pursued collection activities and it has been determined that the incremental cost of pursuing collection outweighs the benefits, JACOS derecognizes the gross carrying amount of the financial asset and the associated allowance from the balance sheets.

 

Derecognition of Financial Liabilities

 

A financial liability is derecognized when the obligation under the liability is discharged or canceled or expires. If an amendment to a contract or agreement comprises a substantial modification, JACOS will derecognize the existing financial liability and recognize a new financial liability, with the difference recognized as a gain or loss in the statements of income. If the modification results in the derecognition of a liability any associated fees are recognized as part of the gain or loss. If the modification is not deemed to be substantial, any associated fees adjust the liability’s carrying amount and are amortized over the remaining term.

 

 

Japan Canada Oil Sands Limited
Notes to the Financial Statements

 

3.

SIGNIFICANT ACCOUNTING POLICIES (cont.)

 

Derivative instruments and hedging activities

 

The Company periodically enters into derivative contracts to manage its exposure to commodity price and foreign exchange risks. These derivative contracts, which are generally placed with major financial institutions, may take the form of forward contracts, futures contracts, swaps, or options. The reference prices, upon which the commodity derivative contracts are based, reflect various market indices that have a high degree of historical correlation with actual prices received by the Company for its oil production.

 

Derivatives are initially recognized at fair value on the date a contract is entered into and are subsequently re-measured at their fair value. The Company’s derivative instruments, while providing effective economic hedges, are not designated as hedges for accounting purposes. Changes in the fair value of any derivatives that are not designated as hedges for accounting purposes are recognized within net income (loss) and comprehensive income (loss) consistent with the underlying nature and purpose of the derivative instruments.

 

Revenue

 

Revenue is measured based on consideration to which the Company expects to be entitled in a contract with a customer. The Company recognizes revenue primarily from the sale of diluted bitumen. Revenue is recognized when performance obligations are satisfied. This occurs when the product is delivered, control of the product and title or risk of loss transfers to the customer. Transaction prices are determined at inception of the contract and allocated to the performance obligations identified. Payment is generally received in the following one month to three months after the sale has occurred.

 

The Company sells its production pursuant to fixed and variable-priced contracts. The transaction price for variable-priced contracts is based on the commodity price, adjusted for quality, location, or other factors, whereby each component of the pricing formula can be either fixed or variable, depending on the contract terms. Revenue is recognized when a unit of production is delivered to the contract counterparty. The amount of revenue recognized is based on the agreed upon transaction.

 

Royalty expenses are recognized as production occurs.

 

Interest income

 

Interest income on cash and cash equivalents and restricted cash, is recorded as earned. For outstanding investments that mature in future periods, income is accrued up to the end of the applicable reporting period based on the terms and conditions of the individual instruments.

 

Cash and cash equivalents

 

The Company considers all cash on hand, depository accounts held by banks, money market accounts and highly liquid investments with an original maturity of three months or less to be cash equivalents. The types of financial instruments in which the Company currently invests in include term deposits and guaranteed investment certificates.

 

Accounts receivable

 

Accounts receivable are amounts due from customers from the rendering of services or sale of goods in the ordinary course of business. Accounts receivables are classified as current assets if payment is due within one year or less. Accounts receivables are recognized initially at fair value and subsequently measured at amortized cost.

 

Inventories

 

Inventories consist of crude oil products and warehouse materials and supplies. The carrying value of inventory includes direct and indirect expenditures incurred in the normal course of business in bringing an item or product to its existing condition and location. The Company values inventories at the lower of cost and net realizable value on a weighted average cost basis. Net realizable value is the estimated selling price less applicable selling expenses. If the carrying value exceeds net realizable value, a write-down is recognized. A change in circumstances could result in a reversal of the write-down for the inventory that remains on hand in a subsequent period.

 

 

Japan Canada Oil Sands Limited
Notes to the Financial Statements

 

3.

SIGNIFICANT ACCOUNTING POLICIES (cont.)

 

Property, plant and equipment (“PP&E”)

 

PP&E is measured at cost to acquire, less accumulated depletion and depreciation, and net of any impairment losses. The Company begins capitalizing oil exploration costs after the right to explore has been obtained and includes land acquisition costs, geological and geophysical activities, drilling expenditures and costs incurred for the completion and testing of exploration wells. The Company capitalizes all subsequent investments attributable to the development of its oil assets if the expenditures are considered a betterment and provide a future benefit beyond one year. The Company’s capitalized costs primarily consist of pad construction, drilling activities, completion activities, well equipment, processing facilities, gathering systems and pipelines. Borrowing costs attributable to long-term development projects are also capitalized.

 

Capitalized costs are classified as exploration and evaluation (“E&E”) assets if technical feasibility and commercial viability have not yet been established. Technical feasibility and commercial viability are generally deemed to exist when proved reserves are present and the Company has sanctioned the project for commercial development. Capitalized costs are classified as PP&E assets if they are attributable to the development of oil reserves after technical feasibility and commercial viability have been achieved. Once the technical feasibility and commercial viability of E&E assets have been established, the E&E assets are tested for impairment and reclassified to PP&E. The majority of the Company’s PP&E is depleted using the unit-of-production method relative to the Company’s estimated total recoverable proved plus probable (“2P”) reserves. The depletion base consists of the historical net book value of capitalized costs, plus the estimated future costs required to develop the Company’s estimated recoverable proved plus probable reserves. The depletion base excludes E&E and the cost of assets that are not yet available for use in the manner intended by Management. Corporate assets and other capitalized costs are depreciated over their estimated useful lives primarily using the declining-balance method.

 

There were no E&E costs as at September 17, 2021, December 31, 2020 or January 1, 2020.

 

Provisions and contingent liabilities

 

A provision is recognized if, as a result of a past event, the Company has a present legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation. The amount recognized as a provision is the best estimate of the consideration required to settle the present obligation at the statement of financial position date, taking into account the risks and uncertainties surrounding the obligation. Where a provision is measured using the cash flows estimated to settle the present obligation, its carrying amount is the present value of those cash flows. The Company’s provisions primarily consist of decommissioning liabilities associated with dismantling, decommissioning, and site disturbance remediation activities related to its oil assets.

 

At initial recognition, the Company recognizes a decommissioning asset and corresponding liability on the balance sheet. Decommissioning obligations are measured at the present value of expected future cash outflows required to settle the obligations. Decommissioning liabilities are measured based on the approximate historical inflation rate and then discounted to net present value using a credit adjusted risk-free discount rate. Any change in the present value, as a result of a change in discount rate or expected future costs, of the estimated obligation is reflected as an adjustment to the provision and the corresponding item of property, plant and equipment. The liability for decommissioning costs is increased each period through the unwinding of the discount, which is included in finance and interest costs in the statements of comprehensive income (loss). Decommissioning liabilities are remeasured at each reporting period primarily to account for any changes in estimates or discount rates. Actual expenditures incurred to settle the obligations reduce the liability.

 

 

Japan Canada Oil Sands Limited
Notes to the Financial Statements

 

3.

SIGNIFICANT ACCOUNTING POLICIES (cont.)

 

Contingent liabilities reflect a possible obligation that may arise from past events and the existence of which can only be confirmed by the occurrence or non-occurrence of one or more uncertain future events, not wholly within the control of the Company. Contingent liabilities are not recognized on the balance sheet unless they can be measured reliably and the possibility of an outflow of economic benefits in respect of the contingent obligation is considered probable. Disclosure of contingent liabilities is provided when there is a less than probable, but more than remote, possibility of material loss to the Company.

 

Impairment of non-financial assets

 

For the purpose of estimating the asset’s recoverable amount, PP&E assets are grouped into cash generating units (“CGU”s). A CGU is the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets. The Company’s PP&E assets are currently held in one CGU.

 

PP&E assets are reviewed at each reporting date to determine whether there is any indication of impairment. If indicators of impairment exist, the recoverable amount of the asset or CGU is estimated as the greater of value-in-use (“VIU”) and fair value less costs of disposal (“FVLCOD”). VIU is estimated as the discounted present value of the expected future cash flows from continuing use of the asset or CGU. FVLCOD is the amount that would be realized from the disposition of an asset or CGU in an arm’s length transaction between knowledgeable and willing parties. An impairment loss is recognized in earnings or loss if the carrying amount of the asset or CGU exceeds its estimated recoverable amount.

 

At each reporting period, PP&E, E&E and right-of-use assets are tested for impairment reversal at the CGU level when there are indicators that a previous impairment recorded has been reversed. Impairment reversal is limited to the carrying amount which would have been recorded had no historical impairment been recorded.

 

Leases

 

A contract is, or contains, a lease if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. A lease obligation and corresponding right-of-use asset are recognized at the commencement of the lease. Lease liabilities are initially measured at the present value of the unavoidable lease payments and discounted using the Company’s incremental borrowing rate when an implicit rate in the lease is not readily available. Interest expense is recognized on the lease obligations using the effective interest rate method. The right-of-use assets are recognized at the amount of the lease liabilities, adjusted for lease incentives received and initial direct costs, on commencement of the leases. Right-of-use assets are depreciated on a straight-line basis over the lease term. The Company is required to make judgments and assumptions on incremental borrowing rates and lease terms. The carrying balance of the leased assets and lease liabilities, and related interest and depreciation expense, may differ due to changes in market conditions and expected lease terms. Short-term and low value leases have not been included in the measurement of lease liabilities.

 

Income taxes

 

Income tax is comprised of current and deferred tax. Income tax expense is recognized in the statement of income (loss) except to the extent that it relates to share capital, in which case it is recognized in equity. Current tax is the expected tax payable (receivable) on the taxable income (loss) for the period, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years.

 

Deferred tax is recognized using the balance sheet method, providing for temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. Deferred tax is not recognized on the initial recognition of assets or liabilities in a transaction that is not a business combination and does not affect profit, other than temporary differences that arise in shareholder’s equity. Deferred tax is measured at the tax rates that are expected to be applied to temporary differences when they reverse, based on the laws that have been enacted or substantively enacted at the reporting date.

 

 

Japan Canada Oil Sands Limited
Notes to the Financial Statements

 

3.

SIGNIFICANT ACCOUNTING POLICIES (cont.)

 

Deferred tax assets and liabilities are offset on the balance sheet if there is a legally enforceable right to offset and they relate to income taxes levied by the same tax authority. A deferred tax asset is recognized to the extent that it is probable that future taxable profits will be available against which the temporary differences can be utilized. Deferred tax assets are reviewed at each reporting date and are not recognized until such time that it is more likely than not that the related tax benefit will be realized.

 

Per share information

 

Basic per share information is calculated using the weighted average number of common shares outstanding during the year. Diluted per share information is calculated using the basic weighted average number of common shares outstanding during the year, as the Company did not have shares which could have had a dilutive effect on net income during the year.

 

Investment tax credits

 

Investment tax credits are deducted from the related expenditures when there is reasonable assurance that they are recoverable.

 

Transportation

 

In order to facilitate pipeline transportation, the Company uses condensate as diluent for blending with the Company’s bitumen. Transportation costs include expenses related to third-party pipelines and terminals used to transport blended bitumen.

 

4.	SIGNIFICANT ACCOUNTING JUDGEMENTS AND ESTIMATES

 

The timely preparation of the financial statements requires that management make estimates and assumptions and use judgement regarding the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during that period. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. The estimated fair value of financial assets and liabilities are subject to measurement uncertainty. Accordingly, actual results may differ materially from estimated amounts as future confirming events occur. Significant judgements, estimates and assumptions made by management in the preparation of these financial statements are outlined below.

 

Inventories

 

The Company evaluates the carrying value of its inventory at the lower of cost and net realizable value. The net realizable value is estimated based on current market prices less selling costs that the Company would expect to receive from the sale of its inventory.

 

Decommissioning obligations

 

The provision for decommissioning obligations is based upon numerous assumptions including settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. Actual costs and cash outflows could differ from the estimates as a result of changes in any of the above noted assumptions.

 

Income Taxes

 

The provision for income taxes is based on judgments in applying income tax law and estimates on the timing and likelihood of reversal of temporary differences between the accounting and tax bases of assets and liabilities. The provision for income taxes is based on the Company’s interpretation of the tax legislation and regulations which are also subject to change. Deferred tax assets are recognized when it is considered probable that deductible temporary differences will be recovered in future periods, which requires management judgment. Deferred tax liabilities are recognized when it is considered probable that temporary differences will be payable to tax authorities in future periods, which requires management judgment. Income tax filings are subject to audit and re-assessment and changes in facts, circumstances and interpretations of the standards may result in a material change to the Company’s provision for income taxes. Estimates of future income taxes are subject to measurement uncertainty. Deferred income tax assets are assessed by management at the end of the reporting period to determine the likelihood that they will be realized from future earnings.

 

 

Japan Canada Oil Sands Limited
Notes to the Financial Statements

 

4.

SIGNIFICANT ACCOUNTING JUDGEMENTS AND ESTIMATES (cont.)

 

Bitumen reserves

 

The estimation of reserves involves the exercise of judgment. Forecasts are based on engineering data, estimated future prices, expected future rates of production and the cost and timing of future capital expenditures, all of which are subject to many uncertainties and interpretations. The Company expects that over time its reserves estimates will be revised either upward or downward based on updated information such as the results of future drilling and production. Reserves estimates can have a significant impact on net earnings, as they are a key component in the calculation of depletion and for determining potential asset impairment.

 

Impairments

 

CGU’s are defined as the lowest grouping of assets that generate identifiable cash inflows that are largely independent of the cash inflows of other assets or groups of assets. The classification of assets into CGU’s requires significant judgment and interpretations with respect to the integration between assets, the existence of active markets, external users, shared infrastructures, and the way in which management monitors the Company’s operations. The recoverable amounts of CGU’s and individual assets have been determined as the higher of the CGU’s or the asset’s fair value less costs of disposal and its value in use. These calculations require the use of estimates and significant assumptions and are subject to changes as new information becomes available including information on future commodity prices, expected production volumes, quantity of proved and probable reserves and discount rates as well as future development and operating costs. Changes in assumptions used in determining the recoverable amount could affect the carrying value of the related assets and CGU’s.

 

Property, plant and equipment

 

Producing assets within PP&E are depleted using the unit-of-production method based on estimated total recoverable proved plus probable reserves and future costs required to develop those reserves. There are several inherent uncertainties associated with estimating reserves. By their nature, these estimates of reserves, including the estimates of future prices and costs, and related future cash flows are subject to measurement uncertainty, and the impact on the financial statements of future periods could be material.

 

Joint arrangements

 

Judgement is required to determine when the Company has joint control of a contractual arrangement, which requires a continuous assessment of the relevant activities and when the decisions in relation to those activities require unanimous consent. Judgement is also required to classify a joint arrangement as either a joint operation or a joint venture when the arrangement has been structured through a separate vehicle. Classifying the arrangement requires the Company to assess its rights and obligations arising from the arrangement. Specifically, the Company considers the legal form of the separate vehicle, the terms of the contractual arrangement and other relevant facts and circumstances. This assessment often requires significant judgement, and a different conclusion on joint control, or whether the arrangement is a joint operation or a joint venture, may have a material impact on the accounting treatment.

 

Leases — estimating the incremental borrowing rate

 

The Company cannot readily determine the interest rate implicit in the lease, therefore, it uses its incremental borrowing rate (“IBR”) to measure lease liabilities. The IBR is the rate of interest that the Company would have to pay to borrow over a similar term, and with a similar security, the funds necessary to obtain an asset of a similar value to the right-of-use asset in a similar economic environment. The IBR therefore reflects what the Company ‘would have to pay’, which requires estimation when no observable rates are available or when they need to be adjusted to reflect the terms and conditions of the lease. The Company estimates the IBR using observable inputs (such as market interest rates) when available and is required to make certain entity-specific estimates.

 

 

Japan Canada Oil Sands Limited
Notes to the Financial Statements

 

4.

SIGNIFICANT ACCOUNTING JUDGEMENTS AND ESTIMATES (cont.)

 

Other

 

The COVID-19 pandemic, which began in early 2020, continues to create uncertainty and negatively impact the commodity price environment by suppressing the continued recovery in global economic activity and demand for hydrocarbon products. It continues to be difficult to forecast and account for the risk posed by the COVID-19 pandemic.

 

5.

FIRST-ADOPTION OF IFRS

 

These financial statements, for the period ended September 17, 2021 are the first financial statements the Company has prepared in accordance with IFRS. For the periods from January 1, 2011, up to and including the year ended December 31, 2020, the Company prepared its financial statements in accordance with US GAAP.

 

Accordingly, the Company has prepared financial statements that comply with IFRS applicable as at September 17, 2021, together with the comparative period data for the year ended December 31, 2020, as described in the summary of significant accounting policies. In preparing the financial statements, the Company’s opening balance sheet was prepared as at January 1, 2020, the Company’s date of transition to IFRS. This note explains the principal adjustments made by the Company in restating its US GAAP financial statements, including the balance sheet as at January 1, 2020 and the financial statements as of, and for, the year ended December 31, 2020 and the period ended September 17, 2021.

 

Exemptions applied

 

IFRS 1 First-time Adoption of International Financial Reporting Standards sets forth guidance for the initial adoption of IFRS. Under IFRS 1 the standards are applied retrospectively at the transitional balance sheet date with all adjustments to assets and liabilities recognized in retained earnings unless certain exemptions are applied. The Company has applied the following optional exemptions to its opening balance sheet dated January 1, 2020:

 

●

The estimates at January 1, 2020, and at December 31, 2020, are consistent with those made for the same dates in accordance with US GAAP (after transitional adjustments to reflect any differences in accounting policies). The estimates used by the Company to present these amounts in accordance with IFRS reflect conditions at January 1, 2020, the date of transition to IFRS and as at December 31, 2020.

 

The Company has assessed the classification and measurement of financial assets on the basis of the facts and circumstances that exist at January 1, 2020.

 

The Company has elected to measure oil and gas assets at January 1, 2020 on the following basis:

 

●

Deemed costs

 

●

IFRS requires that property, plant and equipment associated with oil and natural gas development and production be monitored and depreciated at a more granular level than was required under full costs accounting allowable under US GAAP. Upon adoption of IFRS the Company elected to use fair value as deemed cost of PP&E. The fair value was determined using fair value less cost to sell based on a discounted future cash flows of proved plus probable reserves using forecast prices and costs.

 

●

Leases

 

●

Lease liabilities were measured at the present value of the remaining lease payments, discounted using the lessee’s incremental borrowing rate at January 1, 2020. Hindsight was applied in determining the lease term for leases with extension options. Right-of-use assets were measured at the amount equal to the lease liabilities, adjusted by the amount of any prepaid or accrued lease payments relating to that lease recognized in the balance sheet immediately before January 1, 2020

 

 

Japan Canada Oil Sands Limited
Notes to the Financial Statements

 

5.

FIRST-ADOPTION OF IFRS (cont.)

 

●

Decommissioning Liabilities

 

●

The Company has measured all decommissioning obligations at January 1, 2020. There is no difference between this amount and the US GAAP carrying amount and therefore no adjustment has been made to retained earnings in respect of this exemption.

 

●

The adoption of IFRS has not changed the Company’s actual cash flows, it has resulted in changes to the Company’s reported financial position and results of operations. In order to allow the users of the financial statements to better understand these changes, the Company’s balance sheets at January 1, 2020, and December 31, 2020 as prepared under US GAAP and statements of comprehensive income for the year ended December 31, 2020, as prepared under US GAAP, have been reconciled to IFRS, with the resulting differences explained.

 

Balance Sheet
As at January 1, 2020

 

($CAD thousands)		note		US GAAP				Effect of transition to IFRS				IFRS
Assets
Current assets
Cash and cash equivalents				$	159,591			$	—			$	159,591
Restricted cash					672								672
Accounts receivable					30,565				—				30,565
Inventories					18,550				—				18,550
Due from related parties					18				—				18
Prepaid expenses and deposits					2,446				—				2,446
					211,842				—				211,842
Non-current assets
Property, plant and equipment		A			1,500,757				(860,000	)			640,757
Right of use asset		C			—				1,372				1,372
Deferred tax		D			67,673				(67,673	)			—
					1,568,430				(926,301	)			642,129
Total assets				$	1,780,272			$	(926,301	)		$	853,971
Liabilities
Current liabilities
Accounts payable and accrued liabilities					56,260				—				56,260
Current portion of long-term debt					77,928				—				77,928
Current portion of lease liability		C			—				493				493
Due to related parties					1,009				—				1,009
					135,197				493				135,690
Non-current liabilities
Long-term debt					698,144				—				698,144
Long-term lease liability		C			—				879				879
Decommissioning obligations					7,147				—				7,147
					705,291				879				706,170
Total liabilities					840,488				1,372				841,860
Shareholders’ equity
Share capital					1,010,871				—				1,010,871
Deficit		A			(71,087	)			(927,673	)			(998,760	)
					939,784				(927,673	)			12,111
Total equity and liabilities				$	1,780,272			$	(926,301	)		$	853,971

 

 

Japan Canada Oil Sands Limited
Notes to the Financial Statements

 

5.

FIRST-ADOPTION OF IFRS (cont.)

 

Balance Sheet
As at December 31, 2020

 

($CAD thousands)		note		US GAAP				Effect of transition to IFRS				IFRS
Assets
Current assets
Cash and cash equivalents				$	46,743			$	—			$	46,743
Accounts receivable					29,113				—				29,113
Inventories					7,440				—				7,440
Due from related parties					6				—				6
Prepaid expenses and deposits					2,594				—				2,594
					85,896				—				85,896
Non-current assets
Property, plant and equipment		A,B			1,443,639				(1,150,784	)			292,855
Right of use asset		C			—				841				841
Deferred tax					67,247				(67,247	)			—
					1,510,886				(1,217,190	)			293,696
Total assets				$	1,596,782			$	(1,217,190	)		$	379,592
Liabilities
Current liabilities
Accounts payable and accrued liabilities					51,838				—				51,838
Current portion of long-term debt					76,392				—				76,392
Current portion of lease liability		C			—				544				544
Due to related parties					1,007				—				1,007
					129,237				544				129,781
Non-current liabilities
Long-term debt					608,249				—				608,249
Long-term lease liability		C			—				335				335
Decommissioning obligations					7,728				—				7,728
					615,977				335				616,312
Total liabilities					745,214				879				746,093
Shareholders’ equity
Share capital					1,010,871				—				1,010,871
Deficit		A,B,C			(159,303	)			(1,218,069	)			(1,377,372	)
					851,568				(1,218,069	)			(366,501	)
Total equity and liabilities				$	1,596,782			$	(1,217,190	)		$	379,592

 

 

Japan Canada Oil Sands Limited
Notes to the Financial Statements

 

5.

FIRST-ADOPTION OF IFRS (cont.)

 

Statement of comprehensive income
For the year ended December 31, 2020

 

($CAD thousands, except per share amounts)		note		US GAAP				Effect of transition to IFRS				IFRS
Revenue
Oil sales				$	279,248			$	—			$	279,248
Royalties					(2,019	)			—				(2,019	)
					277,229				—				277,229
Interest income					925				—				925
Other income					1,684				—				1,684
					279,838				—				279,838
Expenses
Diluent expense					158,272				—				158,272
Transportation and marketing					39,368				—				39,368
Operating expenses					67,409				—				67,409
General and administrative		C			6,250				(570	)			5,680
Financing and interest		C			21,525				77				21,602
Depletion and depreciation		B,C			87,064				21,315				108,379
Impairment		A			—				270,000				270,000
Exploration and other expenses					3,352				—				3,352
Foreign Exchange loss/(gain)					(15,612	)			—				(15,612	)
					367,628				290,822				658,450
Loss before income taxes				$	(87,790	)		$	(290,822	)		$	(378,612	)
Deferred income taxes					427				(427	)			—
Net loss and comprehensive loss				$	(88,217	)		$	(290,395	)		$	(378,612	)
Loss per share
Basic				$	(2,91	)		$	(9.58	)		$	(12.49	)
Diluted				$	(2.91	)		$	(9.58	)		$	(12.49	)

 

A Impairment of property, plant and equipment (“PP&E”)

 

In accordance with IFRS, impairment tests of PP&E must be performed at the CGU level as opposed to the entire PP&E balance which was required under US GAAP through the full cost ceiling test. Impairment is recognized if the carrying value exceeds the recoverable amount for a CGU. Upon adoption of IFRS the Company elected to use fair value as deemed cost of PP&E. The fair value was determined using fair value less cost to sell based on a discounted future cash flows of proved plus probable reserves using forecast prices and costs. A fair value adjustment of $860 million was recognized on transition as of January 1, 2020.

 

For the year ended December 31, 2020, as a result of decreased forward oil prices which impacted the fair value less costs to sell derived from the Company’s reserves, an impairment charge of $270 million was recognized based on discounted future cash flows of proved plus probable reserves using forecast prices and costs at 16 percent.

 

B Depletion of PP&E

 

Upon transition to IFRS, the Corporation adopted a policy of depleting bitumen interests on a unit of production basis over proved plus probable reserves. The depletion policy under the previous GAAP was based on units of production over proved reserves. In addition, under US GAAP future development costs were not included in the depletion calculation. There was no impact of this difference on adoption of IFRS as at January 1, 2020 as a result of the IFRS 1 election, as discussed in note above. For the year ended December 31, 2020 depletion and depreciation was increased by $20.7 million as a result of changes to the depletion calculation.

 

 

Japan Canada Oil Sands Limited
Notes to the Financial Statements

 

5.

FIRST-ADOPTION OF IFRS (cont.)

  

C Leases

 

Under US GAAP, the Company had not adopted ASC 842 Leases. As a result, leases were classified as a finance lease or an operating lease. Operating lease payments are recognized as an operating expense in profit or loss on a straight-line basis over the lease term. Under IFRS, as explained in Note 3, a lessee applies a single recognition and measurement approach for all leases, except for short-term leases and leases of low-value assets and recognizes lease liabilities to make lease payments and right-of-use assets representing the right to use the underlying assets. At the date of transition to IFRS, the Company applied the transitional provision and measured lease liabilities at the present value of the remaining lease payments, discounted using the lessee’s incremental borrowing rate at the date of transition to IFRS. Right-of-use assets were measured at the amount equal to the lease liabilities adjusted by the amount of any prepaid or accrued lease payments. As a result, the Company recognized an increase of $1.4 million in lease liabilities and $1.4 million in right-of-use assets. In addition, depreciation increased by $0.5 million, finance costs increased by $0.1 million and general and administration costs decreased by $0.6 million for the period ended December 31, 2020.

 

D Deferred tax

 

The various transitional adjustments resulted in various temporary differences. According to the accounting policies in Note 3, the Company has to recognize the tax effects of such differences. Deferred tax adjustments are recognized in correlation to the underlying transaction either in retained earnings or a separate component of equity.

 

E Statement of cash flows

 

Under US GAAP, a lease is classified as a finance lease or an operating lease. Cash flows arising from operating lease payments are classified as operating activities. Under IFRS, a lessee generally applies a single recognition and measurement approach for all leases and recognizes lease liabilities. Cash flows arising from payments of principal portion of lease liabilities are classified as financing activities. Therefore, cash outflows from operating activities decreased by $0.1 million and cash outflows from financing activities increased by the same amount for the period ended December 31, 2020.

 

F Functional currency

 

Under IFRS, the framework used to determine the functional currency is similar to that used to determine the currency of measurement under US GAAP; however, under IFRS, the indicators for determining the functional currency are broken down into primary and secondary indicators. Primary indicators are closely linked to the primary economic environment in which the entity operates. Secondary indicators provide supporting evidence to determine an entity’s functional currency. Primary indicators receive more weight under IFRS than US GAAP. In 2019 the Company’s revenue contracts had changed from primarily being US dollar denominated to Canadian dollar denominated. The change in revenue contracts resulted in cash flows being driven primarily by the Canadian dollar. Due to the change in the primary economic environment in which the Company operates, management has concluded that the functional currency of the Company under IFRS is the Canadian dollar. Under US GAAP, the functional currency of the Company was the US dollar.

 

Accordingly, all non-monetary assets and liabilities have been converted to the Canadian dollar at their respective historical rates.

 

6. CASH AND CASH EQUIVALENTS

 

As at September 17, 2021, the Company held cash of $4.4 million and $0.5 million in restricted cash (December 31, 2020 — cash of $46.7 million, January 1, 2020 — cash of $159.6 million and $0.7 million restricted cash). The credit risk associated with the Company’s cash and cash equivalents was considered low as the Company’s balances were held with large Canadian or Provincial chartered banks.

 

JACOS has long-term pipeline transportation contracts in place which are subject to credit requirements requiring letters of credit to guarantee future payments under the contracts. Prior to the corporate divestiture to Greenfire Resources Inc. JACOS had approximately $51 million in letters of credit outstanding in relation to these long-term pipeline transportation agreements. The annual guarantee fees incurred is calculated at an interest rate of 0.8%.

 

 

Japan Canada Oil Sands Limited
Notes to the Financial Statements

 

7.

ACCOUNTS RECEIVABLE

 

As at ($000’s)		September 17, 2021				December 31, 2020				January 1, 2020
Accounts receivable		$	56,517			$	29,113			$	30,565

 

Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its contractual obligations and arises principally from the Company’s accounts receivable. The Company is primarily exposed to credit risk from receivables associated with its oil sales. The Company’s customer base consisted of large integrated energy companies. The Company manages its credit risk exposure by transacting with high-quality credit worthy counterparties and monitoring credit worthiness and/or credit ratings on an ongoing basis.

 

At September 17, 2021, December 31, 2020 and January 1, 2020, credit risk from the Company’s outstanding accounts receivable balances was considered low due to a history of collections and the receivables that were held by credit worthy counterparties. There were no overdue balances for the above ending periods.

 

8.

INVENTORIES

 

As at ($000’s)		September 17, 2021				December 31, 2020				January 1, 2020
Oil inventories		$	5,559			$	5,703			$	17,114
Warehouse materials and supplies			1,879				1,737				1,436
Inventories		$	7,438			$	7,440			$	18,550

 

During the period ended September 17, 2021, approximately $171 million (December 31, 2020 — $158 million) of purchased inventory was recorded in diluent expense in the statements of comprehensive income (loss).

 

9.

PROPERTY, PLANT AND EQUIPMENT (“PP&E”)

 

$(000’s)			Petroleum properties and related equipment				Furniture and other equipment				Total
Cost
Balance as at January 1, 2020			637,755				3,002				640,757
Expenditures on PP&E			27,385				310				27,695
Balance as at December 31, 2020			665,140				3,312				668,452
Expenditures on PP&E			9,755				2				9,757
Balance as at September 17, 2021			674,895				3,314				678,209
Accumulated DD&A
Balance as at January 1, 2020			—				—				—
Depletion and depreciation			105,075				522				105,597
Impairment			270,000				—				270,000
Balance as at December 31, 2020			375,075				522				375,597
Depletion and depreciation			77,083				324				77,407
Impairment reversal			(73,252	)			—				(73,252	)
Balance as at September 17, 2021			378,906				846				379,752
Net book Value
Balance at January 1, 2020			637,755				3,002				640,757
Balance at December 31, 2020			290,065				2,790				292,855
Balance at September 17, 2021			295,989				2,468				298,457

 

 

Japan Canada Oil Sands Limited
Notes to the Financial Statements

 

9.

PROPERTY, PLANT AND EQUIPMENT (“PP&E”) (cont.)

 

For the period ended September 17, 2021, due to increases in forward oil prices, a test for impairment reversal was completed. The recoverable value was based on fair value less costs of disposal (“FVLCOD”). FVLCOD is the amount that would be realized from the disposition of an asset or CGU in an arm’s length transaction between knowledgeable and willing parties. As JACOS had a sales agreement is place with Greenfire Resources Inc., the asset was written up to the value assigned in the agreement, which was approximately $298.5 million.

 

At December 31, 2020, due to the continued depressed oil prices as a result of the COVID-19 pandemic, the Company determined that there were indicators of impairment for its CGU. The recoverable amount was not sufficient to support the carrying amount which resulted in an impairment of $270 million. The recoverable amount was based on its FVLCOD which was estimated using a discounted cash flow model of proved plus probable cash flows from an independent reserve report prepared as at December 31, 2020.

 

The recoverable amount of the Company’s CGU was calculated at December 31, 2020 using the following benchmark reference prices for the years 2021 to 2028 adjusted for commodity differentials specific to the Company. The prices and costs subsequent to 2029 have been adjusted for inflation at an annual rate of 2%.

 

		2021				2022				2023				2024				2025				2026				2027				2028
WCS heavy oil (CA$/bbl)		$	45.16			$	49.67			$	53.95			$	57.92			$	59.09			$	60.26			$	61.47			$	62.70
WTI crude oil (US$/bbl)		$	48.00			$	51.50			$	54.50			$	57.79			$	58.95			$	60.13			$	61.33			$	62.56

 

The following table demonstrates the sensitivity of the estimated recoverable amount of the Company’s CGU to possible changes in key assumptions inherent in the estimate.

 

$(000’s)		Amount				Impairment				Change in discount rate of 1%				Change in diluted bitumen pricing of $2.50
Hangingstone Expansion CGU		$	290,065			$	270,000			$	21,500			$	87,500

 

10.

LEASES

 

The Company has recognized the following leases:

 

$(000’s)		Total
Lease obligation at January 1, 2020		$	1,372
Interest expense			77
Payments			(570	)
Balance as at December 31, 2020			879
Interest expense			32
Payments			(390	)
Balance as at September 17, 2021		$	521

 

The Company has recognized the following right of use asset:

 

$(000’s)		Total
Right of use at January 1, 2020		$	1,372
Depreciation			(531	)
Balance as at December 31, 2020			841
Depreciation			(354	)
Balance as at September 17, 2021		$	487

 

The Company incurs lease payments related to its head office. The lease will expire in July 2022. The Company has recognized a lease liability measured at the present value of the remaining lease payments using the Company’s weighted-average incremental borrowing rate of 7%.

 

 

Japan Canada Oil Sands Limited
Notes to the Financial Statements

 

11.

INCOME TAXES

 

The Company has $1.6 billion in unclaimed federal tax deductions and $1.2 billion in unclaimed provincial tax deductions that are available indefinitely to be applied against income generated from oil and gas activities.

 

The Company has obtained investment tax credits, which will expire as follows:

 

$(000’s)
2039		$	143
Total		$	143

 

Although management considers the investment tax credits claimed to be reasonable and appropriate, they are subject to assessment in the future at such time as they are used to reduce income taxes otherwise payable and portions of the claims could be disallowed.

 

The Company has accumulated Federal Non-Capital Loss Carryforward that will expire as follows:

 

$(000’s)
2035		$	38,453
2036			187,478
2037			58,725
2038			29,991
2040			36,168
2041			1,232,793
Total		$	1,583,608

 

The Company has accumulated Provincial Non-Capital Loss Carryforward that will expire as follows:

 

$(000’s)
2036		$	76,903
2037			58,725
2038			29,991
2040			25,968
2041			999,628
Total		$	1,191,215

 

Income tax expense is summarized as follows:

 

$(000’s)			For the period ended September 17, 2021				For the year ended December 31, 2020
Income (loss) before taxes			104,833				(378,612	)
Expected statutory income tax rate			23	%			24	%
Expected income tax expense (recovery)			24,112				(90,867	)
Permanent differences			(731	)			(1,530	)
Effect of Alberta provincial tax rate change			—				12,877
Unrecognized deferred tax assets			(23,381	)			79,520
Deferred income tax expense (recovery)		$	—			$	—

 

 

Japan Canada Oil Sands Limited
Notes to the Financial Statements

 

12.

DECOMMISSIONING OBLIGATIONS

 

The Company’s decommissioning obligations result from net ownership interests in oil assets including well sites, gathering systems and processing facilities. The Company estimates the total undiscounted escalated amount of cash flows required to settle its decommissioning obligations to be approximately $97 million. A credit-adjusted discount rate of 7% and an inflation rate of 1.8% were used to calculate the decommissioning obligations. A 1.0% change in the credit-adjusted discount rate would impact the discounted value of the decommissioning obligations by approximately $0.3 million with a corresponding adjustment to PP&E or net income (loss). The decommissioning obligations are estimated to be settled in periods up to year 2075.

 

A reconciliation of the decommissioning liabilities is provided below:

 

As at $(000’s)		September 17, 2021				December 31, 2020
Beginning balance		$	7,728			$	7,147
Change in estimate			(75	)			167
Liabilities settled in the year			(53	)			(30	)
Accretion expense			320				444
Ending balance		$	7,920			$	7,728

 

13.

OTHER INCOME AND EXPENSES

 

$(000’s)			For the period ended September 17, 2021				For the year ended December 31, 2020
Interest income		$	43			$	925
Gross overriding royalty			935				39
Other			50				1,645
Other income		$	1,028			$	2,609

 

14.

FINANCIAL RISK MANAGEMENT

 

The Company is exposed to financial risk on its financial instruments including cash and cash equivalents, short-term investments, accounts receivable, due from related parties, prepaid expenses and deposits, accounts payable and due to related parties, and long-term banks loans payable. The Company manages its exposure to financial risks by operating in a manner that minimizes its exposure to the extent practical. The Company’s financial instruments as at September 17, 2021 and December 31, 2020 include accounts receivable, accounts payable and accrued liabilities. The fair value of accounts receivable, accounts payable and accrued liabilities approximate their carrying amounts due to its short-term maturity.

 

The main financial risks affecting the Company are discussed below:

 

Credit risk

 

Credit risk arises when a failure by counterparties to discharge their obligations could reduce the amount of future cash inflows from financial instruments on hand as at the balance sheet date. The Company’s financial instrument subject to credit risk is accounts receivable.

 

The maximum exposure to credit risk is represented by the carrying amount of each financial asset on the balance sheet. On an ongoing basis, the Company assesses whether there should be any impairment of the financial instruments. There are no material financial instruments that the Company considers past due.

 

 

Japan Canada Oil Sands Limited
Notes to the Financial Statements

 

14.

FINANCIAL RISK MANAGEMENT (cont.)

 

Liquidity risk

 

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they are due. The Company actively manages its liquidity through cost control and debt management policies. Such strategies include continuously monitoring forecast and actual cash flows. The Company relies on additional funding from Canada Oil Sands Co, Ltd (Parent Company). The nature of the oil and gas industry is very capital intensive. As a result, the Company prepares annual capital expenditure budgets and utilizes authorizations for expenditures for projects to manage capital expenditures. Please refer to note 16 “Long-term Debt” for additional information on liquidity risk.

 

Accounts payable is considered due to suppliers in one year or less while bank debt is repaid in semi-annual equal installments, which began in June 2020 and will end in December 2029. Further, interest is paid semi-annually on the outstanding principal amount during the term of the loan.

 

Market risk

 

Market risk is the risk of loss that might arise from changes in market factors such as interest rates, foreign exchange rates and equity prices.

 

●

Interest rate risk

 

Interest rate risk arises because of the fluctuation in interest rates. The Company’s objective in managing interest rate risk is to minimize the interest expense on liabilities and debt. The Company does not believe that the results of operations or cash flows would be affected to any significant degree by a sudden change in market interest rates.

 

●

Foreign currency risk

 

The Company’s debt is denominated in US dollars. As well, the Company has certain revenue contracts which are denominated and settled in US dollars. The Company manages the risk of foreign exchange fluctuations by monitoring its’ US dollar cash flow. The net carrying value of these US dollar denominated balances is as follows:

 

As at $(000’s CAD)		September 17, 2021				December 31, 2020				January 1, 2020
Cash		$	2,198			$	37,302			$	120,256
Accounts Receivable		$	16,023			$	6,577			$	14,767
Long-term debt			—			$	684,641			$	776,073

 

If there was a 1% strengthening or weakening of the Canadian dollar against the US dollar, the corresponding impact would be as follows:

 

As at $(000’s CAD)		September 17, 2021				December 31, 2020				January 1, 2020
Cash		$	22			$	373			$	1,203
Accounts receivable		$	160			$	66			$	148
Long-term debt			—			$	6,846			$	7,761

 

●

Commodity price risk

 

Commodity price risk arises due to fluctuations in commodity prices. Management believes it is prudent to manage the variability in cash flows by occasionally entering into hedges. The Company utilizes various types of derivatives and financial instruments, such as swaps and options, and fixed-price normal course of business purchase and sale contracts to manage fluctuations in cash flows. As at September 17, 2021, the Company has no outstanding derivatives in place.

 

 

Japan Canada Oil Sands Limited
Notes to the Financial Statements

 

15.

CAPITAL MANAGEMENT

 

The Company’s capital consists primarily of shareholders equity, working capital and long-term debt. The Company manages its capital structure to maximize financial flexibility by making adjustments in light of changes in economic conditions and the risk characteristics of the underlying assets. Each potential investment opportunity is assessed to determine the nature and amount of capital required together with the relative proportions of debt and equity to be deployed to ensure that the Company will be able to continue as a going concern and to provide a return to shareholders through exploring and developing its assets. As the Company is in the early stages of these activities, it will meet its capital requirements through continued funding from the existing shareholder or the ultimate parent company. The Company does not presently utilize any quantitative measures to monitor its capital and is not subject to any externally imposed capital requirements.

 

16.

LONG-TERM DEBT

 

As at $(000’s CAD)		September 17, 2021				December 31, 2020				January 1, 2020
US dollar denominated debt:
LIBOR plus 0.1%		$	—			$	343,764			$	389,640
LIBOR plus 1.0%			—			$	343,764			$	389,640
Amortization of debt issuance costs and issuer discount			—				(2,887	)			(3,207	)
Total term debt		$	—			$	684,641			$	776,073
Current portion of long-term debt		$	—			$	76,392			$	77,928
Long-term debt		$	—			$	608,249			$	698,144

 

Interest is paid semi-annually on the outstanding principal amount during the life of the loan. The principal repayment schedule included semi-annual equal installments, which began in June 2020 and was scheduled to end in December 2029.

 

As a condition of Greenfire Resources Inc. acquiring all of the issued and outstanding shares of the Company, all outstanding bank debt was required to be settled prior to September 17, 2021. In order to facilitate the settlement of the outstanding loans, on September 9, 2021 CANOS contributed additional capital to the Company, thus increasing the value of their stated capital. Approximately $305 million of the debt was repaid with the remaining balance of $341 million in debt being assumed by the Parent Company. No additional shares were issued.

 

17.

DILUENT, TRANSPORTATION & MARKETING AND OPERATING EXPENSES

 

$(000’s)			For the period ended September 17, 2021				For the year ended December 31, 2020
Diluent expense		$	171,174			$	158,272
Transportation and marketing			27,853				39,368
Operating expenses			56,479				67,409
Total expenses		$	255,506			$	265,049

 

Diluent, transportation & marketing and operating expenses are costs incurred in the field that are required in order to produce and get bitumen to a sales market.

 

 

Japan Canada Oil Sands Limited
Notes to the Financial Statements

 

18.

FINANCING AND INTEREST

 

$(000’s)			For the period ended September 17, 2021				For the year ended December 31, 2020
Accretion on long-term debt		$	7,455			$	13,791
Guarantee fees			3,348				7,290
Interest on settlement of lease liability			31				77
Accretion on decommissioning liabilities			320				444
Financing and interest expense		$	11,154			$	21,602

 

19.

COMMITMENTS AND CONTINGENCIES

 

The Company has lease commitments related to office premises (Note 10). The Company also has transportation agreements mainly related to pipeline transportation services. Future minimum amounts payable under these commitments are as follows:

 

$(000’s)		September 18 to December 31, 2021				2022				2023				2024				2025				2026				Beyond 2026				Total
Office leases			155				361				—				—				—				—				—				516
Transportation			7,804				30,027				30,111				30,231				29,175				28,110				249,569				405,567
Total			7,959				30,388				30,111				30,231				29,175				28,110				249,569				406,083

 

The Company is currently involved in legal claims associated with the normal course of operations and it believes that any liabilities that might arise from such matters, to the extent not provided for, are not likely to have a material effect on its financial statements.

 

20.

RELATED PARTY TRANSACTIONS

 

The following related party transactions occurred in the normal course of business and are recorded as income (expense) or capital items in the Company’s financial statements.

 

$(000’s)			For the period ended September 17, 2021				For the year ended December 31, 2020
Operating, general and administrative expenses and financing(a)		$	(3,140	)		$	(4,888	)
Exploration expenses(b)			(89	)			—
Plant and equipment expenditure(c)			(15	)			(47	)
Other income(d)			11				12
Reimbursement for costs incurred on behalf of related parties(e)			82				50
Services provided by management(f)			(493	)			(4,922	)

 

(a)

These costs were paid to the Parent Company for expat services and to Japan Petroleum Exploration Co., Ltd. for guarantee fees.

(b)

All exploration expenses were paid to JGI, Inc.

(c)

Reimbursements to the Parent Company for plant and equipment costs.

(d)

The Company also provided accounting and other management services to Japex Canada Ltd and Japex Montney Ltd.

(e)

Reimbursement from the Parent Company and Japex Montney Ltd. for miscellaneous costs which were incurred by the Company.

(f)

One of the Company’s external directors is employed by Bennett Jones L.L.P. The firm provides legal advisory services to the Company. The above amounts represent amounts paid to Bennett Jones L.L.P. for legal services.

 

 

Japan Canada Oil Sands Limited
Notes to the Financial Statements

 

20.

RELATED PARTY TRANSACTIONS (cont.)

 

The following related party amounts were outstanding:

 

As at $(000’s)		September 17, 2021				December 31, 2020				January 1, 2020
Due from:
Japex Canada Ltd.		$	—			$	6			$	18
		$	—			$	6			$	18
Due to:
Japan Petroleum Exploration Co., Ltd.		$	—			$	712			$	788
Canada Oil Sands Co., Ltd.			—				235				221
JGI, Inc.			—				60				—
		$	—			$	1,007			$	1,009

 

The corporation considers directors and officers of the Company as key management personnel.

 

$(000’s)			For the period ended September 17, 2021				For the year ended December 31, 2020
Salaries, benefits, and director fees		$	3,886			$	3,207

 

21.

SUPPLEMENTAL CASH FLOW INFORMATION

 

The following table reconciles the net changes in non-cash working capital and other liabilities from the balance sheet to the statement of cash flows:

 

$(000’s)			For the period ended September 17, 2021				For the year ended December 31, 2020
Change in accounts receivable		$	(27,404	)		$	1,452
Change in inventories			(278	)			9,298
Change in due from related parties			6				12
Change in prepaid expenses and deposits			(1,691	)			(148	)
Change in accounts payable and accrued liabilities			(24,689	)			(4,422	)
Change in due to related parties			(1,007	)			(2	)
		$	(55,063	)		$	6,190
Related to operating activities		$	(61,929	)		$	8,812
Related to investing activities (accrued additions to PP&E)			6,866			$	(2,622	)
Net change in non-cash working capital		$	(55,063	)		$	6,190
Cash interest paid (included in operating activities)		$	7,947			$	20,837
Cash interest received (included in operating activities)		$	43			$	925

 

 

Japan Canada Oil Sands Limited
Notes to the Financial Statements

 

22.

SHARE CAPITAL

 

31,000,000 common shares are authorized to be issued.

 

		Period ended September 17, 2021								Year ended December 31, 2020
$(000’s)		Number of shares				Amount				Number of shares				Amount
Shares outstanding
Balance, beginning of period			30,302,083			$	1,010,871				30,302,083			$	1,010,871
Return of capital			—				(47,500	)			—				—
Capital contribution			—				645,674				—				—
Balance, end of period			30,302,083			$	1,609,045				30,302,083			$	1,010,871

 

As a condition of Greenfire Resources Inc. acquiring all of the issued and outstanding shares of the Company, The JBIC loan and Mizuho loan were required to be settled prior to September 17, 2021. In order to facilitate the settlement of the outstanding loans, on September 9, 2021 CANOS contributed additional capital to the Company, thus increasing the value of their stated capital. This was completed with two separate transactions. In the first transaction CANOS provided JACOS with a $305 million capital contribution to repay the half of the outstanding loans. In the second transaction CANOS assumed the remaining outstanding debt of $341 million in exchange for additional stated capital in JACOS. No additional shares were issued with the transactions. In August 2021, $47.5 million of capital was returned to CANOS.

 

		Period ended September 17, 2021				Year ended December 31, 2020
Weighted average shares outstanding-basic and diluted			30,302,083				30,302,083

 

23.

SUBSEQUENT EVENTS

 

In the first half of 2021 the Company initiated a strategic alternatives process. Such alternatives may have included a corporate sale or sale of the Company’s assets. On September 17, 2021, Greenfire Resources Inc. acquired all the issued and outstanding common shares of the Company in exchange for $346 million.

 

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