UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM
(Mark One)
OR
For
the fiscal year ended
OR
OR
Commission File Number:
(Exact name of Registrant as specified in its charter)
| Not applicable | ||
| (Translation of Registrant’s name into English) | (Jurisdiction of incorporation or organization) |
(403) 264-9046
(Address of principal executive offices)
(Name, Telephone, Email and/or Facsimile number and Address of Company Contact Person)
Securities registered or to be registered pursuant to Section 12(b) of the Act:
| Title of each class | Trading Symbols | Name of each exchange on which registered | ||
Securities registered or to be registered pursuant to Section 12(g) of the Act: None
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None
Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report:
On December 31, 2023,
the issuer had
Indicate by check mark
if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐
If this report is an
annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934. Yes ☐
Indicate by check mark
whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past 90 days. Yes ☐
Indicate by check mark
whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of
this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
| Large accelerated filer | ☐ | Accelerated filer | ☐ |
| ☒ | Emerging growth company |
If an emerging growth
company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not
to use the extended transition period for complying with any new or revised financial accounting standards† provided pursuant to
Section 13(a) of the Exchange Act.
Indicate by check mark
whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal
control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting
firm that prepared or issued its audit report.
If securities are registered
pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing
reflect the correction of an error to previously issued financial statements.
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:
| U.S. GAAP ☐ | as issued by the International Accounting Standards Board ☒ | Other ☐ |
If “Other” has been checked in response to the previous question, indicate by check mark which financial statement item the registrant has elected to follow. Item 17 ☐ Item 18 ☐
If this is an annual
report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange
Act). Yes ☐ No
This annual report on Form 20-F is incorporated by reference into the registrant’s Registration Statements on Form S-8 File No. 333-277054.
TABLE OF CONTENTS
i
EXPLANATORY NOTE
On September 20, 2023 (the “Closing Date”) Greenfire Resources Ltd., an Alberta corporation (the “Company”) consummated its previously announced business combination, pursuant to the Business Combination Agreement, dated as of December 14, 2022 (as amended on April 21, 2023, June 15, 2023, and September 5, 2023, the “Business Combination Agreement,” and the transactions contemplated thereby, collectively, the “Business Combination”), with M3-Brigade Acquisition III Corp. (“MBSC”), DE Greenfire Merger Sub Inc., a Delaware corporation and a direct, wholly-owned subsidiary of the Company (“DE Merger Sub”), 2476276 Alberta ULC, an Alberta unlimited liability corporation and a direct, wholly-owned subsidiary of the Company (“Canadian Merger Sub”), and Greenfire Resources Inc., an Alberta corporation (“Greenfire”).
As part of the Business Combination, on the Closing Date (i) Canadian Merger Sub amalgamated with and into Greenfire pursuant to a statutory plan of arrangement (the “Plan of Arrangement”) under the Business Corporations Act (Alberta), with Greenfire continuing as the surviving company (“Surviving Greenfire”), and Surviving Greenfire became a direct, wholly-owned subsidiary of the Company 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 following the Merger (“Surviving MBSC”), as a result of which Surviving MBSC became a direct, wholly-owned subsidiary of the Company.
On the Closing Date, pursuant to the Plan of Arrangement and prior to the effective time of the Merger (the “Merger Effective Time”), among other things, (i) the holders of common shares of Greenfire (“Greenfire Common Shares”) received, in the aggregate, 43,690,534 common shares in the capital of the Company (the “Common Shares”) and their pro rata share of US$75,000,000 (the “Cash Consideration”), as determined in accordance with the Plan of Arrangement, in exchange for their Greenfire Common Shares, (ii) the holders of warrants to purchase Greenfire Common Shares issued pursuant to the Greenfire’s former equity plan (“Greenfire Performance Warrants”) received 3,617,016 warrants to purchase the Common Shares, with substantially the same terms as the Greenfire Performance Warrants, as adjusted in accordance with the Plan of Arrangement (the “Company Performance Warrants”), and their pro rata share of the Cash Consideration, as determined in accordance with the Plan of Arrangement, in exchange for their Greenfire Performance Warrants, (iii) holders of warrants (“Greenfire Bond Warrants”) to purchase Greenfire Common Shares issued pursuant to the Warrant Agreement, dated 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, as amended by the First Greenfire Supplemental Warrant Agreement dated December 14, 2022 (the “Bond Warrant Agreement”), received 15,769,183 the Common Shares and a cash payment equal to their pro rata share of the Cash Consideration payable to holders of Greenfire Bond Warrants, each as determined in accordance with the Bond Warrant Agreement and the Plan of Arrangement, in exchange for their Greenfire Bond Warrants. In addition, 5,000,000 Company Warrants (as defined below), were issued to the pre-Plan of Arrangement holders of Greenfire Performance Warrants, Greenfire Bond Warrants, and Greenfire Common Shares, in each case in the numbers determined in accordance with the Plan of Arrangement.
On the Closing Date, at the Merger Effective Time, (i) holders of MBSC Class A common stock, par value $0.0001 per share (the “MBSC Class A Common Shares”) (after giving effect to the stockholder redemptions of the MBSC Class A Common Shares and the issuance of MBSC Class A Common Shares pursuant to the PIPE Financing (as defined below)) received, in aggregate, 4,177,091 Common Shares for their MBSC Class A Common Shares and, (ii) holders of MBSC Class B common stock, par value $0.0001 per share (“MBSC Class B Common Shares”)(after giving effect to certain forfeitures pursuant to the Business Combination Agreement) received, in the aggregate 4,250,000 Common Shares and a cash payment equal to the MBSC Working Capital plus the MBSC Extension Amount (each as defined in the Business Combination Agreement) at the Merger Effective Time; (iii) private placement warrants to purchase shares of MBSC held by M3-Brigade Sponsor III LP, a Delaware limited partnership (the “MBSC Sponsor”) (after giving effect to certain forfeitures pursuant to the Business Combination Agreement) were converted into 2,526,667 warrants to purchase Common Share (the “Company Warrants”).
In addition, immediately prior the Merger Effective time (i) the outstanding units of MBSC were each automatically separated into one MBSC Class A Common Share and one-third of one MBSC Public Warrant and (ii) MBSC redeemed all of the MBSC Public Warrants at $0.50 per MBSC Public Warrant.
Substantially concurrently with the closing of the Business Combination, the Company and MBSC consummated the PIPE Financing pursuant to which 4,177,091 Common Shares were issued to the PIPE Investors for an aggregate purchase price of approximately US$42 million.
Effective as of January 1, 2024, Greenfire Resources Operating Corporation and Surviving Greenfire amalgamated in accordance with the provisions of the ABCA, with the surviving corporation continuing as Greenfire Resources Operation Corporation and as a wholly subsidiary of the Company.
The common shares of the Company are traded on the New York Stock Exchange (“NYSE”) and the Toronto Stock Exchange (“TSX”) under the symbol “GFR”.
ii
INTRODUCTION
Except as otherwise indicated or required by context, references in this Annual Report on Form 20-F (including information incorporated by reference herein, the “Annual Report”) to (i) “we,” “us,” “our,” or the “Company” refer to Greenfire Resources Ltd., an Alberta corporation, and its subsidiaries, (ii) “Greenfire” refers to Greenfire Resources Inc., an Alberta corporation that became a wholly-owned subsidiary of the Company upon the closing of the Business Combination (effective as of January 1, 2024, Greenfire Resources Operating Corporation and Greenfire amalgamated, with the surviving corporation continuing as “Greenfire Resources Operation Corporation”, a wholly-owned subsidiary of the Company, and (iii) CAD$ refers to Canadian dollars. Certain amounts that appear in this Annual Report may not sum due to rounding.
This Annual Report contains (i) the Company’s audited consolidated financial statements as at December 31, 2023 and 2022 and for each of the years in the three-year period ended December 31, 2023 and related notes and (ii) 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”). The Annual Financial Statements have been prepared in accordance with International Financial Reporting Standards, as issued by the International Accounting Standards Board (“IFRS”).
Unless otherwise indicated in this Annual Report, all references to: “fiscal 2023” are to the 12-month period ended December 31, 2023, “fiscal 2022” are to the 12-month period ended December 31, 2022, and “fiscal 2021” are to the 12-month period ended December 31, 2021.
iii
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
Some of the statements contained in this Annual Report 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 Annual Report 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 Annual Report 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; |
iv
| ● | 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; |
v
| ● | 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 Annual Report, 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.
vi
CERTAIN DEFINED TERMS
Unless the context otherwise requires, references in this Annual Report to:
| ● | “2025 Notes” are to Greenfire’s 12.000% Senior Secured Notes, outstanding amounts of which were redeemed concurrently with the Business Combination. | |
| ● | “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. | |
| ● | “ABCA” are to the Business Corporations Act (Alberta). |
| ● | “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. |
| ● | “Amalgamation” are to the amalgamation of Greenfire and Canadian Merger Sub. |
| ● | “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. |
| ● | “APEGA” are to the Association of Professional Engineers and Geoscientists of Alberta. |
| ● | “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. |
| ● | “Arrangement Effective Date” are to the date on which the Articles of Arrangement were filed with the Registrar. |
| ● | “Arrangement Effective Time” are to the time at which the Articles of Arrangement were filed with the Registrar on the Arrangement Effective Date. |
| ● | “Articles of Arrangement” are to the articles of arrangement in respect of the Arrangement. |
| ● | “bbl” are to barrel. |
| ● | “bbls/d” are to barrels per day. |
| ● | “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. |
| ● | “Brigade” are to Brigade Capital Management, LP, a Delaware limited partnership. |
| ● | “Business Combination” are to the transactions contemplated by the Business Combination Agreement. |
| ● | “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. |
| ● | “C$,” “CAD$” and “CAD” are to Canadian dollars. |
vii
| ● | “Canadian Merger Sub” are to 2476276 Alberta ULC, an Alberta unlimited liability corporation and a direct, wholly-owned subsidiary of the Company. |
| ● | “Cantor” are to Cantor Fitzgerald & Co. |
| ● | “Cash Consideration” are to $75,000,000. |
| ● | “Closing” are to the closing of the Transactions. |
| ● | “Closing Date” are to September 20, 2023, the date of Closing. |
| ● | “Code” are to the U.S. Internal Revenue Code of 1986, as amended. |
| ● | “Company” are to Greenfire Resources Ltd., an Alberta corporation. |
| ● | “Company Articles” are to the articles of incorporation of the Company, as may be amended and/or restated from time to time. |
| ● | “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. |
| ● | “Company Board” are to the board of directors of the Company. |
| ● | “Company Bylaws” are to the bylaws of the Company, as may be amended and/or restated from time to time. |
| ● | “Common Shares” are to the common shares in the capital of the Company. |
| ● | “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. |
| ● | “Company Options” means options to purchase the Common Shares granted pursuant to the terms of the Company Incentive Plan. |
| ● | “Company Performance Warrant Plan” are to the amended and restated performance warrant plan of the Company, which amends and restates the Greenfire Equity Plan. |
| ● | “Company Performance Warrants” are to warrants to purchase Common Shares with each such warrant entitling the holder to purchase one the Common Share subject to the terms and conditions of the Company Performance Warrant Plan. |
| ● | “Company Securities” are to the Common Shares and Company Warrants, collectively. |
| ● | “Company Shareholders” are to the holders of the Common Shares. |
| ● | “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. |
| ● | “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. |
viii
| ● | “Consideration” are to, collectively, the Cash Consideration and the Share Consideration. |
| ● | “Court” are to the Alberta Court of King’s Bench. |
| ● | “CRA” are to the Canada Revenue Agency. |
| ● | “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. |
| ● | “Demo GP” are to Hangingstone Demo (GP) Inc. |
| ● | “Demo LP” are to Hangingstone Demo Limited Partnership. |
| ● | “DE Merger Sub” are to DE Greenfire Merger Sub Inc., a Delaware corporation and a direct, wholly-owned subsidiary of the Company. |
| ● | “Demo Asset” are to the Hangingstone Demonstration Facility, a SAGD thermal oil sands production facility in the Athabasca region of Alberta. |
| ● | “diluent” are to lighter viscosity petroleum products that are used to dilute bitumen for transportation in pipelines. |
| ● | “Directors” are to the directors of the Company. |
| ● | “ESG” are to environmental, social and governance. |
| ● | “Exchange Act” are to the U.S. Securities Exchange Act of 1934, as amended. |
| ● | “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. |
| ● | “Expansion Asset” are to the Hangingstone Expansion Facility, a SAGD thermal oil sands production facility in the Athabasca region of Alberta. |
| ● | “Expansion GP” are to Hangingstone Expansion (GP) Inc. |
| ● | “Expansion LP” are to Hangingstone Expansion Limited Partnership. |
| ● | “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. |
| ● | “GAC” are to Greenfire Acquisition Corporation. |
| ● | “GAC HoldCo” are to GAC HoldCo Inc. |
| ● | “GHOPCO” are to Greenfire Hangingstone Operating Corporation. |
| ● | “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. |
ix
| ● | “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). |
| ● | “Greenfire” are to Greenfire Resources Inc., an Alberta corporation. |
| ● | “Greenfire Board” are to the board of directors of Greenfire. |
| ● | “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. |
| ● | “Greenfire Common Shares” are to the common shares in the authorized share capital of Greenfire. |
| ● | “Greenfire Enterprise Value” are to $950,000,000. |
| ● | “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. |
| ● | “Greenfire Employee Shareholders” are to all holders of Greenfire Common Shares other than the Greenfire Founders. |
| ● | “Greenfire Founders” are to Annapurna Limited, Spicelo Limited, Modro Holdings LLC and Allard Services Limited. |
| ● | “Greenfire Net Indebtedness” are to $170,000,000. |
| ● | “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. |
| ● | “Greenfire Performance Warrantholders” are to the holders of the Greenfire Performance Warrants. |
| ● | “Greenfire Pre-Money Equity Value” are to the (A) the Greenfire Enterprise Value minus (B) Greenfire Net Indebtedness. |
| ● | “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. |
| ● | “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. |
| ● | “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. |
| ● | “Hangingstone Facilities” are to, collectively, the Demo Asset and the Expansion Asset. |
| ● | “HEAC” are to HE Acquisition Corporation. |
x
| ● | “Holder” are to a person who is a beneficial owner of the Company Securities immediately following the Business Combination. |
| ● | “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. |
| ● | “IFRS” are to the International Financial Reporting Standards, as issued by the International Accounting Standards Board. |
| ● | “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. |
| ● | “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 Greenfire Shareholders. |
| ● | “IRS” are to the U.S. Internal Revenue Service. |
| ● | “ITA” are to the Income Tax Act (Canada) and the regulations made thereunder as amended from time to time. |
| ● | “JACOS” are to Japan Oil Sands Limited. |
| ● | “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. |
| ● | “JOBS Act” are to the Jumpstart Our Business Startups Act of 2012. |
| ● | “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. |
| ● | “Letter of Credit Facility” are to certain letter of credit facilities with Trafigura Canada General Partnership and certain other parties that provided for revolving or non-revolving credit loans or other arrangements for the purposes of issuing letters of credit. |
| ● | “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 Company Shareholders entered into at the Closing. |
| ● | “MBSC” are to M3-Brigade Acquisition III Corp., a Delaware corporation, prior to the Business Combination. |
| ● | “MBSC Articles” are to the amended and restated certificate of incorporation of MBSC, adopted on October 21, 2021. |
| ● | “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. |
xi
| ● | “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 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 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. |
xii
| ● | “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. |
| ● | “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.” |
| ● | “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 registering the resale of certain securities held by or issuable to certain existing shareholders of MBSC and Greenfire and the PIPE Investors, to be filed by the Company pursuant to the Investor Rights Agreement. |
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| ● | “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. |
| ● | “Treasury Regulations” means the United States Department of the Treasury regulations issued pursuant to the Code. |
| ● | “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 Company 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. |
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PART I
Item 1. Identity of Directors, Senior Management and Advisers
Not applicable.
Item 2. Offer Statistics and Expected Timetable
Not applicable.
Item 3. Key Information
A. [Reserved]
B. Capitalization and Indebtedness
Not applicable.
C. Reasons for the Offer and Use of Proceeds
Not applicable.
D. Risk Factors
Risk Factor Summary
Investing in our securities involves risks. You should carefully consider all of the information set forth in this Annual Report, including the risks described in this section, before making a decision to invest in our securities. Some of the risks related to the Company’s business and industry are summarized below.
| ● | The prices of crude oil, diluted bitumen, non-diluted bitumen and the differentials among various crude oil prices, natural gas and power are volatile, outside of the Company’s control and affect its revenues, profitability, cash flows and future rate of growth. |
| ● | The Company’s SAGD operations are subject to numerous risks, including reservoir performance, operating cost increases and various other factors, could adversely affect the Company’s operating results. |
| ● | The Company markets all of its bitumen production and receives all of its revenue from its Petroleum Marketer and as a result if the Petroleum Marketer faced financial difficulty or has other issues marketing the Company’s bitumen production, it could have a serious impact on the Company’s operations and financial position. |
| ● | If the Company’s capital expenditures relating to debottlenecking its production from the Demo Asset and Expansion Asset do not perform as expected, it could impact the Company’s ability to grow its production. |
| ● | Shortages and volatility of pricing on commodity inputs or 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. |
| ● | There are numerous uncertainties inherent in estimating quantities of reserves and future net revenues to be derived therefrom, including many factors beyond the Company’s control. | |
| ● | Global political events and political decisions made in Canada may adversely affect commodity prices which in turn affect the Company’s cash flow. |
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| ● | The Company’s properties may be subject to actions and opposition by non-governmental agencies. |
| ● | The successful operation of a portion of the Company’s properties is dependent on third parties. |
| ● | The Company may be unable to retain existing suppliers. |
| ● | The Company relies on groundwater licenses, which, if rescinded or the conditions of which are amended, could disrupt its business. |
| ● | 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 may not be able to obtain the regulatory approvals it needs for general operating activities or compliance for decommissioning. |
| ● | 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. |
| ● | Entrance into new industry-related activities or geographical areas could adversely affect the Company’s future operational and financial conditions. |
| ● | 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. |
| ● | Modification to current, or implementation of additional, regulations and the rise of petroleum alternatives may reduce the demand for oil and natural gas and/or increase the Company’s costs and/or delay planned operations. |
| ● | Changes to royalty regimes could adversely affect the profitability of the Company’s operations. |
| ● | 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. |
| ● | 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 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 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’s risk management activities expose it to the risk of financial loss and counter-party risk. |
| ● | Opposition by First Nations groups to the conduct of the Company’s operations, development or exploratory activities may negatively impact the Company. |
| ● | Climate change and other environmental 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. |
| ● | The Company is subject to laws, rules, regulations and policies regarding data privacy and security which are subject to change and reinterpretation, and could result in claims or increased cost of operations and 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 |
2
| ● | Changes to applicable tax laws and regulations or exposure to additional tax liabilities could adversely affect the Company’s business and future profitability. |
| ● | The Company incurs significant increased expenses and administrative burdens as a public company. |
| ● | The Company may identify internal control weaknesses in the future or otherwise fail to develop and maintain an effective system of internal controls, which may result in material misstatements of financial statements and/or the Company’s inability to meet periodic reporting obligations. |
| ● | The Company’s substantial indebtedness could adversely affect the Company’s financial health and a default under any of the Company’s debt instruments could result in the Company being required to repay amounts outstanding thereunder. |
| ● | The Company is a “foreign private issuer” under U.S. securities laws and therefore is exempt from certain requirements applicable to U.S. domestic registrants listed on the NYSE. |
| ● | The Company has a limited operating history, which may not be sufficient to evaluate its business and prospects |
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; |
3
| ● | 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.
4
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.
5
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; |
6
| ● | 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.
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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; |
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| ● | 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.
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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.
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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.
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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.
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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.
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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.
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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.
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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:
| ● | the overall state of the capital markets; |
| ● | the Company’s credit rating (if applicable); |
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| ● | commodity prices; |
| ● | production rates; |
| ● | interest rates; |
| ● | royalty rates; |
| ● | tax burden due to currently applicable tax laws and potential changes in tax laws; and |
| ● | 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.
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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:
| ● | production falls short of the contracted volumes or prices fall significantly lower than projected; |
| ● | there is a widening of price-basis differentials between delivery points for production and the delivery point assumed in the arrangement; |
| ● | 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; |
| ● | counterparties to the arrangements or other price risk management contracts become insolvent or otherwise fail to perform under those arrangements; or |
| ● | 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.
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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.
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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.
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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.
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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.
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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.
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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.
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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:
| ● | 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; |
| ● | expend significant resources to develop or acquire the non-infringing intellectual property; |
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| ● | discontinue processes incorporating the infringing technology; or |
| ● | 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.
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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.
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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$376.4 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 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; |
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| ● | 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.
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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.
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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.
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Risks Related to Ownership of the Common Shares
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 March 26, 2024, the Company’s executive officers, directors and their affiliates, beneficially held approximately 55.5% (including 4,608,131 Common Shares issuable upon exercise of Company Warrants, Company Performance Warrants and Company Awards) 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 December 31, 2023, (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 other Company shareholders party to the Lock-Up Agreement received their Common Shares in exchange for securities of Greenfire for little consideration.
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The last reported sales prices of the Common Shares on the NYSE and TSX on March 25, 2024 was $6.02 and CAD$8.15, 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. 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.
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:
| ● | fluctuations in domestic and international markets for listed securities; |
| ● | 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; |
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| ● | securities issuances by the Company, or share resales by shareholders, or the perception that such issuances or resales may occur; |
| ● | pandemic risk; |
| ● | the nature of the markets in which the Company operates; and |
| ● | 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.
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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; |
| ● | sales of substantial amounts of Common Shares by the Company’s directors, executive officers or significant shareholders, including the 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.
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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 45 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; |
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| ● | 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.
Item 4. Information on the Company
A. 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 entitled “Explanatory Note”.
Following the Business Combination, the Company has continued the business of Greenfire.
Greenfire Corporate History
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 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”).
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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.
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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.
B. Business Overview
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.
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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.
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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.
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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.
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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” in Item 4.D. below. The Company anticipates satisfying these capital commitments with funds from operations.
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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.
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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. The disclosures contained in this section providing oil and gas information are prepared in accordance with FASB Accounting Standards Codification topic 932; Extractive Activities — Oil and Gas. Our financial reporting is prepared in accordance with IFRS.
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 15.1, 15.2 and 15.3 to this Annual Report.
Employees and Training
As at December 31, 2023, the Company had 165 full and part-time employees (with 35 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 171 as at December 31, 2022 (with 39 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.
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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. Subsequent to the fourth quarter of 2023, the Company initiated a planned seven well extended reach Refill drilling program at the Demo Asset, which is anticipated to conclude in second quarter of 2024.
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.
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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.
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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 “Item 5. Operating and Financial Review and Prospects — 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.
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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.”
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
C. 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.
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The following is a chart of our current corporate structure as of the date of this Annual Report:
D. 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” in Item 4.B.
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.
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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 | ||
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Item 4A. Unresolved Staff Comments
None.
Item 5. Operating and Financial Review and Prospects
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. All financial information has been prepared in accordance with IFRS. 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, the “Company,” “we,” or “us” refers to Greenfire Resources Ltd. and its subsidiaries (including Greenfire). “Greenfire,” refers to Greenfire Resources Inc. Certain information called for by this Item 5 with respect to Greenfire and JACOS, including a discussion of the results of operations of Greenfire for the year ended December 31, 2022 compared to the year ended December 31, 2021, and a discussion of results of operations of JACOS for the period from January 1, 2021 to September 17, 2021 to the year ended December 31, 2020, has been reported previously in the Company’s final prospectus filed with the SEC pursuant to Rule 424(b)(3) on February 6, 2024 under the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and is not repeated herein. Such information can be found on EDGAR at https://www.sec.gov/Archives/edgar/data/1966287/000121390024010570/ea192929-424b3_greenfire.htm#b_016.
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. Following the Business Combination (described below), the Company has continued the business of Greenfire. The Company 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 Section 4.A. of this Annual Report. Prior to the acquisition of the Demo Asset in April of 2021, neither Greenfire nor any of its subsidiaries had any material operations.
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. For additional information regarding the Business Combination, please see the section entitled “Explanatory Note” of this Annual Report. The Company had no material operations prior to the Business Combination and following the Business Combination continued the business of Greenfire and its subsidiaries. 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.
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.
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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.
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Non-GAAP Measures
Refer to “—Non-GAAP Measures” for reconciliations and information regarding the following measures and ratios used in this Annual Report: “adjusted EBITDA,” “operating netback,” “adjusted funds flow,” “adjusted free cash flow”,“adjusted working capital,” “net debt,”. “adjusted EBITDA ($/bbl),” “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$/bbl) | 22.05 | 23.65 | 23.08 | 21.41 | ||||||||||||
| Cash provided (used) by operating activities | 25,530 | 17,322 | 86,548 | 164,727 | ||||||||||||
| Adjusted funds flow(1) (2) | 10,517 | 16,902 | 73,206 | 163,926 | ||||||||||||
| Cash provided (used) by investing activities | 18,732 | (17,316 | ) | (12,103 | ) | (63,746 | ) | |||||||||
| Capital expenditures | 19,413 | 12,361 | 33,428 | 39,592 | ||||||||||||
| Adjusted free cash flow(1) | (8,896 | ) | 4,541 | 39,778 | 124,334 | |||||||||||
| Net income (loss) and comprehensive income (loss) | (4,659 | ) | 87,995 | (135,671 | ) | 131,698 | ||||||||||
| Per share – basic(2) | (0.07 | ) | 1.80 | (2.49 | ) | 2.69 | ||||||||||
| Per share – diluted(2) | (0.07 | ) | 1.25 | (2.49 | ) | 1.88 | ||||||||||
| Adjusted EBITDA(1) | 23,434 | 32,528 | 117,316 | 218,033 | ||||||||||||
| (1) | Non-GAAP measures do not have any standardized meaning prescribed by IFRS and may not be comparable with the calculation of similar measures presented by other entities. Refer to the “Non-GAAP Measures” section in this MD&A for further information. |
| (2) | For the year ended December 31, 2022, the Company’s basic and diluted earnings per share is the net income per common share of Greenfire and the weighted average common shares outstanding has been scaled by the applicable exchange ratio following the completion of the Business Combination. |
| (3) | As at December 31, 2023. |
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Selected Liquidity and Balance Sheet Highlights
| December 31, | December 31, | |||||||
| (CAD$ 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 | ||||||||||||
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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 | ||||||||||||
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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.
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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 | |||||||||||||