Exhibit 99.3
FORM 51-101F1
STATEMENT OF RESERVES DATA
AND OTHER OIL AND GAS INFORMATION
AS OF December 31, 2023
DATED MARCH 20, 2024
TABLE OF CONTENTS
| | | Page |
| | | |
| GLOSSARY OF TERMS | | 1 |
| EXPLANATORY NOTE | | 3 |
| ABBREVIATIONS AND CONVERSIONS | | 3 |
| ABBREVIATIONS | | 3 |
| CONVERSIONS | | 4 |
| CAUTION REGARDING USE OF BARRELS OF OIL EQUIVALENT (BOES) | | 4 |
| DISCLOSURE OF RESERVES DATA AND ADVISORIES | | 4 |
| DISCLOSURE OF RESERVES DATA | | 4 |
| ADVISORIES | | 5 |
| STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION | | 7 |
| APPENDIX A – REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE | | 20 |
| APPENDIX B – REPORT ON RESERVES DATA BY THE INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR | | 21 |
Glossary of Terms
The following words and phrases have the following meanings, unless the context otherwise requires:
“Demo Asset” means the Hangingstone Demonstration Facility, a SAGD thermal oil sands production facility in the Athabasca region of Alberta;
“developed non-producing reserves” are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown;
“developed producing reserves” are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty;
“developed reserves” are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing;
“development costs” means costs incurred to obtain access to reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas from reserves. More specifically, development costs, including applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:
| (a) | gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines and power lines, to the extent necessary in developing the reserves; |
| (b) | drill and equip development wells, development type stratigraphic test wells and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment and wellhead assembly; |
| (c) | acquire, construct and install production facilities such as flow lines, separators, treaters, heaters, manifolds, measuring devices and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems; and |
| (d) | provide improved recovery systems; |
“exploration costs” means costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects that may contain oil and gas reserves, including costs of drilling exploratory wells and exploratory type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to as “prospecting costs”) and after acquiring the property. Exploration costs, which include applicable operating costs of support equipment and facilities and other costs of exploration activities, are:
| (a) | costs of topographical, geochemical, geological and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews and others conducting those studies (collectively sometimes referred to as “geological and geophysical costs”); |
| (b) | costs of carrying and retaining unproved properties, such as delay rentals, taxes (other than income and capital taxes) on properties, legal costs for title defence, and the maintenance of land and lease records; |
| (c) | dry hole contributions and bottom hole contributions; |
| (d) | costs of drilling and equipping exploratory wells; and |
| (e) | costs of drilling exploratory type stratigraphic test wells; |
“Expansion Asset” means the Hangingstone Expansion Facility, a SAGD thermal oil sands production facility in the Athabasca region of Alberta;
“forecast prices and costs” means future prices and costs that are:
| (a) | generally accepted as being a reasonable outlook of the future; or |
| (b) | if, and only to the extent that, there are fixed or presently determinable future prices or costs to which Greenfire is legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs rather than the prices and costs referred to in subparagraph (a); |
“Greenfire” or the “Company” means Greenfire Resources Ltd. and/or its consolidated subsidiaries, as the context may require;
“Greenfire Reserves Report” means the report of McDaniel dated March 20, 2024 evaluating the bitumen reserves of Greenfire as at December 31, 2023;
“gross” means:
| (a) | in relation to a reporting issuer’s interest in production or reserves, its “company gross reserves”, which are the reporting issuer’s working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of the reporting issuer; |
| (b) | in relation to wells, the total number of wells in which a reporting issuer has an interest; and |
| (c) | in relation to properties, the total area of properties in which a reporting issuer has an interest; |
“Hangingstone Facilities” are to, collectively, the Demo Asset and the Expansion Asset;
“JACOS” means Japan Canada Oil Sands Limited;
“McDaniel” means McDaniel & Associates Consultants Ltd., independent petroleum engineers of Calgary, Alberta;
“net” means:
| (a) | in relation to a reporting issuer’s interest in production or reserves, the reporting issuer’s working interest (operating or non-operating) share after deduction of royalty obligations, plus the reporting issuer’s royalty interests in production or reserves; |
| (b) | in relation to a reporting issuer’s interest in wells, the number of wells obtained by aggregating the reporting issuer’s working interest in each of its gross wells; and |
| (c) | in relation to a reporting issuer’s interest in a property, the total area in which the reporting issuer has an interest multiplied by the working interest owned by the reporting issuer; |
“NI 51-101” means National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities;
“possible reserves” are those additional reserves that are less certain to be recovered than probable resources. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves;
“probable reserves” are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves;
“proved reserves” are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves;
“reserves” are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on: (i) analysis of drilling, geological, geophysical and engineering data; (ii) the use of established technology; and (iii) specified economic conditions, which are generally accepted as being reasonable and shall be disclosed. Reserves are classified according to the degree of certainty associated with the estimates;
“SAGD” means steam-assisted gravity drainage, an in-situ thermal oil production extraction technique;
“Statement” means this statement of reserves data and other oil and gas information of Greenfire as at December 31, 2023; and
“undeveloped reserves” are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves category (proved, probable, possible) to which they are assigned.
Certain other terms used herein but not defined herein are defined in NI 51-101 and, unless the context otherwise requires, shall have the same meanings herein as in NI 51-101. All dollar amounts stated herein are expressed in Canadian dollars.
EXPLANATORY NOTE
Greenfire Resources Ltd. (“GRL”) is the parent corporation of Greenfire Resources Operating Corporation, and the corporate structure of Greenfire, as it is currently constituted, is the result of: (i) an amalgamation effective as of January 1, 2024, pursuant to which Greenfire Resources Operating Corporation and Greenfire Resources Inc. (“GRI”) amalgamated in accordance with the provisions of the Business Corporations Act (Alberta), with the surviving corporation continuing as “Greenfire Resources Operating Corporation” and as a wholly subsidiary of GRL; (ii) the completion of the transactions contemplated by the business combination agreement, dated December 14, 2022, as amended from time to time, by and between M3-Brigade Acquisition III Corp, GRI, GRL, DE Greenfire Merger Sub Inc. and 2476276 Alberta ULC, which were completed on September 20, 2023; and (iii) a number of other transactions that included: (A) the acquisition of the Demo Asset out of the insolvency proceedings of an unaffiliated corporation named Greenfire Hangingstone Operating Corporation; (ii) a series of incorporations, amalgamations and other reorganization transactions; and (iii) the acquisition of JACOS (which held the Expansion Asset) (the “JACOS Acquisition”).
For more information, see the documents publicly available on Greenfire’s SEDAR+ profile at www.sedarplus.ca and on Greenfire’s EDGAR (as defined below) profile at www.sec.gov/edgar
Abbreviations and Conversions
Abbreviations
The abbreviations set forth below have the following meanings:
| Oil and Natural Gas Liquids | | Natural Gas |
| Bbl(s) | Barrel(s) | | Mcf | thousand cubic feet |
| bbls/d | barrels per day | | GJ | gigajoule |
| Mbbl | thousand barrels | | | |
| boe | barrels of oil equivalent | | | |
| MMboe | million barrels of oil equivalent | | | |
| Other | | |
| WTI | | West Texas Intermediate crude oil, a benchmark oil price determined at Cushing, Oklahoma |
| M$ | | thousands of dollars |
| MM$ | | millions of dollars |
Conversions
The following table sets forth certain Standard Imperial Units and International System of Units conversions:
| From | | To | | Multiply By |
| Mcf | | cubic metres | | 28.174 |
| Mcf | | GJ | | 1.055 |
| cubic metres | | cubic feet | | 35.494 |
| bbls | | cubic metres | | 0.159 |
| acres | | hectares | | 0.405 |
Caution Regarding Use of Barrels of Oil Equivalent (BOEs)
BOEs/boes may be misleading, particularly if used in isolation. A boe conversion ratio of six Mcf to one bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. As the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
Disclosure of Reserves Data and Advisories
Disclosure of Reserves Data
This Statement is prepared as of March 20, 2024 and is based upon an evaluation by McDaniel dated March 20, 2024 with an effective date of December 31, 2023 contained in the Greenfire Reserves Report. This Statement summarizes the bitumen reserves of Greenfire and the future net revenues and net present values for such reserves using forecast prices and costs as at December 31, 2023. All of Greenfire’s reserves are in Canada and, specifically, in the Province of Alberta.
The crude oil and natural gas reserve estimates presented in the Greenfire Reserves Report are based on the guidelines contained in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) and the reserve definitions contained in NI 51-101 and the COGE Handbook. A summary of those definitions are set forth under “Glossary of Terms” above. McDaniel was engaged to provide evaluations of proved and proved plus probable reserves.
The board of directors of Greenfire has reviewed and approved the Greenfire Reserves Report. The Report of Management and Directors on Oil and Gas Disclosure and the Report on Reserves Data by Independent Qualified Reserves Evaluator or Auditor are attached as Appendix A and Appendix B hereto, respectively.
All evaluations of future revenue contained in the Greenfire Reserves Report are after the deduction of royalties, operating costs, development costs and abandonment, decommission and reclamation costs. It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. There are numerous uncertainties inherent in estimating quantities of bitumen reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth in this Statement are estimates only. The recovery and reserve estimates of the bitumen reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual bitumen reserves may be greater than or less than the estimates provided herein.
In general, estimates of economically recoverable oil and gas reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially from actual results. For those reasons, among others, estimates of the economically recoverable oil and gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves may vary and such variations may be material. The actual production, revenues, taxes and development and operating expenditures with respect to the reserves associated with Greenfire’s properties may vary from the information presented herein and such variations could be material. In addition, there is no assurance that the forecast price and cost assumptions contained in the Greenfire Reserves Report will be attained and variances could be material.
For reserves calculated under United States Securities and Exchange Commission (“SEC”) requirements, please refer to Greenfire’s Form 20-F which will be filed on the SEC’s Electronic Data Gathering Analysis and Retrieval system (“EDGAR”) at www.sec.gov/edgar and filed on Greenfire’s SEDAR+ profile on www.sedarplus.ca. As a public company in the United States, Greenfire has and is expected to continue to disclose reserves information in filings with the SEC 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. There are significant differences to the type of volumes disclosed and the basis from which the volumes are economically determined under the SEC requirements and NI 51-101, and the difference between the reported numbers under the two disclosure standards can, therefore, be material. For example, the U.S. standards require United States oil and gas reporting companies, in their filings with the SEC, to disclose only proved reserves after the deduction of royalties and production due to others but permits the optional disclosure of probable and possible reserves in accordance with the SEC’s definitions. Additionally, the COGE Handbook and NI 51-101 require disclosure of reserves and related future net revenue estimates based on forecast prices and costs, whereas the U.S. standards require that reserves and related future net revenue be estimated using average prices for the previous 12 months and that the standardized measure reflect discounted future net income taxes related to Greenfire’s operations. In addition, the COGE Handbook and NI 51-101 permit the presentation of reserves estimates on a “company gross” basis, representing Greenfire’s working interest share before deduction of royalties, whereas the U.S. standards require the presentation of net reserve estimates after the deduction of royalties and similar payments. There are also differences in the technical reserves estimation standards applicable under NI 51-101 and, pursuant thereto, the COGE Handbook, and those applicable under the U.S. Standards. NI 51-101 requires that proved undeveloped reserves be reviewed annually for retention or reclassification if development has not proceeded as previously planned, while the U.S. Standards specify a five-year limit after initial booking for the development of proved undeveloped reserves. Finally, the SEC prohibits disclosure of oil and gas resources in SEC filings, including contingent resources, whereas Canadian securities regulatory authorities allow disclosure of oil and gas resources other than reserves, as well as reserves. The foregoing is not an exhaustive summary of Canadian or U.S. reserves reporting requirements.
Advisories
Certain information regarding Greenfire set forth in this Statement contains forward-looking information or statements as defined in applicable securities laws (collectively, “forward-looking statements” or “statements”) that involve substantial known and unknown risks and uncertainties. The use of any of the words “plan”, “expect”, “prospective”, “project”, “intend”, “believe”, “should”, “anticipate”, “estimate” or other similar words, or statements that certain events or conditions “may” or “will” occur are intended to identify forward-looking statements. Such statements represent Greenfire’s internal projections, estimates or beliefs, which are only predictions and actual events or results may differ materially. Although management believes that the expectations reflected in the forward-looking statements are reasonable, it cannot guarantee future results, levels of activity, performance or achievement since such expectations are inherently subject to significant business, economic, competitive, political and social uncertainties and contingencies. Many factors could cause Greenfire’s actual results to differ materially from those expressed or implied in any forward-looking statements made by, or on behalf of, Greenfire.
More particularly, this Statement may contain, without limitation, statements pertaining to the following: bitumen production levels; projections of commodity prices and costs; future cash flows from reserves; tax horizon (including the expectation that no income taxes will be required to be paid by Greenfire until 2027); expected abandonment and reclamation costs, including the amount thereof and the timing expected to be paid; treatment under governmental regulatory regimes including but not limited to royalties, environmental and taxation; timing of the development of proved undeveloped reserves and probable undeveloped reserves and investment in connection therewith; Greenfire’s development plans over the next several years, including with respect to drilling and other plans to develop Greenfire’s assets; future development costs and that Greenfire expects to use a combination of internally generated cash from operations, working capital and the issuance of new equity or debt where and when it believes appropriate to fund future development costs; and Greenfire’s use of certain financial instruments to hedge exposure to commodity price fluctuations.
Forward-looking statements are based on the beliefs of the Company’s management, as well as on assumptions, which management believes to be reasonable based on information available at the time such statements were made. In addition to other assumptions set out herein, the forward-looking statements contained herein are based on the following assumptions: Greenfire’s ability to compete with other companies; the anticipated future financial or operating performance of the Company; the expected results of operations; assumptions as to future drilling results; assumptions as to costs and commodity prices; the timing and amount of funding required to execute the Company’s business plans; assumptions about future capital expenditures; the effect on the Company of any changes to existing or new legislation or policy or government regulation; the length of time required to obtain permits, certifications and approvals; the availability of labor; estimated budgets; assumptions about future interest and currency exchange rates; requirements for additional capital; the timing and possible outcome of regulatory and permitting matters; goals; strategies; future growth; and the adequacy of financial resources. However, by their nature, forward-looking statements are based on assumptions and involve known and unknown risks, uncertainties and other factors which may cause the actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements.
Forward-looking statements are subject to a variety of risks, uncertainties and other factors which could cause actual results, performance or achievements to differ from those expressed or implied by the forward-looking statements, including, without limitation, a decline in oil prices or widening of differentials between various crude oil prices; lower than expected reservoir performance, including, but not limited to, lower oil production rates; the inability to recognize continued or increased efficiencies from the Company’s production enhancement program and processing plant enhancements, debottlenecking and brownfield expansions; reduced access to or an increase in the cost of diluent; an increase in the cost of natural gas or electricity; the reliability and maintenance of Greenfire’s facilities; supply chain disruption and risks of increases costs relating to inflation; the safety and reliability of pipelines and trucking services that transport Greenfire’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; the availability and cost of insurance and the inability to insure against certain types of losses; severe weather or catastrophic events such as fires, droughts, lightning, earthquakes, extreme cold weather, storms or explosions; seasonal weather patterns and the corresponding effects of the spring thaw on equipment on Greenfire’s properties; the availability of pipeline capacity and other transportation and storage facilities for the Company’s bitumen blend; the cost of chemicals used in Greenfire’s operations, including, but not limited to, in connection with water and/or oil treatment facilities; the availability of and access to drilling equipment and key personnel; risks of cybersecurity threats including the possibility of potential breakdown, invasion, virus, cyber-attack, cyber-fraud, security breach, and destruction or interruption of the Company’s information technology systems; Canadian heavy and light oil export capacity constraints and the resulting impact on realized pricing; the impact of global wars and conflicts on global stability, commodity prices and the world economy, changes in the political landscape and/or legal, tax, royalty and regulatory regimes in Canada, and elsewhere; the cost of compliance with applicable regulatory regimes, including, but not limited to, environmental regulation, if any; the ability to attract or access capital as a result of changing investor priorities and trends, including as a result of climate change, environmental, social and governance initiatives, the adoption of decarbonization policies and the general stigmatization of the oil and gas industry; hedging risks; variations in foreign exchange and interest rates; risks related to the Company’s indebtedness; failure to accurately estimate abandonment and reclamation costs; the potential for management estimates and assumptions to be inaccurate; and general economic, market and business conditions in Canada, the United States and globally.
You should carefully consider all of the risks and uncertainties described in the “Risk Factors” section of the Company’s final non-offering prospectus dated February 2, 2024, which is available on SEDAR+ at www.sedarplus.ca and registration statement on Form F-1, initially filed with the United States Securities and Exchange Commission (the “SEC”) on October 10, 2023, as amended on December 1, 2023, and January 22, 2024 and other documents filed by Greenfire from time to time with the SEC. The lists of risk factors set out in this Statement or in the Company’s other public disclosure documents are not exhaustive of the factors that may affect any forward-looking statements of the Company. Forward-looking statements are statements about the future and are inherently uncertain. Actual results could differ materially from those projected in the forward-looking statements as a result of the matters set out in this Statement generally and certain economic and business factors, some of which may be beyond the control of the Company. In addition, the global financial and credit markets have experienced significant debt and equity market and commodity price volatility which could have a particularly significant, detrimental and unpredictable effect on forward-looking statements. The Company does not intend, and does not assume any obligation, to update any forward-looking statements, other than as required by applicable law. For all of these reasons, the Company’s securityholders should not place undue reliance on forward-looking statements.
Statement of Reserves Data and Other Oil and Gas Information
This Statement of Greenfire’s reserves data and other oil and gas information set forth below is dated December 31, 2023. The effective date of the statement of reserves data and other oil and gas information set forth below is December 31, 2023 and the preparation date is March 20, 2024. All of Greenfire’s reserves are in Canada and, specifically, in the Province of Alberta.
In certain of the tables set forth below, the columns may not add due to rounding. All dollar amounts in the tables below are expressed in Canadian dollars.
Reserves Data (Forecast Prices and Costs)
SUMMARY OF OIL AND GAS RESERVES
AS OF DECEMBER 31, 2023
FORECAST PRICES AND COSTS
| | Bitumen | |
| Reserve Category | | Gross(1) (Mbbl) | | | Net(2) (Mbbl) | |
| PROVED | | | | | | |
| Developed Producing | | | 30,886 | | | | 27,809 | |
| Undeveloped | | | 152,396 | | | | 122,465 | |
| TOTAL PROVED | | | 183,282 | | | | 150,273 | |
| PROBABLE | | | 54,396 | | | | 38,441 | |
| TOTAL PROVED PLUS PROBABLE | | | 237,679 | | | | 188,714 | |
Notes:
| (1) | Gross reserves are working interest reserves before royalty deductions. |
| (2) | Net reserves are working interest reserves after royalty deductions plus royalty interest reserves. |
SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE
AS OF DECEMBER 31, 2023
FORECAST PRICES AND COSTS
| | | Before Income Taxes Discounted at (%/year) | | | After Income Taxes Discounted at (%/year) | | | Unit Value Before Income Tax Discounted at 10%/ year(1) | |
| Reserves Category | | 0 (MM$) | | | 5 (MM$) | | | 10 (MM$) | | | 15 (MM$) | | | 20 (MM$) | | | 0 (MM$) | | | 5 (MM$) | | | 10 (MM$) | | | 15 (MM$) | | | 20 (MM$) | | | ($/bbl) | |
| PROVED | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Developed Producing | | | 851 | | | | 809 | | | | 746 | | | | 686 | | | | 633 | | | | 851 | | | | 809 | | | | 746 | | | | 686 | | | | 633 | | | | 24.15 | |
| Developed Non-Producing | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | |
| Undeveloped | | | 3,968 | | | | 2,147 | | | | 1,277 | | | | 830 | | | | 577 | | | | 2,915 | | | | 1,625 | | | | 986 | | | | 652 | | | | 460 | | | | 8.38 | |
| TOTAL PROVED | | | 4,819 | | | | 2,956 | | | | 2,023 | | | | 1,515 | | | | 1,209 | | | | 3,765 | | | | 2,434 | | | | 1,732 | | | | 1,337 | | | | 1,093 | | | | 11.04 | |
| PROBABLE | | | 2,034 | | | | 779 | | | | 401 | | | | 264 | | | | 202 | | | | 1,458 | | | | 576 | | | | 309 | | | | 211 | | | | 167 | | | | 7.37 | |
| TOTAL PROVED PLUS PROBABLE | | | 6,853 | | | | 3,735 | | | | 2,423 | | | | 1,779 | | | | 1,412 | | | | 5,224 | | | | 3,010 | | | | 2,041 | | | | 1,549 | | | | 1,259 | | | | 10.20 | |
Notes:
| (1) | The unit values are based on net reserve volumes. |
| (2) | Net present values prepared by McDaniel in the evaluation of Greenfire’s properties are calculated by considering sales of bitumen reserves and other income. After tax net present values prepared by McDaniel in the evaluation of Greenfire’s properties are calculated by considering the foregoing factors as well as appropriate income tax calculations, current federal tax regulations and including prior tax pools for Greenfire (at the corporate level). |
TOTAL FUTURE NET REVENUE (UNDISCOUNTED)
AS OF DECEMBER 31, 2023
FORECAST PRICES AND COSTS
| Reserves Category | | Revenue(1) (M$) | | | Royalties(2) (M$) | | | Operating Costs (M$) | | | Development Costs
(M$) | | | Abandonment and Reclamation Costs
(M$)(3) | | | Future Net Revenue Before Income Taxes (M$) | | | Income Taxes (M$) | | | Future Net Revenue After Income Taxes (M$) | |
| Proved Reserves | | | 12,551,632 | | | | 2,380,944 | | | | 3,769,655 | | | | 1,343,870 | | | | 238,338 | | | | 4,818,825 | | | | 1,053,394 | | | | 3,765,431 | |
| Proved Plus Probable Reserves | | | 17,185,654 | | | | 3,717,829 | | | | 4,798,592 | | | | 1,565,109 | | | | 251,205 | | | | 6,852,919 | | | | 1,629,094 | | | | 5,223,824 | |
Notes:
| (1) | Includes all product revenues and other revenues as forecast. |
| (2) | Royalties include any net profits interests paid. |
| (3) | Abandonment and reclamation costs include but are not limited to items such as: producing wells, suspended wells, service wells, gathering systems, facilities, and surface land development. |
FUTURE NET REVENUE BY PRODUCT TYPE
AS OF DECEMBER 31, 2023
FORECAST PRICES AND COSTS
| Reserves Category | | Product Type | | Future Net Revenue Before Income Taxes (Discounted At 10%/Year) (M$) | | | Unit Value(1)
(Units as noted) | |
| Proved Reserves | | Bitumen | | | 2,023 | | | $ | 13.46/bbl | |
| Proved Plus Probable Reserves | | Bitumen | | | 2,423 | | | $ | 12.84/bbl | |
Note:
| (1) | Unit values are calculated using the 10% discount rate divided by the major product type net reserves for each group. |
Pricing Assumptions
The future net revenues and net present values presented in the Greenfire Reserves Report were calculated using the average forecast price and costs of Sproule Associates Limited (“Sproule”), McDaniel and GLJ Ltd. (“GLJ”) as of December 31, 2023 for the future crude oil, natural gas and natural gas product prices.
Sproule, McDaniel, and GLJ have prepared their December 31, 2023, price and market forecasts after a comprehensive review of information. Information sources include numerous government agencies, industry publications, Canadian oil refiners and natural gas marketers. The forecasts presented herein are based on an informed interpretation of currently available data. While these forecasts are considered reasonable at this time, users of these forecasts should understand the inherent high uncertainty in forecasting any commodity or market. These forecasts will be revised periodically as market, economic and political conditions change. These future revisions may be significant.
SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS(1)
AS OF DECEMBER 31, 2023
FORECAST PRICES AND COSTS(1)
The forecast cost and price assumptions assume increases in wellhead selling prices and take into account inflation with respect to future operating and capital costs. The forecast cost and price assumptions utilized in the Greenfire Reserves Report were as follows:
| | | Crude Oil | | | | | | | |
| Year | | WTI Crude Oil ($US/bbl) | | | Brent Crude Oil ($US/bbl) | | | Edmonton Light Crude Oil ($/bbl) | | | Alberta Bow River Hardisty Crude Oil ($/bbl) | | | Western Canadian Select Crude Oil ($/bbl) | | | Alberta Heavy Crude Oil ($/bbl) | | | Sask Cromer Medium Crude Oil ($/bbl) | | | Inflation(2) % | | | Exchange Rate(3) $US/$CAN | |
| Forecast(1) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2024 | | | 73.67 | | | | 78.00 | | | | 92.91 | | | | 77.44 | | | | 76.74 | | | | 69.01 | | | | 88.03 | | | | 0.0 | | | | 0.752 | |
| 2025 | | | 74.98 | | | | 79.18 | | | | 95.04 | | | | 80.48 | | | | 79.77 | | | | 71.90 | | | | 90.02 | | | | 2.0 | | | | 0.752 | |
| 2026 | | | 76.14 | | | | 80.36 | | | | 96.07 | | | | 81.84 | | | | 81.12 | | | | 72.78 | | | | 90.95 | | | | 2.0 | | | | 0.755 | |
| 2027 | | | 77.66 | | | | 81.79 | | | | 97.99 | | | | 83.61 | | | | 82.88 | | | | 74.41 | | | | 92.77 | | | | 2.0 | | | | 0.755 | |
| 2028 | | | 79.22 | | | | 83.41 | | | | 99.95 | | | | 85.78 | | | | 85.04 | | | | 76.56 | | | | 94.63 | | | | 2.0 | | | | 0.755 | |
| 2029 | | | 80.80 | | | | 85.09 | | | | 101.94 | | | | 87.49 | | | | 86.74 | | | | 78.10 | | | | 96.52 | | | | 2.0 | | | | 0.755 | |
| 2030 | | | 82.42 | | | | 86.80 | | | | 103.98 | | | | 89.24 | | | | 88.47 | | | | 79.67 | | | | 98.45 | | | | 2.0 | | | | 0.755 | |
| 2031 | | | 84.06 | | | | 88.52 | | | | 106.06 | | | | 91.01 | | | | 90.24 | | | | 81.27 | | | | 100.42 | | | | 2.0 | | | | 0.755 | |
| 2032 | | | 85.74 | | | | 90.29 | | | | 108.18 | | | | 92.83 | | | | 92.04 | | | | 82.90 | | | | 102.43 | | | | 2.0 | | | | 0.755 | |
| 2033 | | | 87.46 | | | | 92.10 | | | | 110.35 | | | | 94.69 | | | | 93.89 | | | | 84.57 | | | | 104.48 | | | | 2.0 | | | | 0.755 | |
| 2034 | | | 89.21 | | | | 93.94 | | | | 112.56 | | | | 96.58 | | | | 95.77 | | | | 86.26 | | | | 106.57 | | | | 2.0 | | | | 0.755 | |
| 2035 | | | 90.99 | | | | 95.82 | | | | 114.81 | | | | 98.52 | | | | 97.68 | | | | 87.99 | | | | 108.70 | | | | 2.0 | | | | 0.755 | |
| 2036 | | | 92.81 | | | | 97.74 | | | | 117.10 | | | | 100.49 | | | | 99.64 | | | | 89.75 | | | | 110.87 | | | | 2.0 | | | | 0.755 | |
| 2037 | | | 94.67 | | | | 99.69 | | | | 119.45 | | | | 102.50 | | | | 101.63 | | | | 91.54 | | | | 113.09 | | | | 2.0 | | | | 0.755 | |
| 2038 | | | 96.56 | | | | 101.69 | | | | 121.83 | | | | 104.55 | | | | 103.66 | | | | 93.37 | | | | 115.35 | | | | 2.0 | | | | 0.755 | |
| Thereafter | | | | | | | | | | | | | | | Escalation Rate 2%/yr | | | | | | | | | | | | | |
Notes:
| (1) | Calculated using the average forecast price and costs of Sproule, McDaniel and GLJ as of December 31, 2023 for the future crude oil, natural gas and natural gas product prices. |
| (2) | Inflation rates for costs. |
| (3) | The exchange rate used to generate the benchmark reference prices in this table. |
Weighted average historical price realized by Greenfire for the year ended December 31, 2023, was $73.91/bbl for bitumen.
Reserves Reconciliation
RECONCILIATION OF GROSS RESERVES BY PRODUCT TYPE
FORECAST PRICES AND COSTS
| | | Bitumen | |
| FACTORS | | Proved (Mbbl) | | | Probable (Mbbl) | | | Proved Plus Probable (Mbbl) | |
| December 31, 2022 | | | 183,367 | | | | 56,059 | | | | 239,426 | |
| Extensions & Improved Recovery(1) | | | 6,797 | | | | 2,173 | | | | 8,970 | |
| Technical Revisions(2) | | | (444 | ) | | | (3,836 | ) | | | (4,279 | ) |
| Discoveries | | | - | | | | - | | | | - | |
| Acquisitions | | | - | | | | - | | | | - | |
| Dispositions | | | - | | | | - | | | | - | |
| Economic Factors | | | - | | | | - | | | | - | |
| Production | | | (6,438 | ) | | | - | | | | (6,438 | ) |
| December 31, 2023 | | | 183,282 | | | | 54,396 | | | | 237,679 | |
Notes:
| (1) | Extensions are due to the inclusion of additional undeveloped wells at the Demo property that were not previously included in reserves. |
| (2) | Technical revisions are associated with the decommissioning of production from existing well-bores that are to be re-drilled as part of the upcoming drilling program, as well as changes to the future development plan. |
Additional Information Relating to Reserves Data
Undeveloped Reserves
Undeveloped reserves are attributed by McDaniel in accordance with standards and procedures contained in the COGE Handbook. Proved undeveloped reserves are those reserves that can be estimated with a high degree of certainty and are expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production. Probable undeveloped reserves are those reserves that are less certain to be recovered than proved reserves and are expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production. Proved and probable undeveloped reserves have been assigned in accordance with engineering and geological practices as defined under NI 51-101.
Proved and Probable Undeveloped Reserves
The following tables set forth the proved undeveloped reserves and the probable undeveloped bitumen reserves that were first attributed to Greenfire’s assets for the years ended December 31, 2021, 2022 and 2023. Greenfire acquired the Demo Asset and Expansion Asset in 2021 and did not have any oil and gas properties in the year ended December 31, 2020. All of Greenfire’s proved undeveloped reserves and the probable undeveloped reserves are located in the Province of Alberta.
There are a number of factors that could result in delayed or cancelled development, including the following: (i) changing economic conditions (due to commodity pricing, operating and capital expenditure fluctuations); (ii) changing technical conditions (including production anomalies, such as facility bottlenecks or accelerated depletion); (iii) a larger development program may need to be spread out over several years to optimize capital allocation and facility utilization; and (iv) surface access issues (including those relating to land owners, weather conditions and regulatory approvals). See “Disclosure of Reserves Data and Advisories – Advisories” in this Statement.
Proved Undeveloped Reserves
| | | Bitumen
(Mbbl) | |
| Year | | First Attributed | |
| Prior thereto | | - | |
| 2021 | | | 148,007 | |
| 2022 | | | - | |
| 2023 | | | 6,797 | |
Proved undeveloped reserves have been assigned in areas where the reserves can be estimated with a high degree of certainty. In most instances, proved undeveloped reserves will be assigned on lands immediately offsetting existing producing wells within the same accumulation or pool. The Greenfire Reserves Report has assigned 152.4 MMboe of proved undeveloped reserves.
Development of the proved undeveloped reserves is expected to occur over the next 32 years. Timing of the investment and the desired pace of development will depend to a large extent on economic conditions, including, in particular, world commodity prices.
Probable Undeveloped Reserves
| | | Bitumen
(Mbbl) | |
| Year | | First Attributed | |
| Prior thereto | | | - | |
| 2021 | | | 48,229 | |
| 2022 | | | - | |
| 2023 | | | 2,173 | |
Probable undeveloped reserves have been assigned in areas where the reserves can be estimated with less certainty. It is equally likely that the actual remaining quantities recovered will be greater or less than the proved plus probable reserves. In most instances probable undeveloped reserves have been assigned on lands in the area with existing producing wells but there is some uncertainty as to whether they are directly analogous to the producing accumulation or pool. The Greenfire Reserves Report has assigned 48 MMboe of probable undeveloped reserves.
Development of the probable undeveloped reserves is expected to occur over the next 37 years. Timing of the investment and the desired pace of development will depend to a large extent on performance of new and existing wells and economic conditions, including, in particular, world commodity prices.
See “Statement of Reserves Data and Other Oil and Gas Information – Other Oil and Natural Gas Information – Principal Properties” and “Statement of Reserves Data and Other Oil and Gas Information – Additional Information Related to Reserves Data – Future Development Costs” for a description of Greenfire’s exploration and development plans and expenditures.
Significant Factors or Uncertainties
The process of evaluating reserves is inherently complex. It requires significant judgments and decisions based on available geological, geophysical, engineering and economic data. These estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change. The reserve estimates contained herein are based on current production forecasts, prices and economic conditions and other factors and assumptions that may affect the reserve estimates and the present worth of the future net revenue therefrom. These factors and assumptions include, among others: (i) historical production in the area compared with production rates from analogous producing areas; (ii) initial production rates; (iii) production decline rates; (iv) ultimate recovery of reserves; (v) success of future development activities; (vi) marketability of production; (vii) effects of government regulations; and (viii) other government levies imposed over the life of the reserves. Although every reasonable effort is made to ensure that reserve estimates are accurate, reserve estimation is an inferential science. As a result, subjective decisions, new geological or production information and a changing environment may impact these estimates.
Greenfire has a significant amount of proved undeveloped and probable undeveloped reserves assigned to its properties. As circumstances change and additional data becomes available, reserve estimates also change. Estimates are reviewed and revised, either upward or downward, as warranted by new information. Revisions are often required due to changes in well performance, prices, economic conditions and government restrictions. Revisions to reserve estimates can arise from changes in year-end prices, reservoir performance and geologic conditions or production. These revisions can be either positive or negative. Degradation in future commodity price forecasts relative to the forecast in the Greenfire Reserves Report can also have a negative impact on the economics and timing of development of undeveloped reserves, unless significant reduction in the future costs of development are realized.
Other than the foregoing, Greenfire does not anticipate any significant economic factors or significant uncertainties that may affect any particular components of this statement of reserves data and other oil and gas information. However, reserves can be affected significantly by fluctuations in product pricing, capital expenditures, operating costs, royalty regimes and well performance that are beyond Greenfire’s control. See “Disclosure of Reserves Data and Advisories – Advisories” in this Statement.
Abandonment and Reclamation Costs
The Company follows International Financial Reporting Standards to account for and report the estimated cost of future site abandonment and reclamation. This standard requires liability recognition for retirement obligations associated with long-lived assets, which would include abandonment of wells and related facilities, natural gas wells and related facilities, removal of equipment from leased acreage and returning such land to a condition equivalent to its original condition. Under the standard, the estimated cost of each decommissioning obligation is recorded in the period a well or related asset is drilled, constructed or acquired. The obligation is estimated using the present value of the estimated future cash outflows to abandon the asset at the Company’s credit-adjusted risk-free rate. The obligation is reviewed regularly by management based upon current regulations, costs, technologies and industry standards. The discounted obligation is recognized as a liability and is accreted against income until it is settled or the property is sold and is included as a component of net finance expense. Actual restoration expenditures are charged to the accumulated obligation as incurred.
The Company’s decommissioning obligation is the estimated cost of future abandonment and reclamation of the Company’s existing long-lived assets. As of December 31, 2023, the estimated total undiscounted amount required to settle the decommissioning obligations in respect of all the Company’s facilities and wells, net of estimated salvage recoveries, was $206.5 million. This obligation is estimated to be settled in periods up to 2071. The discounted present value of this amount is $8.4 million as reported in the financial statements of the Company for the year ended December 31, 2023.
The Greenfire Reserves Report estimate of abandonment and reclamation costs is an estimate of the amount required to abandon and reclaim the entire development (including well sites, gathering systems and processing facilities) over the life of the reserves. In the Greenfire Reserves Report, abandonment and reclamation costs for total proved plus probable reserves were estimated to be $251 million, undiscounted, and $14 million, discounted at 10%. These costs include the abandonment, decommissioning and reclamation of the entire Hangingstone Facilities, infrastructure, currently drilled SAGD and observation wells plus the future well pairs, infills and observation wells anticipated to be required to develop the assigned reserves over the life of the Hangingstone Facilities. These estimates do not include abandonment and reclamation costs or other liabilities outside of the Hangingstone Facilities, which the Company has included in determining its total decommissioning provision.
Future Development Costs
The following table sets out the development costs deducted in the estimation of future net revenue attributable to proved reserves (using forecast prices and costs) and proved plus probable reserves (using forecast prices and costs) based upon the Greenfire Reserves Report.
| | Total Proved Reserves
(Estimated Using Forecast
Prices and Costs $000s) | | | Total Proved Plus Probable
Reserves (Estimated Using
Forecast Prices and Costs $000s) | |
| 2024 | | | 85,177 | | | | 85,177 | |
| 2025 | | | 108,095 | | | | 105,672 | |
| 2026 | | | 54,387 | | | | 20,912 | |
| 2027 | | | 32,871 | | | | 25,310 | |
| 2028 | | | 42,458 | | | | 42,052 | |
| Thereafter | | | 1,020,882 | | | | 1,285,986 | |
| Total for all years undiscounted | | | 1,343,870 | | | | 1,565,109 | |
| Total for all years discounted at 10% per year | | | 565,484 | | | | 532,461 | |
Greenfire expects to use a combination of internally generated cash from operations, working capital and the issuance of new equity or debt where and when it believes appropriate to fund future development costs set out in the Greenfire Reserves Report. There can be no guarantee that funds will be available or that Greenfire will allocate funding to develop all of the reserves attributable in the Greenfire Reserves Report. Failure to develop those reserves could have a negative impact on Greenfire’s future cash flow. Further, Greenfire may choose to delay development depending upon a number of circumstances including the existence of higher priority expenditures and available cash flow.
Greenfire does not anticipate that interest or other funding costs would make further development of any of Greenfire’s properties uneconomic.
Other Oil and Natural Gas Information
Unless otherwise stated, the following information is presented as at December 31, 2023.
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. Greenfire 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 40.3 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 oil sands 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 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.
Land Acreage
As a result of the JACOS Acquisition, Greenfire 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.
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.
All of Greenfire’s acreage is located in the Province of Alberta and is held indefinitely. There are no near-term acreage expirations. The following table shows Greenfire’s total gross and net mineral rights acreage by asset location as of December 31, 2023:
Properties with Reserves
| Area | | Property | | Interest (%) | | | Gross Area (Hectares) | | | Net Area (Hectares) | |
| Hangingstone | | Expansion | | | 75 | | | | 17,730 | | | | 13,298 | |
| Hangingstone | | Demo | | | 100 | | | | 974 | | | | 974 | |
| Total Acreage | | | | | | | | | 18,704 | | | | 14,272 | |
Unproved Properties
| | Property | | Interest (%) | | | Gross Area (Hectares) | | | Net Area (Hectares) | |
| 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 Acreage | | | | | | | | | 63,767 | | | | 25,524 | |
Well Information
Greenfire had 54 gross (46 net horizontal wells) capable of producing bitumen as of each of the years ended December 31, 2023, and 2022. As of December 31, 2023, Greenfire has drilled eight new redevelopment infill (“Refill”) wells. Refill wells are an infill well that has been drilled via the re-entry of an existing primary producer well to produce incremental pre-heated bitumen between two sets of well pairs. 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 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. Greenfire has no exploratory wells and did not drill any dry exploratory or development wells in the last three fiscal years.
As evaluated by McDaniel as of December 31, 2023, proved undeveloped reserves are from planned well locations in the Alberta Energy Regulator (“AER”) approved development area and are within three miles from existing bitumen producing wells at the Demo Asset and Expansion Asset. Development plans include new well pairs that consist of horizontal steam injector wells placed approximately 15 feet (5 meters) above horizontal bitumen production wells in a reservoir that has a minimum of 32 feet (10 meters) of average bitumen net pay and up to over 100 feet (30 meters). Spacing between well pairs at both the Demo Asset and Expansion Asset is approximately 325 feet (100 meters). Future development plans include drilling infill horizontal bitumen production wells between existing and new well pairs.
In order to make the most efficient use of Greenfire’s steam generating and oil treating facilities, the drilling and steaming of new wells would take place over 30 years. Development of Greenfire’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 Greenfire’s proved reserves extends approximately 32 years.
Oil and Natural Gas Wells
The following table sets forth Greenfire’s producing and non-producing bitumen production wells as of December 31, 2023, all of which are in Alberta, Canada:
| | | Producing Wells as of
December 31, 2023 | | | Non-Producing Wells as of
December 31, 2023 | |
| Expansion Asset | | Gross | | | Net | | | Gross | | | Net | |
| SAGD Well Pairs(1) | | | 32 | | | | 24 | | | | - | | | | - | |
| Infill Wells | | | - | | | | - | | | | - | | | | - | |
| Demo Asset | | | | | | | | | | | | | | | | |
| SAGD Well Pairs | | | 22 | | | | 22 | | | | 2 | | | | 2 | |
| Infill Wells | | | - | | | | - | | | | - | | | | - | |
| Total | | | 54 | | | | 46 | | | | 2 | | | | 2 | |
Note:
| (1) | These SAGD wells include the 8 Refill wells drilled at the Expansion Asset in 2023. A Refill well is an infill well that has been drilled via the re-entry of an existing primary producer well to produce incremental pre-heated bitumen between two sets of well pairs. 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. They do not add to a well pair count nor can be considered a true infill well. |
Properties with No Attributed Reserves
As at December 31, 2023, Greenfire held approximately 63,767 gross acres and 25,524 net acres of rights with no attributed reserves. For additional information about Greenfire’s properties with no attributed reserves see “Other Oil and Natural Gas Information – Principal Properties – Land Acreage”.
Forward Contracts
Greenfire may use financial derivatives to manage its exposure to fluctuations in commodity prices, foreign exchange and interest rates. These include contracts for exposure management unrelated to crude oil sales price risk management; and contracts for management of price exposures associated with crude oil, crude oil differentials, condensate, natural gas liquids, refined products, refining margins, natural gas, electricity and renewable power contracts. The indenture governing Greenfire’s senior secured notes has a minimum hedging requirement of 50% of the forward 12 calendar month proved developed producing forecasted production as prepared in accordance with the Canadian standards under NI 51-101 until principal debt under the senior secured notes is less than US$100.0 million.
As of December 31, 2023, Greenfire entered into commodity-based derivative contracts as follows:
| | | WTI -Costless Collar | | | Natural Gas-Fixed
Price Swaps | |
| Term | | | Volume
(bbls) | | | Put Strike Price
(US$/bbl) | | | Call Strike Price
(US$/bbl) | | | Volume
(GJs) | | | Swap Price
(CAD$/GL) | |
| Q1 2024 | | | | 877,968 | | | $ | 60.00 | | | $ | 77.00 | | | | 455,000 | | | $ | 2.97 | |
| Q2 2024 | | | | 877,968 | | | $ | 60.00 | | | $ | 74.55 | | | | - | | | | - | |
| Q3 2024 | | | | 887,800 | | | $ | 62.00 | | | $ | 92.32 | | | | - | | | | - | |
| Q4 2024 | | | | 887,800 | | | $ | 59.46 | | | $ | 87.58 | | | | - | | | | - | |
Greenfire has revised its risk management contracts for 2024 replacing the WTI costless collars with WTI-fixed price swaps. As of March 20, 2024, Greenfire has the following commodity-based derivative contracts.
| | | WTI-Fixed Price Swaps | | | WTI-Costless Collars | | | Natural Gas-Fixed
Price Swaps | |
| Term | | | Volume
(bbls) | | | Swap Price
(US$/bbl) | | | Volume
(bbls) | | | Put Strike Price
(US$/bbl) | | | Call Strike Price
($US/bbl) | | | Volume
(GJs) | | | Swap Price
(US$/GJ) | |
| Q1 2024 | | | | 1,046,500 | | | $ | 70.94 | | | | - | | | | - | | | | - | | | | 455,000 | | | $ | 2.97 | |
| Q2 2024 | | | | 1,046,500 | | | $ | 70.94 | | | | - | | | | - | | | | - | | | | - | | | | - | |
| Q3 2024 | | | | 1,058,000 | | | $ | 70.94 | | | | - | | | | - | | | | - | | | | - | | | | - | |
| Q4 2024 | | | | 1,058,000 | | | $ | 70.94 | | | | - | | | | - | | | | - | | | | - | | | | - | |
| Q1 2025 | | | | - | | | | - | | | | 640,700 | | | $ | 57.97 | | | $ | 84.22 | | | | - | | | | - | |
Tax Horizon
In 2023, Greenfire was not required to pay any income related taxes. It is expected, based upon current legislation, the projections contained in the Greenfire Reserves Report, proved plus probable analysis and various other assumptions, that no income taxes will be required to be paid by Greenfire until 2027. A higher level of capital expenditures than those contained in the Greenfire Reserves Report, or further additional acquisitions, could further extend the estimated tax horizon.
Costs Incurred
The following table summarizes certain costs incurred by Greenfire in Canada for the year ended December 31, 2023:
Expenditure(1) | | ($millions) | |
| Property acquisition costs | | | | |
| Proved properties | | | - | |
| Unproved properties | | | - | |
| Exploration costs | | | - | |
| Development costs | | | 33 | |
| Total | | | 33 | |
Note:
| (1) | Greenfire had no property acquisition costs, or disposition proceeds, for the year ended December 31, 2023. Development costs during the year were related to mineral lease rentals on undeveloped lands. |
Exploration and Development Activities
The following table sets forth the wells in which Greenfire participated during the year ended December 31, 2023.
| | | 2023 Wells
(Gross and Net) | |
| | | Gross Wells | | | Net Wells | |
| Exploration Wells | | | - | | | | - | |
| Stratigraphic Test Wells | | | - | | | | - | |
| SAGD Wells(1) | | | 8 | | | | 6 | |
| Observation Wells | | | - | | | | - | |
| Infill Wells | | | - | | | | - | |
| Water Source Wells | | | - | | | | - | |
| Water Disposal Wells | | | - | | | | - | |
| Total Completed Wells: | | | 8 | | | | 6 | |
Note:
| (1) | These are the 8 Refill wells drilled at the Expansion Asset in 2023. A Refill well is an infill well that has been drilled via the re-entry of an existing primary producer well to produce incremental pre-heated bitumen between two sets of well pairs. 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. They do not add to a well pair count nor can be considered a true infill well. |
See “Other Oil and Natural Gas Information – Principal Properties” for a description of Greenfire’s current and proposed exploration and development activities.
Production Estimates
The following table sets out the volumes of company share production estimated by McDaniel for 2024, which is reflected in the estimate of future net revenue disclosed in the forecast price tables contained under “Statement of Reserves Data and Other Oil and Gas Information –Disclosure of Reserves Data – Pricing Assumptions”.
| | | Bitumen
(bbls/d) | |
| Total Proved | | | |
| Alberta | | | | |
| Expansion Asset | | | 18,356 | |
| Demo Asset | | | 4,870 | |
| Other | | | - | |
| Total | | | 23,226 | |
| Total Proved Plus Probable | | | | |
| Alberta | | | | |
| Expansion Asset | | | 20,134 | |
| Demo Asset | | | 5,450 | |
| Other | | | - | |
| Total | | | 25,584 | |
Production History
The following table sets forth certain information in respect of production, product prices received, royalties paid, production costs and resulting netback received by Greenfire for the periods indicated below:
| | | Quarter Ended 2023 | | | Year Ended 2023 | |
| | | Mar. 31 | | | June 30 | | | Sept. 30 | | | Dec. 31 | | | Dec 31 | |
| Average Daily Sales(1) | | | | | | | | | | | | | | | |
| Bitumen (Bbls/d) | | | 20,586 | | | | 18,036 | | | | 11,052 | | | | 17,335 | | | | 17,639 | |
| Average Price Received (net of quality adjustment) | | | | | | | | | | | | | | | | | | | | |
| Bitumen ($/Bbl) | | | 65.87 | | | | 75.78 | | | | 89.86 | | | | 71.04 | | | | 73.91 | |
| Royalties Paid | | | | | | | | | | | | | | | | | | | | |
| Bitumen ($/Bbl) | | | 2.36 | | | | 3.54 | | | | 5.60 | | | | 3.79 | | | | 3.67 | |
| Production Costs | | | | | | | | | | | | | | | | | | | | |
| Bitumen ($/Bbl) | | | 20.87 | | | | 20.20 | | | | 29.12 | | | | 22.05 | | | | 23.08 | |
| Net Transportation Costs | | | | | | | | | | | | | | | | | | | | |
| Bitumen ($/Bbl) | | | 6.83 | | | | 6.46 | | | | 7.79 | | | | 6.82 | | | | 6.93 | |
| Resulting Netback Received(2) | | | | | | | | | | | | | | | | | | | | |
| Bitumen ($/Bbl) | | | 9.11 | | | | 23.05 | | | | 38.07 | | | | 17.19 | | | | 20.56 | |
Notes:
| (1) | Before deduction of royalties. |
| (2) | Netbacks are calculated by subtracting royalties and operating costs from revenues. Excludes realized gains (losses) on risk management contracts. |
The following table indicates Greenfire’s average daily production from the Demo Asset and the Expansion Asset for the year ended December 31, 2023:
| | | Bitumen
(Bbls/d) | |
| Alberta | | | |
| Demo Asset | | | 3,810 | |
| Expansion Asset | | | 13,829 | |
| Total | | | 17,639 | |
APPENDIX A – REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE
Management of Greenfire Resources Ltd. (the “Company”) is responsible for the preparation and disclosure of information with respect to the Company’s oil and natural gas activities in accordance with securities regulatory requirements. This information includes reserves data which are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2023, estimated using forecast prices and costs.
An independent qualified reserves evaluator has evaluated the Company’s reserves data. The report of the independent qualified reserves evaluator is presented above.
The Audit and Reserves Committee of the Board of Directors of the Company has:
| (a) | reviewed the Company’s procedures for providing information to the independent qualified reserves evaluator; |
| (b) | met with the independent qualified reserves evaluator to determine whether any restrictions affected the ability of the independent qualified reserves evaluator to report without reservation; and |
| (c) | reviewed the reserves data with management and the independent qualified reserves evaluator. |
The Audit and Reserves Committee of the Board of Directors has reviewed the Company’s procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The Board of Directors has, on the recommendation of the Audit and Reserves Committee, approved:
| (a) | the content and filing with securities regulatory authorities of Form 51-101F1 containing reserves data and other oil and gas information; |
| (b) | the filing of Form 51-101F2 which is the report of the independent qualified reserves evaluator on the reserves data, contingent resources data, or prospective resources data; and |
| (c) | the content and filing of this report. |
Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.
| (Signed) “Robert Logan” | | (Signed) “Tony Kraljic” |
| Robert Logan | | Tony Kraljic |
| President, Chief Executive Officer and a Director | | Chief Financial Officer |
| (Signed) “Venkat Siva” | | (Signed) “William Derek Aylesworth” |
| Venkat Siva | | William Derek Aylesworth |
| Director and Member of the Audit and Reserves Committee | | Director and Chair of the Audit and Reserves Committee |
March 20, 2024
APPENDIX B – REPORT ON RESERVES DATA BY THE INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR
To the Board of Directors of Greenfire Resources Ltd., (the “Company”):
| 1. | We have evaluated the Company’s reserves data as at December 31, 2023. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2023, estimated using forecast prices and costs. |
| 2. | The reserves data are the responsibility of the Company’s management. Our responsibility is to express an opinion on the reserves data based on our evaluation. |
| 3. | We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook as amended from time to time (the “COGE Handbook”) maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter). |
| 4. | Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook. |
| 5. | The following table shows the net present value of future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10%, included in the reserves data of the Company evaluated by us for the year ended December 31, 2023, and identifies the respective portions thereof that we have evaluated and reported on to the Company’s Board of Directors: |
| Independent Qualified | | Effective Date of Evaluation | | Location of Reserves (County or Foreign Geographic | | Net Present Value of Future Net Revenue (before income
taxes, 10% discount rate - $M) | |
| Reserves Evaluator | | Report | | Area) | | Audited | | | Evaluated | | | Reviewed | | | Total | |
| McDaniel | | December 31, 2023 | | Canada | | | - | | | | 2,423,414 | | | | - | | | | 2,423,414 | |
| 6. | In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook, consistently applied. We express no opinion on the reserves data that we reviewed but did not audit or evaluate. |
| 7. | We have no responsibility to update our reports referred to in paragraph 5 for events and circumstances occurring after the effective date of our reports. |
| 8. | Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material. |
Executed as to our report referred to above:
McDaniel & Associates Consultants Ltd.
| (Signed) “Jared Wynveen” | |
| Jared Wynveen, P.Eng. | |
| Executive Vice President | |
| Calgary, Alberta, Canada, March 20, 2024 | |
