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Coelacanth Energy Inc. — Management Reports 2026
Apr 22, 2026
48379_rns_2026-04-21_d82274f8-412f-440e-9be6-5d63d364d5c9.pdf
Management Reports
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COELACANTH ENERGY INC. - 3 - 2025 YEAR END REPORT
MANAGEMENT'S DISCUSSION AND ANALYSIS ("MD&A")
April 21, 2026
The MD&A should be read in conjunction with the audited financial statements and related notes for the years ended December 31, 2025 and 2024. The audited financial statements and financial data contained in the MD&A have been prepared in accordance with IFRS Accounting Standards ("IFRS") as issued by the International Accounting Standards Board ("IASB"). All dollar amounts are expressed in Canadian currency, unless otherwise noted.
DESCRIPTION OF BUSINESS
Coelacanth Energy Inc. ("Coelacanth" or the "Company") is an oil and natural gas company, actively engaged in the acquisition, development, exploration, and production of oil and natural gas reserves in northeastern British Columbia, Canada. The Company trades on the TSX Venture Exchange ("TSXV") under the symbol "CEI".
OIL AND GAS TERMS
The Company uses the following frequently recurring oil and gas industry terms in the MD&A:
Liquids
- Bbls: Barrels
- Bbls/d: Barrels per day
- NGLs: Natural gas liquids (includes condensate, pentane, butane, propane, and ethane)
- Condensate: Pentane and heavier hydrocarbons
Natural Gas
- Mcf: Thousands of cubic feet
- Mcf/d: Thousands of cubic feet per day
- MMcf/d: Millions of cubic feet per day
- MMbtu: Million of British thermal units
- MMbtu/d: Million of British thermal units per day
- GJ: Gigajoules
- GJ/d: Gigajoules per day
Oil Equivalent
- Boe: Barrels of oil equivalent
- Boe/d: Barrels of oil equivalent per day
Disclosure provided herein in respect of a boe may be misleading, particularly if used in isolation. A boe conversion rate of six thousand cubic feet of natural gas to one barrel of oil equivalent has been used for the calculation of boe amounts in the MD&A. This boe conversion rate is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
NOTE REGARDING PRODUCT TYPES
The Company uses the following references to sales volumes in the MD&A:
- Natural gas refers to shale gas
- Oil and condensate refers to condensate and tight oil combined
- Other NGLs refers to butane, propane and ethane combined
- Oil and NGLs refers to tight oil and NGLs combined
- Oil equivalent refers to the total oil equivalent of shale gas, tight oil, and NGLs combined, using the conversion rate of six thousand cubic feet of shale gas to one barrel of oil equivalent as described above.
Readers are referred to the "Product Types" section for a complete breakdown of sales volumes for applicable periods by specific product types of shale gas, tight oil, and NGLs.
NON-GAAP AND OTHER FINANCIAL MEASURES
This MD&A refers to certain measures that are not determined in accordance with IFRS (or "GAAP"). These non-GAAP and other financial measures do not have any standardized meaning prescribed under IFRS and therefore may not be comparable to similar measures presented by other entities. The non-GAAP and other financial measures should not be considered alternatives to, or more meaningful than, financial measures that are determined in accordance with IFRS as indicators of the Company's performance. Management believes that the presentation of these non-GAAP and other financial measures provides useful information to shareholders and investors in understanding and evaluating the Company's ongoing operating performance, and the measures provide increased transparency to better analyze the Company's performance against prior periods on a comparable basis.
Non-GAAP Financial Measures
Adjusted funds flow
Management uses adjusted funds flow to analyze performance and considers it a key measure as it demonstrates the Company's ability to generate the cash necessary to fund future capital investments and abandonment obligations and to repay debt. Adjusted funds flow is a non-GAAP financial measure and has been defined by the Company as cash flow from operating activities excluding the change in non-cash working capital related to operating activities, movements in restricted cash deposits and expenditures on decommissioning
obligations. Management believes the timing of collection, payment or incurrence of these items involves a high degree of discretion and as such may not be useful for evaluating the Company's cash flows. Adjusted funds flow is reconciled from cash flow from operating activities under the heading "Cash Flow From Operating Activities and Adjusted Funds Flow".
Net transportation expenses
Management considers net transportation expenses an important measure as it demonstrates the cost of utilized transportation related to the Company's production. Net transportation expenses is calculated as transportation expenses less unutilized transportation and is calculated as follows:
| ($000s) | Three Months Ended | Year Ended | ||
|---|---|---|---|---|
| December 31 2025 | 2024 | December 31 2025 | 2024 | |
| Transportation expenses | 1,120 | 887 | 3,618 | 3,313 |
| Unutilized transportation | (132) | (387) | (831) | (1,891) |
| Net transportation expenses (non-GAAP) | 988 | 500 | 2,787 | 1,422 |
Operating netback
Management considers operating netback an important measure as it demonstrates its profitability relative to current commodity prices. Operating netback is calculated as oil and natural gas sales less royalties, operating expenses, and net transportation expenses and is calculated as follows:
| ($000s) | Three Months Ended | Year Ended | ||
|---|---|---|---|---|
| December 31 2025 | 2024 | December 31 2025 | 2024 | |
| Oil and natural gas sales | 11,603 | 4,544 | 30,469 | 13,736 |
| Royalties | (1,511) | (820) | (5,236) | (2,698) |
| Operating expenses | (2,759) | (786) | (7,031) | (3,335) |
| Net transportation expenses | (988) | (500) | (2,787) | (1,422) |
| Operating netback (non-GAAP) | 6,345 | 2,438 | 15,415 | 6,281 |
Capital expenditures
Coelacanth utilizes capital expenditures as a measure of capital investment on property, plant, and equipment, exploration and evaluation assets and property acquisitions compared to its annual budgeted capital expenditures. Capital expenditures are calculated as follows:
| ($000s) | Three Months Ended | Year Ended | ||
|---|---|---|---|---|
| December 31 2025 | 2024 | December 31 2025 | 2024 | |
| Capital expenditures – property, plant, and equipment | 30,615 | 233 | 35,891 | 1,206 |
| Capital expenditures – exploration and evaluation assets | 3,921 | 64,719 | 44,723 | 83,291 |
| Capital expenditures (non-GAAP) | 34,536 | 64,952 | 80,614 | 84,497 |
Capital Management Measures
Adjusted working capital deficiency and net debt
Management uses adjusted working capital deficiency and net debt as measures to assess the Company's financial position. Adjusted working capital is calculated as current assets and restricted cash deposits less current liabilities, excluding the current portion of decommissioning obligations and other obligations. Net debt includes adjusted working capital deficiency and non-current portion of the credit facility. Refer to the calculation of adjusted working capital deficiency and net debt and reconciliation to working capital under the heading "Liquidity and Capital Resources".
Non-GAAP Financial Ratios
Adjusted funds flow per share
Adjusted funds flow per share is a non-GAAP financial ratio, calculated using adjusted funds flow and the same weighted average basic and diluted shares used in calculating net loss per share.
Net transportation expenses per boe
The Company utilizes net transportation expenses per boe to assess the per unit cost of utilized transportation related to the Company's production. Net transportation expenses per boe is calculated as net transportation expenses divided by total production for the applicable period. Net transportation expenses per boe is reconciled to transportation expenses per boe under the heading "Net Transportation Expenses".
Operating netback per boe
The Company utilizes operating netback per boe to assess the operating performance of its oil and natural gas assets on a per unit of production basis. Operating netback per boe is calculated as operating netback divided by total production for the applicable period. Operating netback per boe is reconciled to net loss per boe under the heading "Operating Netback".
COELACANTH ENERGY INC. - 4 - 2025 YEAR END REPORT
Supplementary Financial Measures
The supplementary financial measures used in this MD&A (primarily average sales price per product type, royalty rates, and certain per boe and per share figures) are either a per unit disclosure of a corresponding GAAP measure, or a component of a corresponding GAAP measure, presented in the financial statements. Supplementary financial measures that are disclosed on a per unit basis are calculated by dividing the aggregate GAAP measure (or component thereof) by the applicable unit for the period. Supplementary financial measures that are disclosed on a component basis of a corresponding GAAP measure are a granular representation of a financial statement line item and are determined in accordance with GAAP.
OPERATIONS UPDATE
Coelacanth had a very active 2025 investing over $80.0 million to further its large Montney Project at Two Rivers in northeast British Columbia. Over half the capital was spent on completing the facilities and gathering lines to bring on the 5-19 pad wells previously drilled and tested. Remaining capital expenditures were for drilling three additional Montney pad wells at 5-19. Throughout Q4 2025 and Q1 2026, wells were systematically placed on production to achieve a production rate of 8,000 boe/d in late March 2026 with additional wells anticipated to be placed on production by end of April 2026 as previously disclosed. As part of an expanded role and in conjunction with the recent production increases, Coelacanth has also promoted Dan Rach to the role of VP Production.
With the construction of the new infrastructure completed with excess capacity available for growth, Coelacanth can focus on go-forward capital in 2026 and 2027 primarily on drilling. Coelacanth anticipates drilling a new 5 or 6 well development pad in summer 2026 and start further delineation of the large Montney resource that has stacked Montney zones.
Reserves were conservatively booked with less than 8% of the lands with reserves booked in the Lower Montney and less than 2% of the lands with reserves booked in the Upper Montney. This leaves significant upside for future bookings pending successful delineation of the asset base both aerially across the lands and vertically through the Montney stack.
The Amended Credit Facility completed on April 20, 2026 to increase and extend the Company's bank credit facility to $90.0 million plus the recently announced equity raise of $80.0 million anticipated to close on or around May 6, 2026, will allow Coelacanth to systematically work through its business plan of not only increasing production year over year but proving out the resource to understand the ultimate scale of this project.
We look forward to reporting on future developments as they arise.
SUMMARY OF FINANCIAL RESULTS
| Three Months Ended | Year Ended | |||||
|---|---|---|---|---|---|---|
| December 31 | December 31 | |||||
| ($000s, except per share amounts) | 2025 | 2024 | % Change | 2025 | 2024 | 2023 |
| Oil and natural gas sales | 11,603 | 4,544 | 155 | 30,469 | 13,736 | 6,663 |
| Cash flow from (used in) operating activities | 4,852 | 3,157 | 54 | 8,906 | 2,203 | (4,234) |
| Per share - basic and diluted (4) | 0.01 | 0.01 | - | 0.02 | - | (0.01) |
| Adjusted funds flow (used) (1) | 2,310 | 382 | 505 | 2,843 | 1,515 | (333) |
| Per share - basic and diluted | - | - | - | 0.01 | - | (-) |
| Net loss | (2,181) | (2,903) | (25) | (11,026) | (8,897) | (6,573) |
| Per share - basic and diluted | - | (0.01) | (100) | (0.02) | (0.02) | (0.01) |
| Total assets | 275,800 | 213,038 | 208,994 | |||
| Total long-term liabilities | 65,063 | 7,775 | 7,721 | |||
| Adjusted working capital (deficiency) (2) | (37,934) | (18,527) | 68,024 | |||
| Net debt (4) | (76,035) | (18,527) | 68,024 |
(1) Adjusted funds flow (used) and adjusted funds flow (used) per share do not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures used by other companies. Please refer to the "Non-GAAP and Other Financial Measures" section for more details and the "Cash Flow From Operating Activities and Adjusted Funds Flow" section for a reconciliation from cash flow from operating activities.
(2) Adjusted working capital (deficiency) is a capital management measure calculated as current assets and restricted cash deposits less current liabilities, excluding the current portion of decommissioning obligations and other obligations. Please refer to the "Non-GAAP and Other Financial Measures" section for more details.
(3) Net debt is a capital management measure calculated as the non-current portion of the credit facility and adjusted working capital deficiency. Please refer to the "Non-GAAP and Other Financial Measures" section for more details.
(4) Supplemental financial measure. Please refer to the "Non-GAAP and Other Financial Measures" section for more details.
COELACANTH ENERGY INC. - 5 - 2025 YEAR END REPORT
Oil and natural gas sales increased in 2025 compared to 2024 as a result of the initiation of commercial production at Two Rivers East part way through June 2025. Cash flow and adjusted funds flow increased mainly as a result of increased production partially offset by increased interest expense, lower interest income and payments on financing obligation.
Oil and natural gas sales, cash flow from operating activities, and adjusted funds flow increased in 2024 compared to 2023 mainly due to an increase in oil and natural gas production stemming from two new wells at Two Rivers West placed on production in Q4 2023.
Net loss increased in 2025 compared to 2024 mainly as the result of increased depletion and depreciation resulting from increased production and cost base of property, plant and equipment, partially offset by increased adjusted funds flow.
Net loss increased in 2024 compared to 2023 mainly as the result of $1.7 million of third party fees to secure the initial one-year term of a $45.0 million credit facility and increased depletion and depreciation expense resulting from increased production.
Adjusted working capital deficiency increased in 2025 compared to 2024 and 2023 as the result of building out the required infrastructure and commencing its pad drilling program at Two Rivers East.
| PRODUCTION | Three Months Ended | Year Ended | ||||
|---|---|---|---|---|---|---|
| December 31 | December 31 | |||||
| 2025 | 2024 | % Change | 2025 | 2024 | % Change | |
| Average Daily Production (1) | ||||||
| Oil and condensate (bbls/d) | 1,151 | 473 | 143 | 816 | 320 | 155 |
| Other NGLs (bbls/d) | 165 | 29 | 469 | 77 | 34 | 126 |
| Oil and NGLs (bbls/d) | 1,316 | 502 | 162 | 893 | 354 | 152 |
| Natural gas (mcf/d) | 16,268 | 3,490 | 366 | 8,626 | 3,648 | 136 |
| Oil equivalent (boe/d) | 4,027 | 1,084 | 271 | 2,331 | 962 | 142 |
(1) "Natural gas" refers to shale gas; "Oil and condensate" refers to condensate and tight oil combined; "Other NGLs" refers to butane, propane and ethane combined; "Oil and NGLs" refers to tight oil and NGLs combined; "Oil equivalent" refers to the total oil equivalent of shale gas, tight oil, and NGLs combined, using the conversion rate of six thousand cubic feet of shale gas to one barrel of oil equivalent. Readers are referred to the "Product Types" section for a complete breakdown of sales volumes for applicable periods by specific product types of shale gas, tight oil, and NGLs.
Daily production increased to 4,027 boe/d and 2,331 boe/d for the three months and year ended December 31, 2025, respectively, from 1,084 boe/d and 962 boe/d for the comparative periods in 2024. The increase in production was the result of the initiation of commercial production at Two Rivers East part way through June 2025.
Coelacanth's production profile for the fourth quarter of 2025 was comprised of lower oil and NGLs content when compared to the comparative quarter in 2024 as the result of increased oil content during the testing phase of early successful drilling at Two Rivers East in Q4 2024 when overall production was significantly lower than in Q4 2025. The Q4 2025 weighting was 67% natural gas (Q4 2024 - 54%) and 33% oil and NGLs (Q4 2024 - 46%). As the wells mature, it is expected that the production mix will become more gas weighted.
| OIL AND NATURAL GAS SALES | Three Months Ended | Year Ended | ||||
|---|---|---|---|---|---|---|
| December 31 | December 31 | |||||
| ($000s) | 2025 | 2024 | % Change | 2025 | 2024 | % Change |
| Oil and condensate | 7,768 | 3,791 | 105 | 23,382 | 10,465 | 123 |
| Other NGLs | 313 | 88 | 256 | 685 | 419 | 63 |
| Oil and NGLs | 8,081 | 3,879 | 108 | 24,067 | 10,884 | 121 |
| Natural gas | 3,522 | 665 | 430 | 6,402 | 2,852 | 124 |
| Total | 11,603 | 4,544 | 155 | 30,469 | 13,736 | 122 |
| Average Sales Price | ||||||
| Oil and condensate ($/bbl) | 73.36 | 87.06 | (16) | 78.15 | 89.46 | (13) |
| Other NGLs ($/bbl) | 20.66 | 33.28 | (38) | 24.29 | 33.22 | (27) |
| Oil and NGLs ($/bbl) | 66.78 | 83.97 | (20) | 73.83 | 83.99 | (12) |
| Natural gas production sales and transportation revenue ($/mcf) | 2.35 | 2.07 | 14 | 2.03 | 2.14 | (5) |
| Combined ($/boe) | 31.32 | 45.57 | (31) | 35.82 | 39.01 | (8) |
Revenue totaled $11.6 million and $30.5 million for the three months and year ended December 31, 2025, respectively, compared to $4.5 million and $13.7 million for the comparative periods in 2024. The increase in revenue was mainly the result of the increase in production resulting from initiation of commercial production at Two Rivers East part way through June 2025.
COELACANTH ENERGY INC. - 6 - 2025 YEAR END REPORT
The following table outlines the Company's realized wellhead prices and industry benchmarks:
| Commodity Pricing | Three Months Ended | Year Ended | ||||
|---|---|---|---|---|---|---|
| December 31 | December 31 | |||||
| 2025 | 2024 | % Change | 2025 | 2024 | % Change | |
| Oil and NGLs | ||||||
| Corporate price ($CDN/bbl) | 66.78 | 83.97 | (20) | 73.83 | 83.99 | (12) |
| Canadian light sweet ($CDN/bbl) | 76.54 | 92.69 | (17) | 85.66 | 98.13 | (13) |
| West Texas Intermediate ("WTI") ($US/bbl) | 59.14 | 70.27 | (16) | 64.81 | 75.73 | (14) |
| Natural gas | ||||||
| Corporate price ($CDN/mcf) | 2.35 | 2.07 | 14 | 2.03 | 2.14 | (5) |
| AECO price ($CDN/mcf) | 2.28 | 1.48 | 54 | 1.69 | 1.39 | 22 |
| Westcoast Station 2 ($CDN/mcf) | 1.94 | 0.95 | 104 | 0.99 | 1.09 | (9) |
| Chicago City Gate ($US/mmbtu) | 3.36 | 2.51 | 34 | 3.25 | 2.19 | 48 |
| Exchange rate | ||||||
| CDN/US dollar exchange rate | 0.7171 | 0.7147 | - | 0.7158 | 0.7301 | (2) |
Future prices received from the sale of the products may fluctuate as a result of market factors. Differences between corporate and benchmark prices can be the result of quality differences (higher or lower API oil and higher or lower heat content natural gas), sour content, the mix of sales points and marketing contracts negotiated for products, the mix of oil and NGLs, and various other factors. Coelacanth's differences are mainly the result of higher heat content natural gas production that is priced higher than AECO reference prices as well as the diversification of sales points and marketing contracts for products.
The Company's corporate average oil and NGLs prices were 87.2% and 86.2% of Canadian light sweet prices for the three months and year ended December 31, 2025, respectively, consistent with 90.6% and 85.6% for the comparative periods in 2024. Coelacanth's liquids mix during the fourth quarter of 2025 was approximately 88% light oil, condensate and pentanes, 7% butane and 5% propane (Q4 2024 - 94% light oil, condensate and pentanes, 3% butane and 3% propane).
Corporate average natural gas prices were 121.1% and 205.1% of Westcoast Station 2 price for the three months and year ended December 31, 2025, respectively, compared to 217.9% and 196.3% for the comparative periods in 2024. The decrease in the fourth quarter of 2025 compared to the fourth quarter of 2024 was due to a higher percentage of the Company's natural gas production being sold under lower priced Westcoast Station 2 contracts than Chicago contracts. The Company has contracted 1.5 mmcf/d of natural gas to be delivered to Chicago with the remainder being delivered to Westcoast Station 2.
At December 31, 2025, the Company had the following commodity price contracts outstanding:
| Commodity | Period | Type of Contract | Quantity | Contract Price |
|---|---|---|---|---|
| Oil | January 1, 2026 - April 30, 2026 | Physical Sales | 500 bbls/d | WTI CDN $86.86/bbl |
| Natural Gas | January 1, 2026 - March 31, 2026 | Physical Sales | 10,000 GJ/d | Westcoast Station 2 CDN $2.49/GJ |
Subsequent to December 31, 2025, the Company entered into the following commodity price contracts:
| Commodity | Period | Type of Contract | Quantity | Contract Price |
|---|---|---|---|---|
| Oil | May 1, 2026 - June 30, 2026 | Physical Sales | 500 bbls/d | WTI CDN $85.69/bbl |
The Company accounts for any physical sales contracts as executory contracts and as such are not recorded at fair value on the statement of financial position. Settlements on these physical sales contracts are recognized in oil and natural gas sales.
| ROYALTIES | Three Months Ended | Year Ended | ||||
|---|---|---|---|---|---|---|
| December 31 | December 31 | |||||
| ($000s) | 2025 | 2024 | % Change | 2025 | 2024 | % Change |
| Oil and NGLs | 1,312 | 779 | 68 | 4,840 | 2,424 | 100 |
| Natural gas | 199 | 41 | 385 | 396 | 274 | 45 |
| Total | 1,511 | 820 | 84 | 5,236 | 2,698 | 94 |
| Average Royalty Rate (% of sales) | ||||||
| --- | --- | --- | --- | --- | --- | --- |
| Oil and NGLs | 16.2 | 20.1 | (19) | 20.1 | 22.3 | (10) |
| Natural gas | 5.7 | 6.2 | (8) | 6.2 | 9.6 | (35) |
| Combined | 13.0 | 18.0 | (28) | 17.2 | 19.6 | (12) |
The Company pays royalties to provincial governments (Crown) and other oil and gas companies that own surface or mineral rights. Crown royalties are calculated on a sliding scale based on commodity prices and individual well production rates. Royalty rates can change due to commodity price fluctuations and changes in production volumes on a well-by-well basis, subject to a minimum and maximum rate restriction ascribed by the Crown.
COELACANTH ENERGY INC. - 7 - 2025 YEAR END REPORT
Royalties totaled $1.5 million and $5.2 million for the three months and year ended December 31, 2025, respectively, compared to $0.8 million and $2.7 million for the comparative periods in 2024. The increase in 2025 from 2024 was mainly as a result of the increased production and revenue at Two Rivers East. Royalty rates decreased in the three months and year ended December 31, 2025 compared to the same periods in 2024 as the result of a portion of the new oil wells at Two Rivers East being subject to British Columbia's flat 5.0% transition royalty rate for the first twelve months of equivalent production. This transition royalty program relates to oil wells drilled on or after September 1, 2024 to December 31, 2026.
| OPERATING EXPENSES | Three Months Ended December 31 | Year Ended December 31 | ||||
|---|---|---|---|---|---|---|
| 2025 | 2024 | % Change | 2025 | 2024 | % Change | |
| Operating expenses ($000s) | 2,759 | 786 | 251 | 7,031 | 3,335 | 111 |
| Operating expenses ($/boe) | 7.45 | 7.88 | (5) | 8.26 | 9.47 | (13) |
Per unit operating expenses decreased to $7.45/boe and $8.26/boe for the three months and year ended December 31, 2025, respectively, from $7.88/boe and $9.47/boe in the comparative periods in 2024 as a result of increased production at Two Rivers East.
| NET TRANSPORTATION EXPENSES ($000s) | Three Months Ended December 31 | Year Ended December 31 | ||||
|---|---|---|---|---|---|---|
| 2025 | 2024 | % Change | 2025 | 2024 | % Change | |
| Oil and NGLs | 391 | 256 | 53 | 1,235 | 448 | 176 |
| Natural gas | 597 | 244 | 145 | 1,552 | 974 | 59 |
| Net transportation expenses (non-GAAP) | 988 | 500 | 98 | 2,787 | 1,422 | 96 |
| Unutilized transportation | 132 | 387 | (66) | 831 | 1,891 | (56) |
| Transportation expenses | 1,120 | 887 | 26 | 3,618 | 3,313 | 9 |
| Average transportation expenses | ||||||
| --- | --- | --- | --- | --- | --- | --- |
| Oil and NGLs ($/bbl) | 3.24 | 5.54 | (42) | 3.79 | 3.46 | 10 |
| Natural gas ($/mcf) | 0.40 | 0.76 | (47) | 0.49 | 0.73 | (33) |
| Net transportation expenses ($/boe) | 2.67 | 5.01 | (47) | 3.28 | 4.04 | (19) |
| Unutilized transportation ($/boe) | 0.36 | 3.88 | (91) | 0.98 | 5.37 | (82) |
| Transportation expenses ($/boe) | 3.03 | 8.89 | (66) | 4.26 | 9.41 | (55) |
Net transportation expenses (see "Non-GAAP and Other Financial Measures") are mainly third-party pipeline tariffs from firm transportation agreements to deliver production to the purchasers at main hubs.
Transportation expenses increased to $1.1 million and $3.6 million for the three months and year ended December 31, 2025, respectively, compared to $0.9 million and $3.3 million for the comparative periods in 2024 mainly as the result of increased production and transportation commitments.
Net transportation expenses for oil and NGLs decreased on a per unit basis to $3.24/bbl for the three months ended December 31, 2025 compared to $5.54/bbl for the comparative period in 2024 as a result of test production from new oil wells at Two Rivers East in Q4 2024 that had limited options at the time for oil terminal receipt points resulting in higher trucking costs. Net transportation expenses for oil and NGLs were comparable for the year ended December 31, 2025 relative to the comparative period in 2024.
Net transportation expenses for natural gas decreased on a per unit basis to $0.40/mcf and $0.49/mcf for the three months and year ended December 31, 2025, respectively, compared to $0.76/mcf and $0.73/mcf for the comparative periods in 2024 as a result of increased natural gas production from new wells at Two Rivers East being delivered to Westcoast Station 2 at lower transportation rates. Natural gas production exceeding the Company's 1.5 mmcf/d commitment to deliver to Chicago is being delivered to Westcoast Station 2.
Unutilized transportation is the portion of firm transportation agreements that the Company has committed to (less what has been assigned to other producers) that exceeds what the Company actually transported through pipelines for its produced natural gas volumes. See the "Contractual Obligations" section for more information related to firm transportation agreements. The Company actively manages its firm transportation commitments and has been successful in mitigating a portion of its 75.0 mmcf/d commitment to deliver natural gas to Westcoast Station 2. The Company has mitigated and reduced its Westcoast Station 2 commitment to approximately 40.6 mmcf/d through March 31, 2026 and to approximately 45.0 mmcf/d from April 1, 2026 to December 31, 2026.
COELACANTH ENERGY INC. - 8 - 2025 YEAR END REPORT
| OPERATING NETBACK ($000s) | Three Months Ended December 31 | Year Ended December 31 | ||||
|---|---|---|---|---|---|---|
| 2025 | 2024 | % Change | 2025 | 2024 | % Change | |
| Oil and natural gas sales | 11,603 | 4,544 | 155 | 30,469 | 13,736 | 122 |
| Royalties | (1,511) | (820) | 84 | (5,236) | (2,698) | 94 |
| Operating expenses | (2,759) | (786) | 251 | (7,031) | (3,335) | 111 |
| Net transportation expenses (non-GAAP) | (988) | (500) | 98 | (2,787) | (1,422) | 96 |
| Operating netback (non-GAAP) | 6,345 | 2,438 | 160 | 15,415 | 6,281 | 145 |
| Depletion and depreciation | (3,504) | (1,073) | 227 | (8,985) | (4,786) | 88 |
| General and administrative expenses | (2,226) | (1,540) | 45 | (6,615) | (5,049) | 31 |
| Share based compensation | (884) | (706) | 25 | (4,434) | (3,917) | 13 |
| Loss on lease termination | - | (201) | (100) | - | (201) | (100) |
| Finance expense | (1,821) | (1,797) | 1 | (5,837) | (2,230) | 162 |
| Finance income | 41 | 363 | (89) | 261 | 2,896 | (91) |
| Unutilized transportation | (132) | (387) | (66) | (831) | (1,891) | (56) |
| Net loss | (2,181) | (2,903) | (25) | (11,026) | (8,897) | 24 |
| ($/boe) | Three Months Ended December 31 | Year Ended December 31 | ||||
| --- | --- | --- | --- | --- | --- | --- |
| 2025 | 2024 | % Change | 2025 | 2024 | % Change | |
| Oil and natural gas sales | 31.32 | 45.57 | (31) | 35.82 | 39.01 | (8) |
| Royalties | (4.08) | (8.22) | (50) | (6.15) | (7.66) | (20) |
| Operating expenses | (7.45) | (7.88) | (5) | (8.26) | (9.47) | (13) |
| Net transportation expenses (non-GAAP) | (2.67) | (5.01) | (47) | (3.28) | (4.04) | (19) |
| Operating netback (non-GAAP) | 17.12 | 24.46 | (30) | 18.13 | 17.84 | 2 |
| Depletion and depreciation | (9.46) | (10.76) | (12) | (10.56) | (13.59) | (22) |
| General and administrative expenses | (6.01) | (15.46) | (61) | (7.78) | (14.34) | (46) |
| Share based compensation | (2.39) | (7.08) | (66) | (5.21) | (11.12) | (53) |
| Loss on lease termination | - | (2.02) | (100) | - | (0.57) | (100) |
| Finance expense | (4.91) | (18.02) | (73) | (6.86) | (6.33) | 8 |
| Finance income | 0.11 | 3.65 | (97) | 0.31 | 8.23 | (96) |
| Unutilized transportation | (0.36) | (3.88) | (91) | (0.98) | (5.37) | (82) |
| Net loss | (5.90) | (29.11) | (80) | (12.95) | (25.25) | (49) |
During the three months and year ended December 31, 2025, Coelacanth generated an operating netback (see "Non-GAAP and Other Financial Measures") of $17.12/boe and $18.13/boe, respectively, compared to $24.46/boe and $17.84/boe for the comparative periods in 2024. The decrease for the three months ended December 31, 2025 compared to 2024 was mainly the result of lower oil and NGLs pricing which was partially offset by stronger natural gas pricing and lower royalties, operating costs and net transportation costs discussed above. This decrease in oil and NGLs pricing was less prominent during the year ended December 31, 2025 than it was in the fourth quarter of 2025, and as a result, the operating netback for the year ended December 31, 2025 was consistent with the same period in 2024.
| DEPLETION AND DEPRECIATION | Three Months Ended | Year Ended | ||||
|---|---|---|---|---|---|---|
| December 31 | December 31 | |||||
| 2025 | 2024 | % Change | 2025 | 2024 | % Change | |
| Depletion and depreciation ($000s) | 3,504 | 1,073 | 227 | 8,985 | 4,786 | 88 |
| Depletion and depreciation ($/boe) | 9.46 | 10.76 | (12) | 10.56 | 13.59 | (22) |
The Company calculates depletion on development and production assets included in property, plant, and equipment ("PP&E") based on proved and probable oil and natural gas reserves. Certain facility and pipeline assets included within PP&E are being depreciated on a straight-line basis over their estimated useful lives of 30 years. Depletion and depreciation expense for the three months and year ended December 31, 2025 increased to $3.5 million and $9.0 million, respectively, from $1.1 million and $4.8 million for the comparative periods in 2024 as a result of increased production and cost base of PP&E. The Company commenced depleting and depreciating the Two Rivers East development project costs in June 2025 upon the transfer from exploration and evaluation assets to PP&E. On a per boe basis, depletion and depreciation for the three months and year ended December 31, 2025 decreased to $9.46/boe and $10.56/boe, respectively, from $10.76/boe and $13.59/boe for the comparative periods in 2024 as a result of increased proved and probable reserves.
Included in depletion and depreciation expense for the three months and year ended December 31, 2025, is $30 thousand (December 31, 2024 - $50 thousand) and $0.1 million (December 31, 2024 - $0.4 million), respectively, related to the Company's right-of-use assets.
COELACANTH ENERGY INC. - 9 - 2025 YEAR END REPORT
IMPAIRMENT OF PROPERTY, PLANT, AND EQUIPMENT AND EXPLORATION AND EVALUATION ASSETS
In June 2025, as a result of all wells being capable of production due to the completion of the new battery facility, the Company transferred its Two Rivers East development project costs from exploration and evaluation assets to PP&E. The Company completed the mandatory impairment test upon transfer and no impairment was recorded.
At December 31, 2025 and December 31, 2024, the Company evaluated its PP&E Two Rivers CGU for indicators of impairment or impairment reversal and as a result of this assessment management determined that an impairment test was not required to be performed.
At December 31, 2025 and December 31, 2024, the Company evaluated its exploration and evaluation assets and determined that there were no facts or circumstances suggesting that the carrying amount of its exploration and evaluation assets exceeded their recoverable amount, therefore, an impairment test was not required to be performed.
| GENERAL AND ADMINISTRATIVE ($000s) | Three Months Ended December 31 | Year Ended December 31 | ||||
|---|---|---|---|---|---|---|
| 2025 | 2024 | % Change | 2025 | 2024 | % Change | |
| G&A expenses (gross) | 2,626 | 2,160 | 22 | 7,244 | 5,964 | 21 |
| G&A capitalized | (400) | (620) | (35) | (629) | (915) | (31) |
| G&A expenses (net) | 2,226 | 1,540 | 45 | 6,615 | 5,049 | 31 |
| G&A expenses ($/boe) | 6.01 | 15.46 | (61) | 7.78 | 14.34 | (46) |
Net general and administrative ("G&A") expenses increased to $2.2 million and $6.6 million for the three months and year ended December 31, 2025, respectively, from $1.5 million and $5.0 million for the comparative periods in 2024 mainly due to higher employment costs and capital management fees.
On a per unit basis G&A was $6.01/boe and $7.78/boe for the three months and year ended December 31, 2025, respectively, compared to $15.46/boe and $14.34/boe for the comparative periods in 2024. Although G&A expenses increased in 2025 compared to 2024, on a per unit basis G&A expenses decreased in 2025 from 2024 due to the increased production from the initiation of commercial production at Two Rivers East.
| SHARE BASED COMPENSATION ($000s) | Three Months Ended December 31 | Year Ended December 31 | ||||
|---|---|---|---|---|---|---|
| 2025 | 2024 | % Change | 2025 | 2024 | % Change | |
| Share based compensation (gross) | 1,249 | 816 | 53 | 5,319 | 4,695 | 13 |
| Share based compensation (capitalized) | (365) | (110) | 232 | (885) | (778) | 14 |
| Share based compensation (net) | 884 | 706 | 25 | 4,434 | 3,917 | 13 |
| Share based compensation ($/boe) | 2.39 | 7.08 | (66) | 5.21 | 11.12 | (53) |
The Company accounts for its share based compensation plans using the fair value method. Under this method, compensation cost is charged to earnings over the vesting period for stock options and restricted share units ("RSUs") granted to officers, directors, employees, and consultants with a corresponding increase to contributed surplus.
Share based compensation expense totaled $0.9 million and $4.4 million for the three months and year ended December 31, 2025, respectively, consistent with $0.7 million and $3.9 million for the comparative periods in 2024. On a per unit basis share based compensation expenses decreased in 2025 from 2024 due to the increased production from the initiation of commercial production at Two Rivers East.
| FINANCE EXPENSE ($000s) | Three Months Ended December 31 | Year Ended December 31 | ||||
|---|---|---|---|---|---|---|
| 2025 | 2024 | % Change | 2025 | 2024 | % Change | |
| Interest expense on credit facility | 890 | 371 | 140 | 2,706 | 533 | 408 |
| Other obligations interest expense | 603 | 9 | 6,600 | 1,443 | 77 | 1,774 |
| Financing obligation payable | - | 1,350 | (100) | - | 1,350 | (100) |
| Amortization of financing costs | 251 | - | 100 | 786 | - | 100 |
| Accretion of other obligations | - | - | - | 614 | - | 100 |
| Accretion of decommissioning obligations | 77 | 67 | 15 | 288 | 270 | 7 |
| Finance expense | 1,821 | 1,797 | 1 | 5,837 | 2,230 | 162 |
| Finance expense ($/boe) | 4.91 | 18.02 | (73) | 6.86 | 6.33 | 8 |
Accretion expense on decommissioning obligations was consistent for the three months and year ended December 31, 2025 compared to the same periods in 2024. Interest expense relates to interest expense and standby fees on the credit facilities and outstanding letters of guarantee for firm transportation agreements and decommissioning obligations. The large increase for the year ended December 31, 2025 from the comparable period in 2024 stems from moving from a positive cash balance at December 31, 2024 to being drawn $58.8 million on the Company's credit facilities at December 31, 2025 as a result of capital expenditures during the past twelve months. The increase in interest on other obligations is the result of a $22.7 million obligation to a midstream company funding the extension of their gathering system to connect to the Company's Two Rivers East project. Commencing June 2025, the Company is required to repay the principal amount over a five-year period at an interest rate of 12.0%. Financing obligation payable relates to non-refundable third party fees to secure the initial one-year term of the previous $45.0 million credit facility.
COELACANTH ENERGY INC. - 10 - 2025 YEAR END REPORT
FINANCE INCOME
Finance income relates to interest earned on cash in the bank. Finance income totaled $41 thousand and $0.3 million for the three months and year ended December 31, 2025, respectively, compared to $0.4 million and $2.9 million for the comparative periods in 2024. The decrease corresponds to the decrease in the Company's cash balance over the comparative periods mainly due to capital expenditures during the past twelve months.
DEFERRED INCOME TAXES
The Company has not realized the net deferred income tax asset due to a history of losses and it is not probable that future taxable profits, based on the estimated cash flows derived from the independently evaluated reserve report, would be sufficient to realize the deferred income tax asset at this time.
Estimated tax pools at December 31, 2025 total approximately $325.9 million (December 31, 2024 - $264.9 million).
CASH FLOW FROM OPERATING ACTIVITIES AND ADJUSTED FUNDS FLOW
The following is a reconciliation of cash flow from operating activities to adjusted funds flow for the periods noted:
| ($000s) | Three Months Ended December 31 | Year Ended December 31 | ||||
|---|---|---|---|---|---|---|
| 2025 | 2024 | % Change | 2025 | 2024 | % Change | |
| Cash flow from operating activities | 4,852 | 3,157 | 54 | 8,906 | 2,203 | 304 |
| Add (deduct): | ||||||
| Decommissioning expenditures | 36 | 161 | (78) | 421 | 1,427 | (70) |
| Change in restricted cash deposits | (4,900) | (5,361) | (9) | (4,900) | (2,376) | 106 |
| Change in non-cash working capital | 2,322 | 2,425 | (4) | (1,584) | 261 | (707) |
| Adjusted funds flow (non-GAAP) | 2,310 | 382 | 505 | 2,843 | 1,515 | 88 |
Adjusted funds flow (see "Non-GAAP and Other Financial Measures") was $2.3 million ($nil per basic and diluted share) and $2.8 million ($0.01 per basic and diluted share) for the three months and year ended December 31, 2025, respectively, compared to $0.4 million ($nil per basic and diluted share) and $1.5 million ($nil per basic and diluted share) for the comparative periods in 2024. The increase for the three months and year ended December 31, 2025 was the result of increased production partially offset by increased interest expense, lower interest income and payments on the financing obligation. This is the result of the significant upfront capital costs associated with the Two Rivers East development project which commenced production in June 2025.
Cash flow from operating activities for the three months and year ended December 31, 2025 was $4.9 million ($0.01 per basic and diluted share) and $8.9 million ($0.02 per basic and diluted share), respectively, compared to $3.2 million ($0.01 per basic and diluted share) and $2.2 million ($nil per basic and diluted share) for the comparative periods in 2024. Cash flow from operating activities differs from adjusted funds flow due to the inclusion of changes in non-cash working capital, movements in restricted cash deposits and expenditures on decommissioning obligations.
NET LOSS
The Company incurred net losses of $2.2 million ($nil per basic and diluted share) and $11.0 million ($0.02 per basic and diluted share) for the three months and year ended December 31, 2025, respectively, compared to $2.9 million ($0.01 per basic and diluted share) and $8.9 million ($0.02 per basic and diluted share) for the comparative periods in 2024. The increase in 2025 compared to 2024 was mainly the result of increased depletion and depreciation resulting from increased production and cost base of PP&E partially offset by increased adjusted funds flow.
| CAPITAL EXPENDITURES | Three Months Ended December 31 | Year Ended December 31 | ||||
|---|---|---|---|---|---|---|
| 2025 | 2024 | % Change | 2025 | 2024 | % Change | |
| ($000s) | ||||||
| Land | 307 | 220 | 40 | 2,743 | 765 | 259 |
| Drilling, completions, and workovers | 30,142 | 29,273 | 3 | 30,975 | 38,353 | (19) |
| Equipment | 3,945 | 35,152 | (89) | 46,633 | 44,935 | 4 |
| Geological and geophysical | 142 | 307 | (54) | 263 | 444 | (41) |
| Total expenditures | 34,536 | 64,952 | (47) | 80,614 | 84,497 | (5) |
During the year ended December 31, 2025, the Company continued with facility procurement at Two Rivers East. Commercial production from Two Rivers East commenced with the completion of the facility in June 2025. In Q4 2025, the Company drilled and completed three Lower Montney wells expected to be on-stream late in Q1 2026.
During the year ended December 31, 2024, the Company continued with facility procurement at Two Rivers East and related gathering and transport pipelines. The Company drilled and completed three Lower Montney wells and completed a previously drilled Basal Montney well at Two Rivers East on the existing 5-19 pad. The Company also negotiated a reduction in royalties on certain lands in return for a royalty on additional lands.
COELACANTH ENERGY INC. - 11 - 2025 YEAR END REPORT
LIQUIDITY AND CAPITAL RESOURCES
Management uses adjusted working capital deficiency and net debt (see "Non-GAAP and Other Financial Measures") as measures to assess the Company's financial position and is reconciled as follows:
| ($000s) | December 31, 2025 | December 31, 2024 | % Change |
|---|---|---|---|
| Current assets | 6,119 | 11,579 | (47) |
| Less: | |||
| Current liabilities | (48,635) | (37,234) | 31 |
| Working capital deficiency | (42,516) | (25,655) | 66 |
| Add: | |||
| Restricted cash deposits | - | 4,900 | (100) |
| Current portion of other obligations | 4,037 | 110 | 3,570 |
| Current portion of decommissioning obligations | 545 | 2,118 | (74) |
| Adjusted working capital deficiency (Capital management measure) | (37,934) | (18,527) | 105 |
| Credit facility, non-current | (38,101) | - | 100 |
| Net debt (Capital management measure) | (76,035) | (18,527) | 310 |
To facilitate its capital expenditure program, the Company has an $80.0 million credit facility (refer to the "Liquidity and Capital Resources" section). At December 31, 2025, the Company had an adjusted working capital deficiency of $37.9 million which includes $19.9 million drawn under its credit facility and net debt of $76.0 million which includes $58.8 million drawn under its credit facility.
Exit 2025 production was 5,100 boe/d and exit Q1 2026 production was 8,000 boe/d with the ramp up of new wells on production on its 5-19 pad at Two Rivers East. This increase in production will help in reducing the adjusted working capital deficiency and net debt in 2026.
On November 18, 2025, the Company entered into an $80.0 million credit facility with a Canadian chartered bank to replace its previous credit facilities and returned the letter of credit to the third party. The new credit facility consists of a $10.0 million operating facility, a $50.0 million syndicated facility, and a $20.0 million term facility. The operating and syndicated facilities revolve for a 364 day period and will be subject to their next 364 day extension by May 31, 2026. If not extended, the credit facility will cease to revolve, the margins thereunder will increase by 0.50%, and all outstanding advances will become repayable in one year from the extension date (May 31, 2027). The term facility matures on May 31, 2026 and has been presented as a current liability on the statement of financial position.
Advances under the credit facility are available by way of prime rate loans, with interest rates between 2.00% and 4.00% over the Canadian prime lending rate and Canadian Overnight Repo Rate Average ("CORRA") loans which are subject to margins ranging from 3.00% to 5.00% depending upon the debt to EBITDA ratio of the Company as defined in the agreement. Standby fees are charged on the undrawn portion of the credit facility at rates ranging from 0.75% to 1.25%. Until delivery of the Q1 2026 compliance certificate, the prime rate margin is fixed at 3.0%, the CORRA margin is fixed at 4.0% and standby fees are fixed at 1.0%. The term facility margins are based on the applicable margins for the operating and syndicated facilities plus 2.5% and must be drawn first before the operating and syndicated facilities. The credit facility is secured by a $250.0 million fixed and floating charge debenture on the assets of the Company.
The credit facility includes a covenant requiring the Company to maintain an adjusted working capital ratio of not less than one-to-one. The adjusted working capital ratio, as defined in the agreement, is calculated as current assets plus any undrawn amounts available on the credit facility less current liabilities excluding amounts drawn on the credit facility. The definition of current assets and current liabilities excludes the fair value of risk management contracts and amounts associated with the pipeline obligation. The Company was compliant with this covenant at December 31, 2025.
Subsequent to December 31, 2025, the $20.0 million term facility was cancelled and replaced by an increase in the syndicated facility from $50.0 million to $80.0 million. The aggregate amended credit facility totals $90.0 million and will be subject to its next 364 day extension by May 31, 2027. If not extended, the credit facility will cease to revolve, the margins thereunder will increase by 0.50%, and all outstanding advances will become repayable in one year from the extension date (May 31, 2028). The adjusted working capital ratio covenant was also removed under the terms of the amended agreement. The next scheduled borrowing base review of the credit facility is scheduled on or before November 30, 2026.
On November 18, 2025, the Company entered into a standby letter of credit facility agreement with a third party of up to $10.0 million USD ($13.7 million CDN) to guarantee letters of credit issued by the Company to other third parties. The fee on drawn amounts under the facility are 2.82%. This facility returned $4.9 million of restricted cash deposits to the Company. At December 31, 2025, the Company has $10.1 million of standby letters of credit used against this facility (December 31, 2024 - $nil). Subsequent to December 31, 2025, an additional $1.7 million letters of credit were issued bringing the total to $11.8 million.
During the year ended December 31, 2025, the Company received $22.7 million from a midstream company to finance a pipeline connecting Coelacanth facilities to the midstream company's gathering system. Commencing June 2025, this amount will be repaid over a five-year period at an interest rate of 12.0%.
COELACANTH ENERGY INC. - 12 - 2025 YEAR END REPORT
CONTRACTUAL OBLIGATIONS
The following is a summary of the Company's contractual obligations and commitments at December 31, 2025:
| ($000s) | Total | Less than One Year | One to Three Years | After Three Years |
|---|---|---|---|---|
| Accounts payable and accrued liabilities | 24,278 | 24,278 | - | - |
| Credit facility - principal | 58,846 | 20,000 | 38,846 | - |
| Other obligations - principal | 21,949 | 4,037 | 9,543 | 8,369 |
| Decommissioning obligations | 9,595 | 545 | 479 | 8,571 |
| Operating commitments | 1,613 | 252 | 594 | 767 |
| Firm transportation agreements | 174,493 | 5,856 | 17,718 | 150,919 |
| Firm processing agreements | 122,602 | 10,192 | 23,999 | 88,411 |
| Total contractual obligations | 413,376 | 65,160 | 91,179 | 257,037 |
Operating commitments include the non-lease variable components (operating expenses) of the head office lease inclusive of the extension to July 31, 2031.
Transportation commitments include contracts to transport natural gas and NGLs through third-party owned pipeline systems. The Company currently has the following firm transportation commitments:
- 1.5 mmcf/d to deliver natural gas to the Alliance Trading Pool (ATP) through October 31, 2035 and then to Chicago through October 31, 2027.
- 10.0 mmcf/d to deliver natural gas to Westcoast Station 2 from January 1, 2023 through July 31, 2038.
- 50.0 mmcf/d to deliver natural gas to Westcoast Station 2 from June 1, 2023 through May 31, 2038.
- 15.0 mmcf/d to deliver natural gas to Westcoast Station 2 from May 1, 2024 through April 30, 2055.
- 25.0 mmcf/d to deliver natural gas to Westcoast Station 2 from August 1, 2028 through July 31, 2043.
The Company assigned the following contracts to third parties, thus reducing its commitment:
- 4.4 mmcf/d to deliver natural gas to Westcoast Station 2 from April 1, 2023 through March 31, 2026.
- 10.0 mmcf/d to deliver natural gas to Westcoast Station 2 from June 1, 2023 through December 31, 2027.
- 20.0 mmcf/d to deliver natural gas to Westcoast Station 2 from October 1, 2023 through October 31, 2026.
The impact of the reduced commitments are reflected in the table above.
Subsequent to December 31, 2025, the assignment of the contract for 20.0 mmcf/d to deliver natural gas to Westcoast Station 2 from October 1, 2023 through October 31, 2026 was extended with the third party for an additional year to October 31, 2027. This is expected to reduce the Company's transportation commitments by approximately $2.2 million.
Firm processing agreements include 30.0 mmcf/d of processing services at a gas processing facility for a period of 10 years. Effective July 1, 2026, the commitment increases to 40.0 mmcf/d for the remaining term. Under the terms of the processing agreement, the Company can elect prior to November 1, 2026 to increase by any volume up to an additional 20.0 mmcf/d (60.0 mmcf/d total) for the remainder of the original term. As part of the arrangement, the midstream company funded the extension of their gathering system to connect to the Company's Two Rivers East project. During the year ended December 31, 2025, the Company received $22.7 million from the midstream company. Commencing June 2025, the Company is required to repay the principal amount over a five-year period at an interest rate of 12.0%.
OFF BALANCE SHEET ARRANGEMENTS
The Company has certain lease arrangements, all of which are reflected in the contractual obligations and commitments table, which were entered into in the normal course of operations. All leases other than the fixed payment component of the head office lease and a field equipment vehicle lease have been treated as operating leases whereby the lease payments are included in operating expenses or general and administrative expenses depending on the nature of the lease.
RELATED PARTY TRANSACTIONS
For the year ended December 31, 2025, related party transactions included key management compensation. Refer to note 13 of the audited financial statements for further details.
OUTSTANDING SHARE DATA
The Company is authorized to issue an unlimited number of voting common shares, an unlimited number of non-voting common shares, Class A preferred shares, issuable in series, Class B preferred shares, issuable in series, and Class C preferred shares, issuable in series. The voting common shares of the Company commenced trading on the TSXV on June 20, 2022 under the symbol "CEI". The following table summarizes the common shares outstanding and the number of shares exercisable into common shares from options, warrants, and other instruments:
COELACANTH ENERGY INC. - 13 - 2025 YEAR END REPORT
(000s)
December 31, 2025
April 21, 2026
| Voting common shares | 533,465 | 536,104 |
|---|---|---|
| Warrants | 29,377 | 29,377 |
| Stock options | 21,587 | 30,171 |
| Restricted share units | 6,348 | 9,054 |
| Total | 590,777 | 604,706 |
Subsequent to December 31, 2025, the Company granted 8.6 million stock options with an exercise price of $0.80 per common share expiring five years from the date of grant and vest one-third on each of the first, second and third anniversaries of the date of grant. The Company also granted 5.4 million RSUs vesting one-third on each of the first, second and third anniversaries of the date of grant.
SUMMARY OF QUARTERLY RESULTS
| Q4 2025 | Q3 2025 | Q2 2025 | Q1 2025 | Q4 2024 | Q3 2024 | Q2 2024 | Q1 2024 | |
|---|---|---|---|---|---|---|---|---|
| Average Daily Production | ||||||||
| Oil and NGLs (bbls/d) | 1,316 | 1,464 | 566 | 209 | 502 | 254 | 323 | 337 |
| Natural gas (mcf/d) | 16,268 | 10,896 | 3,861 | 3,311 | 3,490 | 3,450 | 3,724 | 3,934 |
| Oil equivalent (boe/d) | 4,027 | 3,280 | 1,210 | 761 | 1,084 | 829 | 944 | 993 |
| ($000s, except per share amounts) | ||||||||
| Oil and natural gas sales | 11,603 | 11,372 | 4,828 | 2,666 | 4,544 | 2,362 | 3,164 | 3,666 |
| Cash flow from (used in) | ||||||||
| operating activities | 4,852 | 4,712 | (1,826) | 1,168 | 3,157 | (3,730) | (480) | 3,256 |
| Per share basic and diluted(2) | 0.01 | 0.01 | (-) | - | 0.01 | (0.01) | (-) | 0.01 |
| Adjusted funds flow (used)(1) | 2,310 | 2,386 | (600) | (1,253) | 382 | (207) | 262 | 1,078 |
| Per share basic and diluted | - | - | (-) | (-) | - | (-) | - | - |
| Net loss | (2,181) | (1,764) | (3,464) | (3,617) | (2,903) | (2,464) | (2,329) | (1,201) |
| Per share basic and diluted | (-) | (-) | (0.01) | (0.01) | (0.01) | (-) | (-) | (-) |
(1) Adjusted funds flow (used) and adjusted funds flow (used) per share do not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures used by other companies. Please refer to the "Non-GAAP and Other Financial Measures" section for more details and the "Cash Flow From Operating Activities and Adjusted Funds Flow" section for a reconciliation from cash flow from operating activities.
(2) Supplemental financial measure. Please refer to the "Non-GAAP and Other Financial Measures" section for more details.
The increase in production, oil and natural gas sales, cash flow from operating activities, and adjusted funds flow in the last six months of 2025 was the result of the initiation of commercial production at Two Rivers East.
The increase in production, oil and natural gas sales, cash flow from operating activities, and adjusted funds flow in Q4 2024 stems from the testing of new wells at Two Rivers East during Q4 2024. The decrease in Q1 2025 production from Q4 2024 was natural declines and the lack of testing new wells in Q1 2025. The decrease in cash flow from operations and adjusted funds flow and the increase in net loss in the first half of 2025 was mainly the result of increased interest expense, lower interest income, and payments on financing obligation. Oil and natural gas sales, cash flow from (used in) operating activities and adjusted funds flow (used) generally followed the same trend as production with some exceptions based on volatility of commodity prices received.
MATERIAL ACCOUNTING POLICIES
All accounting policies are consistent with those of the previous financial year. Refer to note 3 of the audited financial statements for the year ended December 31, 2025 for the Company's material accounting policies.
FUTURE ACCOUNTING PRONOUNCEMENTS
IFRS 18 Presentation and Disclosure in Financial Statements was issued by the IASB in April 2024. IFRS 18 introduces defined categories for income and expenses and certain defined subtotals in the statement of operations and comprehensive income (loss), required disclosures of certain management-defined performance measures, and aggregation and disaggregation principles for the grouping of information in the financial statements. IFRS 18 will replace IAS 1 and is effective for annual periods beginning on or after January 1, 2027. The standard requires retrospective application with early adoption permitted. The Company is currently evaluating the impact of adopting IFRS 18 on the financial statements.
In May 2024, the IASB issued amendments to IFRS 9 Financial Instruments and IFRS 7 Financial Instruments: Disclosures regarding the settlement of financial liabilities via electronic payment systems and the assessment of contractual cash flow characteristics of financial assets. The amendments are effective for annual periods beginning on or after January 1, 2026, and require retrospective application with early adoption permitted. The Company is currently evaluating the impact of adoption on its financial statements.
COELACANTH ENERGY INC. - 14 - 2025 YEAR END REPORT
CRITICAL ACCOUNTING ESTIMATES
Management is required to make estimates, judgments, and assumptions in the application of IFRS that affect the reported amounts of assets and liabilities at the date of the financial statements and revenues and expenses for the period then ended. Certain of these estimates may change from period to period resulting in a material impact on the Company's results from operations and financial position (see note 2d in the notes to the Company's December 31, 2025 financial statements for full descriptions of the use of estimates and judgments).
RISK ASSESSMENT
The acquisition, exploration, and development of oil and natural gas properties involves many risks common to all participants in the oil and natural gas industry. Coelacanth's exploration and development activities are subject to various business risks such as unstable commodity prices, interest rate and foreign exchange rate fluctuations, the uncertainty of replacing production and reserves on an economic basis, government regulations including implementation of new, or expansion of existing, tariffs on exported and/or imported products, taxes, and safety and environmental concerns. While management realizes these risks cannot be eliminated, they are committed to monitoring and mitigating these risks.
Reserves and reserve replacement
The recovery and reserve estimates on Coelacanth's properties are estimates only and the actual reserves may be materially different from that estimated. The estimates of reserve values are based on a number of variables including: forecasted oil and natural gas commodity prices, forecasted production, forecasted operating costs, forecasted royalty costs and forecasted future development costs. All of these factors may cause estimates to vary from actual results.
Coelacanth's future oil and natural gas reserves, production, and adjusted funds flow to be derived therefrom are highly dependent on the Company successfully acquiring or discovering new reserves. Without the continual addition of new reserves, any existing reserves the Company may have at any particular time and the production therefrom will decline over time as such existing reserves are exploited. A future increase in Coelacanth's reserves will depend on its ability to acquire suitable prospects or properties and discover new reserves.
To mitigate this risk, Coelacanth has assembled a team of experienced technical professionals who have expertise operating and exploring in areas the Company has identified as being the most prospective for increasing reserves on an economic basis. To further mitigate reserve replacement risk, Coelacanth has targeted a majority of its prospects in areas which have multi-zone potential, year-round access, and lower drilling costs and employs advanced geological and geophysical techniques to increase the likelihood of finding additional reserves.
Operational risks
Coelacanth's operations are subject to the risks normally incidental to the operation and development of oil and natural gas properties and the drilling of oil and natural gas wells. Continuing production from a property, and to some extent the marketing of production therefrom, are largely dependent upon the ability of the operator of the property.
Market risk
Market risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate because of changes in market prices. Market risk is comprised of foreign exchange risk, interest rate risk, and other price risk, such as commodity price risk. The objective of market risk management is to manage and control market price exposures within acceptable limits, while maximizing returns. The Company may use financial derivatives or physical delivery sales contracts to manage market risks. All such transactions are conducted within risk management tolerances that are reviewed by the Board of Directors.
Foreign exchange risk
The prices received by the Company for the production of oil, natural gas, and NGLs are primarily determined in reference to US dollars, but are settled with the Company in Canadian dollars. The Company's cash flow from commodity sales will therefore be impacted by fluctuations in foreign exchange rates. The Company currently does not have any foreign exchange contracts in place.
Interest rate risk
The Company is exposed to interest rate risk on its cash and credit facility balances. The Company currently does not use interest rate hedges or fixed interest rate contracts to manage the Company's exposure to interest rate fluctuations. The amount drawn on the Company's credit facilities at December 31, 2025 was $58.8 million (December 31, 2024 - $nil). A 100 basis point increase or decrease in interest rates would have impacted net loss by approximately $0.4 million for the year ended December 31, 2025 (December 31, 2024 - $nil).
Commodity price risk
Oil and natural gas prices are impacted by not only the relationship between the Canadian and US dollar but also by world economic events that dictate the levels of supply and demand. The Company's oil, natural gas, and NGLs production is marketed and sold on the spot market to area aggregators based on daily spot prices that are adjusted for product quality and transportation costs. The Company's cash flow from product sales will therefore be impacted by fluctuations in commodity prices. In addition, the Company may enter into commodity price contracts to manage future cash flows.
At December 31, 2025, the Company had the following commodity price contracts outstanding:
| Commodity | Period | Type of Contract | Quantity | Contract Price |
|---|---|---|---|---|
| Oil | January 1, 2026 - April 30, 2026 | Physical Sales | 500 bbls/d | WTI CDN $86.86/bbl |
| Natural Gas | January 1, 2026 - March 31, 2026 | Physical Sales | 10,000 GJ/d | Westcoast Station 2 CDN $2.49/GJ |
COELACANTH ENERGY INC. - 15 - 2025 YEAR END REPORT
Subsequent to December 31, 2025, the Company entered into the following commodity price contracts:
| Commodity | Period | Type of Contract | Quantity | Contract Price |
|---|---|---|---|---|
| Oil | May 1, 2026 - June 30, 2026 | Physical Sales | 500 bbls/d | WTI CDN $85.69/bbl |
Credit risk
Credit risk represents the financial loss that the Company would suffer if the Company's counterparties to a financial asset fail to meet or discharge their obligation to the Company. A substantial portion of the Company's accounts receivable are with customers and joint interest partners in the oil and natural gas industry and are subject to normal industry credit risks. The Company generally grants unsecured credit but routinely assesses the financial strength of its customers and joint interest partners.
The Company sells the majority of its production to three oil and natural gas marketers and therefore is subject to concentration risk. Historically, the Company has not experienced any collection issues with its oil and natural gas marketers. Joint interest receivables are typically collected within one to three months of the joint interest billing being issued to the partner. The Company attempts to mitigate the risk from joint interest receivables by obtaining partner approval for significant capital expenditures prior to the expenditure being incurred. The Company does not typically obtain collateral from oil and natural gas marketers or joint interest partners; however, in certain circumstances, the Company may cash call a partner in advance of expenditures being incurred.
The maximum exposure to credit risk is represented by the carrying amount of cash, restricted cash deposits and accounts receivable on the statement of financial position. At December 31, 2025, $5.6 million (>99%) of the Company's outstanding accounts receivable were current and $17 thousand (<1%) were outstanding for more than 90 days. During the year ended December 31, 2025, the Company deemed $55 thousand of outstanding accounts receivable to be uncollectable (December 31, 2024 - $35 thousand).
Cash and restricted cash deposits consist of bank balances placed with a financial institution with strong investment grade ratings which management believes the risk of loss to be remote. The Company manages the credit risk exposure related to risk management contracts by selecting investment grade financial institution counterparties and by not entering into contracts for trading or speculative purposes.
Liquidity risk
Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due. The Company's processes for managing liquidity risk includes ensuring, to the extent possible, that it will have sufficient liquidity to meet its liabilities when they become due. The Company prepares annual, quarterly, and monthly capital expenditure budgets, which are monitored and updated as required, and requires authorizations for expenditures on projects to assist with the management of capital.
To facilitate its capital expenditure program, the Company has an $80.0 million credit facility (refer to the "Liquidity and Capital Resources" section). At December 31, 2025, the Company had an adjusted working capital deficiency of $37.9 million, which includes $19.9 million drawn under its credit facility, and net debt of $76.0 million which includes $58.8 million drawn under its credit facility.
Subsequent to December 31, 2025, the $20.0 million term facility was cancelled and replaced by an increase in the syndicated facility from $50.0 million to $80.0 million. The aggregate amended credit facility totals $90.0 million and will be subject to its next 364 day extension by May 31, 2027. If not extended, the credit facility will cease to revolve, the margins thereunder will increase by 0.50%, and all outstanding advances will become repayable in one year from the extension date (May 31, 2028). The adjusted working capital ratio covenant was also removed under the terms of the amended agreement. The next scheduled borrowing base review of the credit facility is scheduled on or before November 30, 2026.
With the completion of the Two Rivers East development project, the resultant production from the 5-19 pad, and the expanded credit facility, the Company anticipates that it will have sufficient lending capacity and operational cash flows to meet its current and future obligations, to make any scheduled credit facility and associated interest payments, and to fund the other needs of the business for at least the next 12 months. Coelacanth's capital program is flexible and can be adjusted as needed based upon the current economic environment. The Company will continue to monitor the economic environment and the possible impact on its business and strategy and will make adjustments as necessary.
During the year ended December 31, 2025, the Company received $22.7 million from a midstream company to finance a pipeline connecting Coelacanth facilities to the midstream company's gathering system. Commencing June 2025, this amount will be repaid over a five-year period at an interest rate of 12.0%.
Safety and Environmental Risks
The oil and natural gas business is subject to extensive regulation pursuant to various municipal, provincial, national, and international conventions and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases, or emissions of various substances produced in association with oil and natural gas operations. Coelacanth is committed to meeting and exceeding its environmental and safety responsibilities. Coelacanth has implemented an environmental and safety policy that is designed, at a minimum, to comply with current governmental regulations set for the oil and natural gas industry. Changes to governmental regulations are monitored to ensure compliance. Environmental reviews are completed as part of the due diligence process when evaluating acquisitions. Environmental and safety updates are presented and discussed at each Board of Directors meeting. Coelacanth maintains adequate insurance commensurate with industry standards to cover reasonable risks and potential liabilities associated with its activities as well as insurance coverage for officers and directors executing their corporate duties. To the knowledge of management, there are no legal proceedings to which Coelacanth is a party or of which any of its property is the subject matter, nor are any such proceedings known to Coelacanth to be contemplated.
COELACANTH ENERGY INC. - 16 - 2025 YEAR END REPORT
Geopolitical Risks
Existing or future conflicts in major oil and gas producing nations and the international response may have potential wide-ranging consequences for global market volatility and economic conditions, including affecting oil and natural gas prices. Financial and trade sanctions that may be imposed against countries involved in such conflicts may have continued far-reaching effects on the global economy, energy and commodity prices. The implications of any such conflicts is difficult to predict with any degree of certainty. Depending on the extent, duration, and severity of such conflicts, it may have the effect of heightening many of the other risks described herein, including, without limitation, risks relating to global market volatility and economic conditions; cybersecurity threats; oil and natural gas prices; inflationary pressures, interest rates and costs of capital; change in trade relations and policies, including the potential for tariffs; and supply chains and cost-effective and timely transportation.
For additional information on the risks relating to the Company's business, see the "Risk Factors" section contained in the Company's annual information form for the year ended December 31, 2025, which is available on the SEDAR+ website at www.sedarplus.com.
PRODUCT TYPES
The Company uses the following references to sales volumes in the MD&A:
Natural gas refers to shale gas
Oil and condensate refers to condensate and tight oil combined
Other NGLs refers to butane, propane and ethane combined
Oil and NGLs refers to tight oil and NGLs combined
Oil equivalent refers to the total oil equivalent of shale gas, tight oil, and NGLs combined, using the conversion rate of six thousand cubic feet of shale gas to one barrel of oil equivalent as described above.
The following is a complete breakdown of sales volumes for applicable periods by specific product types of shale gas, tight oil, and NGLs:
| Sales Volumes by Product Type | Q4 2025 | Q3 2025 | Q2 2025 | Q1 2025 | Q4 2024 | Q3 2024 | Q2 2024 | Q1 2024 |
|---|---|---|---|---|---|---|---|---|
| Condensate (bbls/d) | 109 | 46 | 17 | 18 | 22 | 33 | 56 | 19 |
| Other NGLs (bbls/d) | 165 | 92 | 27 | 25 | 29 | 33 | 39 | 37 |
| NGLs (bbls/d) | 274 | 138 | 44 | 43 | 51 | 66 | 95 | 56 |
| Tight oil (bbls/d) | 1,042 | 1,326 | 522 | 166 | 451 | 188 | 228 | 281 |
| Condensate (bbls/d) | 109 | 46 | 17 | 18 | 22 | 33 | 56 | 19 |
| Oil and condensate (bbls/d) | 1,151 | 1,372 | 539 | 184 | 473 | 221 | 284 | 300 |
| Other NGLs (bbls/d) | 165 | 92 | 27 | 25 | 29 | 33 | 39 | 37 |
| Oil and NGLs (bbls/d) | 1,316 | 1,464 | 566 | 209 | 502 | 254 | 323 | 337 |
| Shale gas (mcf/d) | 16,268 | 10,896 | 3,861 | 3,311 | 3,490 | 3,450 | 3,724 | 3,934 |
| Natural gas (mcf/d) | 16,268 | 10,896 | 3,861 | 3,311 | 3,490 | 3,450 | 3,724 | 3,934 |
| Oil equivalent (boe/d) | 4,027 | 3,280 | 1,210 | 761 | 1,084 | 829 | 944 | 993 |
FORWARD-LOOKING INFORMATION
This document contains forward-looking statements and forward-looking information within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", "may", "will", "should", "believe", "intends", "forecast", "plans", "guidance" and similar expressions are intended to identify forward-looking statements or information.
More particularly and without limitation, this MD&A contains forward-looking statements and information relating to the Company's oil and condensate, other NGLs, and natural gas production, royalty rates, capital programs and expenditure plans for 2026 and 2027; drilling plans, including the anticipated drilling of a 5 or 6 well development pad in the summer of 2026; the timing of wells being placed on production, including the expectation that additional wells will be placed on production by the end of April 2026; anticipated delineation activities and resource potential; the anticipated closing of the $80.0 million equity raise on or around May 6, 2026; the Company's business plan, including expectations regarding year-over-year production growth; adjusted working capital; and the Company's expectations regarding future reserve bookings. The forward-looking statements and information are based on certain key expectations and assumptions made by the Company, including expectations and assumptions relating to prevailing commodity prices and exchange rates, applicable royalty rates and tax laws, future well production rates, the performance of existing wells, the success of drilling new wells, the availability of capital to undertake planned activities, and the availability and cost of labour and services. Specific assumptions underlying the forward-looking statements in this news release include: that the equity raise will close on the terms and timeline currently contemplated; that the Company will continue to have access to capital under its $90.0 million credit facility; that the summer 2026 drilling program will proceed on the currently anticipated timeline; that well performance will be consistent with results from existing wells at Two Rivers East; that commodity prices will remain at levels that support the Company's development plans; that there will be no material delays in regulatory approvals or permitting; and that the Company's delineation program will confirm the existence of commercial hydrocarbon quantities across the Montney zones.
Although the Company believes that the expectations reflected in such forward-looking statements and information are reasonable, it can give no assurance that such expectations will prove to be correct. Since forward-looking statements and information address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results may differ materially from those currently
COELACANTH ENERGY INC. - 17 - 2025 YEAR END REPORT
anticipated due to a number of factors and risks. These include, but are not limited to, the risks associated with the oil and gas industry in general such as operational risks in development, exploration and production, delays or changes in plans with respect to exploration or development projects or capital expenditures, the uncertainty of estimates and projections relating to production rates, costs, and expenses, commodity price and exchange rate fluctuations, marketing and transportation, environmental risks, competition, the ability to access sufficient capital from internal and external sources and changes in tax, royalty, and environmental legislation. Additional material risks specific to the forward-looking statements in this news release include: the risk that the equity raise may not close on the anticipated terms or timeline, which could affect the Company's ability to execute its capital program; the risk that well performance may vary materially from expectations, which could affect production targets; the risk that delineation drilling may not confirm the Company's expectations regarding resource potential in the Montney zones; the risk that infrastructure capacity constraints may delay bringing new wells on production; and the risk that the Company may not be able to access capital under its credit facility on the anticipated terms. All statements regarding timing, including anticipated closing dates, production commencement dates, and drilling schedules, are estimates only and are subject to change based on operational, regulatory, and market conditions. Readers are cautioned not to place undue reliance on forward-looking statements, as there can be no assurance that the plans, intentions, or expectations upon which they are based will occur. The forward-looking statements and information contained in this document are made as of the date hereof for the purpose of providing the readers with the Company's expectations for the coming year. The forward-looking statements and information may not be appropriate for other purposes. The Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.
ADDITIONAL INFORMATION
In addition to the information disclosed in this MD&A, more detailed information related to the Company can be found on the SEDAR+ website at www.sedarplus.com.
COELACANTH ENERGY INC. - 18 - 2025 YEAR END REPORT