Coelacanth Energy Inc. (TSXV: CEI) (‘Coelacanth’ or the ‘Company’) is pleased to announce its 2024 year-end reserves as independently evaluated by GLJ Ltd. (‘GLJ’) effective December 31, 2024 (the ‘GLJ Report’ or the ‘Report’), in accordance with National Instrument 51-101 (‘NI 51-101’) and the Canadian Oil and Gas Evaluation (‘COGE’) Handbook. All dollar figures are Canadian dollars unless otherwise noted.

Introduction

During 2024, Coelacanth drilled an additional 3 Lower Montney wells on its 5-19 pad and started the construction of pipelines and facilities to allow for the production of all 9 wells on the 5-19 pad to come on production in Q2 2025. The 9 wells consist of 7 Lower Montney wells, 1 Upper Montney well and 1 Basal Montney well that have tested over 11,000 boe/d (flush production) ⁽¹⁾. On completion of phase 1 of the facility in May 2025, Coelacanth will have capacity to produce 30.0 mmcf/d of gas plus the concurrent oil production for a combined capacity of approximately 7,500-8,000 boe/d. Phase 2 (adding compression) is scheduled for Q4 2025 and will double capacity.

Coelacanth almost doubled its reserves from 2023 while still only having recognized reserves on less than 10% of its 150 section Montney land block at Two Rivers. A total of 23 combined wells and locations are included in the Report comprised of 13 drilled and completed Montney wells plus 10 Montney undeveloped locations. The 13 existing wells include 8 Lower Montney wells, 4 Upper Montney wells, and 1 Basal Montney well. All 10 undeveloped locations booked were Lower Montney leaving potential to book additional Upper and Basal Montney wells on the same lands. Coelacanth believes it has been conservative in its bookings and, over time, will be able to expand the current reserve base to cover a greater portion of the land base.

The Report includes a total of $148.3 million of future development capital (‘FDC’) of which $33.5 million is in Jan-May of 2025 for phase 1 of the facility. By the end of May, the capital for phase 1 of the facility will have been spent and all of the proved developed non-producing and probable developed non-producing reserves will change to producing status. These adjustments will have a material effect on the Report given the FDC for phase 1 of the facility will be removed (thereby increasing the overall value) and the producing portion of the Report will increase dramatically with wells coming on production. Coelacanth is planning to engage GLJ to provide a mid-year update of the Report to better illustrate the magnitude of the changes.

Coelacanth’s business plan for the Two Rivers Montney Project includes:

• Delineating and establishing production on multiple Montney zones over its extensive land base.
• Accelerating production through pad drilling once initial infrastructure is complete.
• Licensing and constructing additional facilities and pipelines to process future production additions.

Coelacanth is currently:

• Finalizing the construction of Two Rivers East facility to accommodate the 5-19 pad production.
• Licensing additional pads for future development.
• Completing a third-party resource study to aid in well spacing and completion design as well as future delineation.
• Completing a detailed review of Two Rivers for well development and future infrastructure requirements.

Coelacanth is excited to initiate its business plan to systematically develop the property, establish the ultimate reserve recoveries and move the established recoverable resource from land to its established producing reserve base.

Reserve Highlights

Coelacanth is pleased to report material increases in both reserves and value:

• Increased Total Proved plus Probable reserves by 95% to 27.5 million boe from 14.1 million boe.
• Increased Total Proved reserves by 63% to 17.1 million boe from 10.5 million boe.
• Increased Total Proved plus Probable Reserve value (net present value before taxes, discounted at 10%) by 155% to $239.6 million from $93.9 million.

Notes:
(1) See ‘Test Results and Initial Production Rates’.

Reserves Summary

Coelacanth’s December 31, 2024 reserves as prepared by GLJ effective December 31, 2024 and based on the GLJ (2025-01) future price forecast are as follows: ^(1,4)

Notes:
(1) Numbers may not add due to rounding.
(2) ‘Working Interest’ or ‘Gross’ reserves means Coelacanth’s working interest (operating and non-operating) share before deduction of royalties and without including any royalty interest of Coelacanth.
(3) Oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil.
(4) Disclosure of Net reserves are included in Company’s Annual Information Form (‘AIF’) dated April 23, 2025 filed on SEDAR+ at www.sedarplus.ca. ‘Net’ reserves means Coelacanth’s working interest (operated and non-operated) share after deduction of royalties, plus Coelacanth’s royalty interest in reserves.

Reserves Values

The estimated future net revenues before taxes associated with Coelacanth’s reserves effective December 31, 2024 and based on the GLJ (2025-01) future price forecast are summarized in the following table: ^(1,2,3,4)

Notes:
(1) Numbers may not add due to rounding.
(2) The estimated future net revenues are stated prior to provision for interest, debt service charges or general administrative expenses and after deduction of royalties, operating costs, estimated well abandonment and reclamation costs and estimated future capital expenditures.
(3) The estimated future net revenue contained in the table does not necessarily represent the fair market value of the reserves. There is no assurance that the forecast price and cost assumptions contained in the GLJ Report will be attained and variations could be material. The recovery and reserve estimates described herein are estimates only. Actual reserves may be greater or less than those calculated.
(4) The after-tax present values of future net revenue attributed to Coelacanth’s reserves are included in Company’s AIF dated April 23, 2025 filed on SEDAR+ at www.sedarplus.ca.

Price Forecast

The GLJ (2025-01) price forecast is as follows:

Note:
(1) Escalated at two per cent per year starting in 2034 in the January 1, 2025 GLJ price forecast with the exception of foreign exchange, which remains flat.

Reserve Life Index (‘RLI’)

Coelacanth’s RLI presented below is based on estimated Q4 2024 average production of 1,084 boe per day.

Reserves Reconciliation

The following summary reconciliation of Coelacanth’s working interest reserves compares changes in the Company’s reserves as at December 31, 2024 to the reserves as at December 31, 2023 based on the GLJ (2025-01) future price forecast: ^(1,2)

Notes:
(1) Numbers may not add due to rounding.
(2) ‘Working Interest’ or ‘Gross’ reserves means Coelacanth’s working interest (operating and non-operating) share before deduction of royalties and without including any royalty interest of Coelacanth.
(3) Oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil.

Capital Expenditures

Capital allocation by category is as follows:

Finding and Development Costs (‘F&D’) and Finding, Development and Acquisition Costs (‘FD&A’)

Coelacanth has presented FD&A and F&D costs below:

Notes:
(1) Future development capital (‘FDC’) expenditures required to recover reserves estimated by GLJ. The aggregate of the exploration and development costs incurred in the most recent financial period and the change during that period in estimated future development costs generally may not reflect total finding and development costs related to reserve additions for that period.
(2) Sum of extensions and improved recovery, technical revisions and economic factors in the reserves reconciliation included above.

For Coelacanth’s full NI 51-101 disclosure related to its 2024 year-end reserves please refer to the Company’s AIF dated April 23, 2025 filed on SEDAR+ at www.sedarplus.ca.

Forward-Looking Information

This news release 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 document contains forward-looking statements and information relating to the Company’s oil, NGLs and natural gas production and reserves and reserves values, capital programs, and oil, NGLs, and natural gas commodity prices. 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 labor and services.

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 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. 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.

Reserves Data

There are numerous uncertainties inherent in estimating quantities of tight oil, shale gas, and NGLs reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth above are estimates only. In general, estimates of economically recoverable tight oil, shale gas, and NGLs 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 natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially.

Individual properties may not reflect the same confidence level as estimates of reserves for all properties due to the effects of aggregation.

This news release contains estimates of the net present value of the Company’s future net revenue from its reserves. Such amounts do not represent the fair market value of the Company’s reserves.

The reserves data contained in this news release has been prepared in accordance with National Instrument 51-101 (‘NI 51-101’). The reserve data provided in this news release presents only a portion of the disclosure required under NI 51-101. All of the required information will be contained in the Company’s Annual Information Form for the year ended December 31, 2024, filed on SEDAR+ at www.sedarplus.ca.

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 the analysis of drilling, geological, geophysical and engineering data; the use of established technology, and specified economic conditions, which are generally accepted as being reasonable. Reserves are classified according to the degree of certainty associated with the estimates as follows:

• 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.

• 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.

Industry Metrics

This news release contains metrics commonly used in the oil and natural gas industry. Each of these metrics is determined by the Company as set out below or elsewhere in this news release. These metrics are ‘F&D costs’, ‘FD&A costs’, and ‘reserve-life index’. These metrics do not have standardized meanings and may not be comparable to similar measures presented by other companies. As such, they should not be used to make comparisons.

Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare the Company’s performance over time, however, such measures are not reliable indicators of the Company’s future performance and future performance may not compare to the performance in previous periods.

‘F&D costs’ are calculated by dividing the sum of the total capital expenditures for the year (in dollars) by the change in reserves within the applicable reserves category (in boe). F&D costs, including FDC, includes all capital expenditures in the year as well as the change in FDC required to bring the reserves within the specified reserves category on production.

‘FD&A costs’ are calculated by dividing the sum of the total capital expenditures for the year inclusive of the net acquisition costs and disposition proceeds (in dollars) by the change in reserves within the applicable reserves category inclusive of changes due to acquisitions and dispositions (in boe). FD&A costs, including FDC, includes all capital expenditures in the year inclusive of the net acquisition costs and disposition proceeds as well as the change in FDC required to bring the reserves within the specified reserves category on production.

The Company uses F&D and FD&A as a measure of the efficiency of its overall capital program including the effect of acquisitions and dispositions. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.

‘Reserve life index’ or ‘RLI’ is calculated by dividing the reserves (in boe) in the referenced category by the latest quarter of production (in boe) annualized. The Company uses this measure to determine how long the booked reserves will last at current production rates if no further reserves were added.

BOE Conversions

BOE’s may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf: 1 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.

Abbreviations

Test Results and Initial Production Rates

The 5-19 Lower Montney well was production tested for 9.4 days and produced at an average rate of 377 bbl/d oil and 2,202 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.

The A5-19 Basal Montney well was production tested for 5.9 days and produced at an average rate of 117 bbl/d oil and 630 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.

The B5-19 Upper Montney well was production tested for 6.3 days and produced at an average rate of 92 bbl/d oil and 2,100 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.

The C5-19 Lower Montney well was production tested for 5.8 days and produced at an average rate of 736 bbl/d oil and 2,660 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.

The D5-19 Lower Montney well was production tested for 12.6 days and produced at an average rate of 170 bbl/d oil and 580 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.

The E5-19 Lower Montney well was production tested for 11.4 days and produced at an average rate of 312 bbl/d oil and 890 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure was stable, and production was starting to decline.

The F5-19 Lower Montney well was production tested for 4.9 days and produced at an average rate of 728 bbl/d oil and 1,607 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.

The G5-19 Lower Montney well was production tested for 7.1 days and produced at an average rate of 415 bbl/d oil and 1,489 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.

The H5-19 Lower Montney well was production tested for 8.1 days and produced at an average rate of 411 bbl/d oil and 1,166 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure was stable and production was starting to decline.

A pressure transient analysis or well-test interpretation has not been carried out on these nine wells and thus certain of the test results provided herein should be considered to be preliminary until such analysis or interpretation has been completed. Test results and initial production rates disclosed herein, particularly those short in duration, may not necessarily be indicative of long-term performance or of ultimate recovery.

Any references to peak rates, test rates, IP30, IP90, IP180 or initial production rates or declines are useful for confirming the presence of hydrocarbons, however, such rates and declines are not determinative of the rates at which such wells will continue production and decline thereafter and are not indicative of long-term performance or ultimate recovery. IP30 is defined as an average production rate over 30 consecutive days, IP90 is defined as an average production rate over 90 consecutive days and IP180 is defined as an average production rate over 180 consecutive days. Readers are cautioned not to place reliance on such rates in calculating aggregate production for the Company.

Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.

To view the source version of this press release, please visit https://www.newsfilecorp.com/release/249585

Coelacanth Energy Inc. (TSXV: CEI) (‘Coelacanth’ or the ‘Company’) is pleased to announce its financial and operating results for the three months and year ended December 31, 2024. All dollar figures are Canadian dollars unless otherwise noted.

2024 HIGHLIGHTS

• Drilled and completed three Lower Montney wells and completed a previously drilled Upper Montney well on its 5-19 pad at Two Rivers East. Average test production from the three Lower Montney wells was 1,624 boe/d (61% light oil) and test production from the Upper Montney well was 1,338 boe/d (54% light oil). ⁽²⁾

• Secured revolving bank credit facilities for a total of $52.0 million from a Canadian chartered bank.

• Substantially completed construction of pipelines to connect the 5-19 pad wells to the Two Rivers East facility.

• Initiated construction of its Two Rivers East facility for a Q2 2025 on-stream date.

(1) See ‘Non-GAAP and Other Financial Measures’ section.
(2) See ‘Test Results and Initial Production Rates’ section.

(1) See ‘Oil and Gas Terms’ section.
(2) See ‘Product Types’ section.
(3) See ‘Non-GAAP and Other Financial Measures’ section.

Selected financial and operational information outlined in this news release should be read in conjunction with Coelacanth’s audited financial statements and related Management’s Discussion and Analysis (‘MD&A’) for the year ended December 31, 2024, which are available for review under the Company’s profile on SEDAR+ at www.sedarplus.ca.

OPERATIONS UPDATE

In Q4 2024, Coelacanth achieved two more significant milestones in its vision of moving the Two Rivers Montney Project from a large Montney land block to a proven resource with decades of inventory.

In 2022 and 2023, Coelacanth was able to prove productivity in the Lower Montney over a significant portion of lands at Two Rivers that allowed for the decision to build-out infrastructure and to continue pad drilling at Two Rivers East. During 2024, Coelacanth completed the licensing phase of the infrastructure and started construction while also continuing to develop the Montney resource.

In Q4 2024, Coelacanth was able to substantially complete all pipelines required for its 5-19 pad that connected it from the pad to the future facility and then on to a midstream gathering system. Concurrently, Coelacanth completed a successful Upper Montney well at Two Rivers East and changed the completion design in the Lower Montney on the 5-19 pad. The Upper Montney completion proved significant productivity (previously announced test rate of 1,136 boe/d) (1) in a zone that can be mapped over a significant portion of Coelacanth’s lands and should materially increase drilling inventory. The new Lower Montney completions yielded increased overall test rates as well as increasing the oil percentage (3-well average test rates previously announced at 1,624 boe/d with 61% light oil) ⁽¹⁾ pointing to potentially higher per-well recoveries of oil and gas and corresponding per-well values than previously estimated.

Construction of the facility continued throughout Q1 2025 and is now substantially complete. With 9 wells and over 11,000 boe/d ⁽¹⁾ of test production waiting on completion of the facility, we anticipate yet another major milestone will be reached imminently. We look forward to reporting updates on the Two Rivers East project as new developments arise.

(1) See ‘Test Results and Initial Production Rates’ section for more details.

OIL AND GAS TERMS

The Company uses the following frequently recurring oil and gas industry terms in the news release:

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 news release. 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.

NON-GAAP AND OTHER FINANCIAL MEASURES

This news release 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 (used)
Management uses adjusted funds flow (used) 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, if any. Adjusted funds flow (used) is a non-GAAP financial measure and has been defined by the Company as cash flow from (used in) 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 (used) is reconciled from cash flow from (used) in operating activities as follows:

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:

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:

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:

Capital Management Measures

Adjusted working capital (deficiency)
Management uses adjusted working capital (deficiency) as a measure 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.

Non-GAAP Financial Ratios

Adjusted Funds Flow (Used) per share
Adjusted funds flow (used) per share is a non-GAAP financial ratio, calculated using adjusted funds flow (used) 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.

Operating netback per boe
The Company utilizes operating netback per boe to assess the operating performance of its petroleum 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.

Supplementary Financial Measures

The supplementary financial measures used in this news release (primarily average sales price per product type 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.

PRODUCT TYPES

The Company uses the following references to sales volumes in the news release:

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:

TEST RESULTS AND INITIAL PRODUCTION RATES

The 5-19 Lower Montney well was production tested for 9.4 days and produced at an average rate of 377 bbl/d oil and 2,202 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.

The A5-19 Basal Montney well was production tested for 5.9 days and produced at an average rate of 117 bbl/d oil and 630 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.

The B5-19 Upper Montney well was production tested for 6.3 days and produced at an average rate of 92 bbl/d oil and 2,100 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.

The C5-19 Lower Montney well was production tested for 5.8 days and produced at an average rate of 736 bbl/d oil and 2,660 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.

The D5-19 Lower Montney well was production tested for 12.6 days and produced at an average rate of 170 bbl/d oil and 580 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.

The E5-19 Lower Montney well was production tested for 11.4 days and produced at an average rate of 312 bbl/d oil and 890 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure was stable, and production was starting to decline.

The F5-19 Lower Montney well was production tested for 4.9 days and produced at an average rate of 728 bbl/d oil and 1,607 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.

The G5-19 Lower Montney well was production tested for 7.1 days and produced at an average rate of 415 bbl/d oil and 1,489 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.

The H5-19 Lower Montney well was production tested for 8.1 days and produced at an average rate of 411 bbl/d oil and 1,166 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure was stable and production was starting to decline.

A pressure transient analysis or well-test interpretation has not been carried out on these nine wells and thus certain of the test results provided herein should be considered to be preliminary until such analysis or interpretation has been completed. Test results and initial production rates disclosed herein, particularly those short in duration, may not necessarily be indicative of long-term performance or of ultimate recovery.

Any references to peak rates, test rates, IP30, IP90, IP180 or initial production rates or declines are useful for confirming the presence of hydrocarbons, however, such rates and declines are not determinative of the rates at which such wells will continue production and decline thereafter and are not indicative of long-term performance or ultimate recovery. IP30 is defined as an average production rate over 30 consecutive days, IP90 is defined as an average production rate over 90 consecutive days and IP180 is defined as an average production rate over 180 consecutive days. Readers are cautioned not to place reliance on such rates in calculating aggregate production for the Company.

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 news release contains forward-looking statements and information relating to the Company’s oil and condensate, other NGLs, and natural gas production, capital programs, and adjusted working capital (deficiency). 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.

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 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. 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.

Coelacanth 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.

Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.

To view the source version of this press release, please visit https://www.newsfilecorp.com/release/249584

Radisson Mining Resources Inc. (TSXV: RDS) (OTCQB: RMRDF) (FSE: 2RX) (‘Radisson’ or the ‘Company’) is pleased to announce that it intends to raise C$7 Million in a non-brokered private placement (the ‘Offering’), with the proceeds directed towards advancing the exploration and development of the Company’s O’Brien Gold Project located in the Abitibi region of Québec and for general corporate purposes.

The Offering will include the sale of the following securities (collectively, the ‘Securities‘):

• Class A common shares of the Company (the ‘FT Shares‘) which shall each qualify as a ‘flow-through share’ as defined in subsection 66(15) of the Income Tax Act (Canada) (‘ITA‘) and section 359.1 of the Taxation Act (Québec) (the ‘Québec Tax Act‘), at a price of C$0.34 per FT Share; and,

• Class A common shares of the Company (‘Common Shares‘) at a price of C$0.30 per Common Share.

The gross proceeds received by the Corporation from the sale of the FT Shares will be used to incur Canadian Exploration Expenses (‘CEE‘) that are ‘flow-through mining expenditures’ (as such terms are defined in the Income Tax Act (Canada)) on the O’Brien Gold Project in the Province of Québec, which will be renounced to the subscribers with an effective date no later than December 31, 2025, in the aggregate amount of not less than the total amount of the gross proceeds raised from the issue of FT Shares.

The closing of the Offering is expected to occur on or about May 15, 2025, and is subject to receipt of all necessary regulatory approvals including the acceptance of the Offering by the TSX Venture Exchange. All securities issued pursuant to the Offering will be subject to a four month hold period from the date of issue. A finder’s fee may apply to a portion of the proceeds raised under the Offering in the amount of 6% cash.

This news release does not constitute an offer to sell or a solicitation of an offer to buy the securities described herein in the United States. The securities described herein have not been and will not be registered under the United States Securities Act of 1933, as amended, and may not be offered or sold in the United States or to the account or benefit of a U.S. person absent an exemption from the registration requirements of such Act.

It is anticipated that one or more directors will acquire Securities under the Offering. Any such participation will be considered a ‘related party transaction’ as defined under Multilateral Instrument 61-101 (‘MI 61-101‘). It is anticipated that the transaction will be exempt from the formal valuation and minority shareholder approval requirements of MI 61-101 based on a determination that the securities of the Company are listed on the TSXV and that the fair market value of the Offering, insofar as it involves interested parties, will not exceed 25% of the market capitalization of the Company.

Radisson Mining Resources Inc.

Radisson is a gold exploration company focused on its 100% owned O’Brien Gold Project, located in the Bousquet-Cadillac mining camp along the world-renowned Larder-Lake-Cadillac Break in Abitibi, Québec. The Bousquet-Cadillac mining camp has produced over 25 million ounces of gold over the last 100 years. The Project hosts the former O’Brien Mine, considered to have been Québec’s highest-grade gold producer during its production. Indicated Mineral Resources are estimated at 0.50 million ounces (1.52 million tonnes at 10.26 g/t Au), with additional Inferred Mineral Resources estimated at 0.45 million ounces (1.60 million tonnes at 8.66 g/t Au). Please see the NI 43-101 ‘Technical Report on the O’Brien Project, Northwestern Québec, Canada’ effective March 2, 2023 and other filings made with Canadian securities regulatory authorities available at www.sedar.com for further details and assumptions relating to the O’Brien Gold Project.

For more information on Radisson, visit our website at www.radissonmining.com or contact:

Forward-Looking Statements

This news release contains ‘forward-looking information’ within the meaning of the applicable Canadian securities legislation that is based on expectations, estimates, projections, and interpretations as at the date of this news release. Forward-looking statements including, but are not limited to, statements with respect to planned and ongoing drilling, the significance of drill results, the ability to continue drilling, the impact of drilling on the definition of any resource, the ability to incorporate new drilling in an updated technical report and resource modelling, the Company’s ability to grow the O’Brien project and the ability to convert inferred mineral resources to indicated mineral resources. Any statement that involves discussions with respect to predictions, expectations, interpretations, beliefs, plans, projections, objectives, assumptions, future events or performance (often but not always using phrases such as ‘expects’, or ‘does not expect’, ‘is expected’, ‘interpreted’, ‘management’s view’, ‘anticipates’ or ‘does not anticipate’, ‘plans’, ‘budget’, ‘scheduled’, ‘forecasts’, ‘estimates’, ‘believes’ or ‘intends’ or variations of such words and phrases or stating that certain actions, events or results ‘may’ or ‘could’, ‘would’, ‘might’ or ‘will’ be taken to occur or be achieved) are not statements of historical fact and may be forward-looking information and are intended to identify forward-looking information. Except for statements of historical fact relating to the Company, certain information contained herein constitutes forward-looking statements Forward-looking information is based on estimates of management of the Company, at the time it was made, involves known and unknown risks, uncertainties and other factors which may cause the actual results, performance or achievements of the companies to be materially different from any future results, performance or achievements expressed or implied by such forward-looking information. Such factors include, among others, risks relating to the drill results at O’Brien; the significance of drill results; the ability of drill results to accurately predict mineralization; the ability of any material to be mined in a matter that is economic. Although the forward-looking information contained in this news release is based upon what management believes, or believed at the time, to be reasonable assumptions, the parties cannot assure shareholders and prospective purchasers of securities that actual results will be consistent with such forward-looking information, as there may be other factors that cause results not to be as anticipated, estimated or intended, and neither the Company nor any other person assumes responsibility for the accuracy and completeness of any such forward-looking information. The Company believes that this forward-looking information is based on reasonable assumptions, but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this press release should not be unduly relied upon. The Company does not undertake, and assumes no obligation, to update or revise any such forward-looking statements or forward-looking information contained herein to reflect new events or circumstances, except as may be required by law. These statements speak only as of the date of this news release.

Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this news release. No stock exchange, securities commission or other regulatory authority has approved or disapproved the information contained herein.

Not for distribution to United States newswire services or for dissemination in the United States

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Lahontan Gold Corp. (TSXV: LG) (OTCQB: LGCXF) (the ‘Company’ or ‘Lahontan’) is pleased to announce that, further to its press release of April 8, 2025, the Company has increased the size of its non-brokered private placement financing to up to 44,000,000 units (each, a ‘Unit’) at a price of $0.05 per Unit for aggregate gross proceeds of up to $2,200,000 (the ‘Offering’).

Each Unit is comprised of one common share of the Company (each, a ‘Common Share‘) and one-half of one whole Common Share purchase warrant (each whole warrant, a ‘Warrant‘) of the Company. Each Warrant entitling the holder thereof to purchase one Common Share at a price of $0.08 per Common Share for a period of two (2) years from the date of issuance, provided, however, that should the closing price at which the Common Shares trade on the TSX Venture Exchange (or any such other stock exchange in Canada as the Common Shares may trade at the applicable time) exceed CDN$0.12 for ten (10) consecutive trading days at any time following the date that is four months and one day after the date of issuance, the Company may accelerate the Warrant Term (the ‘Reduced Warrant Term‘) such that the Warrants shall expire on the date which is 30 business days following the date a press release is issued by the Company announcing the Reduced Warrant Term

Gross proceeds raised from the Offering will be used for general working capital purposes and for exploration at the Company’s Santa Fe Mine Project.

Closing of the Offering is subject to receipt of all necessary corporate and regulatory approvals, including the approval of TSX Venture Exchange. All securities issued in connection with the Offering will be subject to a hold period of four months plus a day from the date of issuance and the resale rules of applicable securities legislation.

This press release does not constitute an offer to sell or a solicitation of an offer to buy the securities in the United States. The securities have not been and will not be registered under the United States Securities Act of 1933, as amended (the ‘U.S. Securities Act’) or any state securities laws and may not be offered or sold within the United States or to U.S. Persons as defined under applicable United States securities laws unless registered under the U.S. Securities Act and applicable state securities laws or an exemption from such registration is available.

About Lahontan Gold Corp.

Lahontan Gold Corp. is a Canadian mine development and mineral exploration company that holds, through its US subsidiaries, four top-tier gold and silver exploration properties in the Walker Lane of mining friendly Nevada. Lahontan’s flagship property, the 26.4 km² Santa Fe Mine project, had past production of 359,202 ounces of gold and 702,067ounces of silver between 1988 and 1995 from open pit mines utilizing heap-leach processing*. The Santa Fe Mine has a Canadian National Instrument 43-101 compliant Indicated Mineral Resource of 1,539,000 oz Au Eq (grading 0.99 g/t Au Eq) and an Inferred Mineral Resource of 411,000 oz Au Eq (grading 0.76 g/t Au Eq), all pit constrained (Au Eq is inclusive of recovery, please see Santa Fe Project Technical Report*). The Company plans to continue advancing the Santa Fe Mine project towards production, update the Santa Fe Preliminary Economic Assessment, and drill test its satellite West Santa Fe project during 2025. For more information, please visit our website: www.lahontangoldcorp.com.

* Please see the ‘Preliminary Economic Assessment, NI 43-101 Technical Report, Santa Fe Project’, Authors: Kenji Umeno, P. Eng., Thomas Dyer, PE, Kyle Murphy, PE, Trevor Rabb, P. Geo, Darcy Baker, PhD, P. Geo., and John M. Young, SME-RM; Effective Date: December 10, 2024, Report Date: January 24, 2025. The Technical Report is available on the Company’s website and SEDAR+.

On behalf of the Board of Directors

Kimberly Ann

Founder, CEO, President, and Director

Cautionary Note Regarding Forward-Looking Statements:

Neither TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release. Except for statements of historical fact, this news release contains certain ‘forward-looking information’ within the meaning of applicable securities law. Forward-looking information is frequently characterized by words such as ‘plan’, ‘expect’, ‘project’, ‘intend’, ‘believe’, ‘anticipate’, ‘estimate’ and other similar words, or statements that certain events or conditions ‘may’ or ‘will’ occur. Forward-looking statements are based on the opinions and estimates at the date the statements are made and are subject to a variety of risks and uncertainties and other factors that could cause actual events or results to differ materially from those anticipated in the forward-looking statements including, but not limited to delays or uncertainties with regulatory approvals, including that of the TSXV. There are uncertainties inherent in forward-looking information, including factors beyond the Company’s control. The Company undertakes no obligation to update forward-looking information if circumstances or management’s estimates or opinions should change except as required by law. The reader is cautioned not to place undue reliance on forward-looking statements. Additional information identifying risks and uncertainties that could affect financial results is contained in the Company’s filings with Canadian securities regulators, which filings are available at www.sedarplus.ca.

NOT FOR DISTRIBUTION TO UNITED STATES NEWS WIRE SERVICES OR FOR DISSEMINATION IN THE UNITED STATES.

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