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:
Coelacanth is currently:
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:
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)
| Working Interest Reserves (2) | Tight Oil (Mbbl) | Shale Natural Gas (Mmcf) | NGLs (Mbbl) | Total Oil Equivalent (Mboe) (3) |
| Proved | ||||
| Producing | 344 | 8,097 | 150 | 1,843 |
| Developed non-producing | 1,874 | 38,862 | 720 | 9,071 |
| Undeveloped | 1,137 | 27,324 | 506 | 6,197 |
| Total proved | 3,355 | 74,283 | 1,376 | 17,111 |
| Probable | 2,154 | 44,543 | 825 | 10,403 |
| Total proved & probable | 5,509 | 118,826 | 2,201 | 27,515 |
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)
| Discount factor per year | |||||
| ($000s) | 0% | 5% | 10% | 15% | 20% |
| Proved | |||||
| Producing | 21,615 | 17,655 | 14,827 | 12,765 | 11,220 |
| Developed non-producing | 131,346 | 97,179 | 74,105 | 57,825 | 45,878 |
| Undeveloped | 93,068 | 63,389 | 44,903 | 32,689 | 24,196 |
| Total proved | 246,030 | 178,224 | 133,834 | 103,279 | 81,294 |
| Probable | 221,362 | 147,285 | 105,806 | 80,431 | 63,701 |
| Total proved & probable | 467,391 | 325,509 | 239,640 | 183,710 | 144,995 |
Notes:
(1) Numbers may not add due to rounding.
(2) The estimated future net revenues are stated prior to provision for interest, debt service charges or general administrative expenses and after deduction of royalties, operating costs, estimated well abandonment and reclamation costs and estimated future capital expenditures.
(3) The estimated future net revenue contained in the table does not necessarily represent the fair market value of the reserves. There is no assurance that the forecast price and cost assumptions contained in the GLJ Report will be attained and variations could be material. The recovery and reserve estimates described herein are estimates only. Actual reserves may be greater or less than those calculated.
(4) The after-tax present values of future net revenue attributed to Coelacanth's reserves are included in Company's AIF dated April 23, 2025 filed on SEDAR+ at www.sedarplus.ca.
Price Forecast
The GLJ (2025-01) price forecast is as follows:
| Year | WTI Oil @ Cushing ($US / Bbl) | Edmonton Light Oil ($Cdn / Bbl) | AECO Natural Gas ($Cdn / Mmbtu) | Chicago Natural Gas ($US / Mmbtu) | Foreign Exchange (Cdn$/US$) |
| 2025 | 71.25 | 91.33 | 2.05 | 2.79 | 0.7050 |
| 2026 | 73.50 | 93.32 | 3.00 | 3.70 | 0.7300 |
| 2027 | 76.00 | 96.45 | 3.50 | 4.01 | 0.7500 |
| 2028 | 78.53 | 99.82 | 4.00 | 4.10 | 0.7500 |
| 2029 | 80.10 | 101.80 | 4.08 | 4.18 | 0.7500 |
| 2030 | 81.70 | 103.84 | 4.16 | 4.27 | 0.7500 |
| 2031 | 83.34 | 105.92 | 4.24 | 4.35 | 0.7500 |
| 2032 | 85.00 | 108.04 | 4.33 | 4.45 | 0.7500 |
| 2033 | 86.70 | 110.20 | 4.41 | 4.54 | 0.7500 |
| 2034 | 88.44 | 112.40 | 4.50 | 4.63 | 0.7500 |
| Escalate thereafter (1) | 2.0% per year | 2.0% per year | 2.0% per year | 2.0% per year |
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.
| Reserve Category | RLI |
| Proved plus Probable Reserves | 69.0 |
| Proved Reserves | 42.9 |
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)
| Total Proved | Tight Oil | Shale Natural Gas | NGLs | Total Oil Equivalent |
| (Mbbl) | (Mmcf) | (Mbbl) | (Mboe) (3) | |
| Opening balance | 2,291 | 44,784 | 720 | 10,475 |
| Discoveries | - | - | - | - |
| Extensions and improved recovery | 1,212 | 27,468 | 509 | 6,298 |
| Technical revisions | (28) | 3,663 | 173 | 756 |
| Acquisitions | - | - | - | - |
| Dispositions | - | - | - | - |
| Economic factors | (15) | (297) | (1) | (66) |
| Production | (105) | (1,335) | (24) | (352) |
| Closing balance | 3,355 | 74,283 | 1,376 | 17,111 |
| Proved plus Probable | Tight Oil | Shale Natural Gas | NGLs | Total Oil Equivalent |
| (Mbbl) | (Mmcf) | (Mbbl) | (Mboe) (3) | |
| Opening balance | 3,038 | 60,432 | 970 | 14,080 |
| Discoveries | - | - | - | - |
| Extensions and improved recovery | 2,599 | 56,330 | 1,043 | 13,031 |
| Technical revisions | (9) | 3,734 | 213 | 825 |
| Acquisitions | - | - | - | - |
| Dispositions | - | - | - | - |
| Economic factors | (13) | (334) | - | (69) |
| Production | (105) | (1,335) | (24) | (352) |
| Closing balance | 5,509 | 118,826 | 2,201 | 27,515 |
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:
| ($000s) | 2024 | 2023 | 2022 |
| Undeveloped land | 765 | 1,006 | 1,164 |
| Acquisitions | 765 | 1,006 | 1,164 |
| Drilling and completion | 38,353 | 61,274 | 9,009 |
| Facilities and related infrastructure | 44,935 | 12,094 | 3,689 |
| Geological, geophysical and other | 444 | 239 | 42 |
| Exploration and development expenditures | 83,732 | 73,607 | 12,740 |
| Total capital expenditures | 84,497 | 74,613 | 13,904 |
Finding and Development Costs ("F&D") and Finding, Development and Acquisition Costs ("FD&A")
Coelacanth has presented FD&A and F&D costs below:
| 2024 | 2023 | 2022 | 3 Year Cumulative | |||||
| Proved & | Proved & | Proved & | Proved & | |||||
| ($000's, except where noted) | Proved | Probable | Proved | Probable | Proved | Probable | Proved | Probable |
| Exploration and development expenditures | 83,732 | 83,732 | 73,607 | 73,607 | 12,740 | 12,740 | 170,079 | 170,079 |
| Change in FDC (1) | (1,713) | 30,469 | 90,598 | 77,759 | 11,400 | 33,748 | 100,285 | 141,976 |
| F&D costs | 82,019 | 114,201 | 164,205 | 151,366 | 24,140 | 46,488 | 270,364 | 312,055 |
| Acquisitions | 765 | 765 | 1,006 | 1,006 | 1,164 | 1,164 | 2,935 | 2,935 |
| FD&A costs | 82,784 | 114,966 | 165,211 | 152,372 | 25,304 | 47,652 | 273,299 | 314,990 |
| Reserve Additions (Mboe) (2) | ||||||||
| Exploration and development | 6,989 | 13,789 | 8,637 | 9,784 | 1,169 | 3,400 | 16,795 | 26,973 |
| Acquisitions | - | - | - | - | - | - | - | - |
| 6,989 | 13,789 | 8,637 | 9,784 | 1,169 | 3,400 | 16,795 | 26,973 | |
| F&D costs ($/boe) | 11.74 | 8.28 | 19.01 | 15.47 | 20.65 | 13.67 | 16.10 | 11.57 |
| FD&A costs ($/boe) | 11.84 | 8.34 | 19.13 | 15.57 | 21.65 | 14.02 | 16.27 | 11.68 |
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
| Bbl | barrel |
| Mbbl | thousands of barrels |
| MMbtu | millions of British thermal units |
| Mcf | thousand cubic feet |
| MMcf | million cubic feet |
| NGLs | natural gas liquids |
| BOE | barrel of oil equivalent |
| MBOE | thousands of barrels of oil equivalent |
| WTI | West Texas Intermediate at Cushing, Oklahoma |
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.
For further information, please contact:
Coelacanth Energy Inc.
2110, 530 - 8th Ave SW
Calgary, Alberta T2P 3S8
Phone: (403) 705-4525
www.coelacanth.ca
Robert Zakresky
President and Chief Executive Officer
Nolan Chicoine
Vice President, Finance and Chief Financial Officer
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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
| FINANCIAL RESULTS | Three Months Ended | Year Ended | ||||||||||||||||
| December 31 | December 31 | |||||||||||||||||
| ($000s, except per share amounts) | 2024 | 2023 | % Change | 2024 | 2023 | % Change | ||||||||||||
| Oil and natural gas sales | 4,544 | 4,204 | 8 | 13,736 | 6,663 | 106 | ||||||||||||
| Cash flow from (used in) operating activities | 3,157 | (404 | ) | (881 | ) | 2,203 | (4,234 | ) | (152 | ) | ||||||||
| Per share - basic and diluted (1) | 0.01 | (-) | (100 | ) | - | (0.01 | ) | (100 | ) | |||||||||
| Adjusted funds flow (used) (1) | 382 | 1,750 | (78 | ) | 1,515 | (333 | ) | (555 | ) | |||||||||
| Per share - basic and diluted | - | - | - | - | (-) | (-) | ||||||||||||
| Net loss | (2,903 | ) | (750 | ) | 287 | (8,897 | ) | (6,573 | ) | 35 | ||||||||
| Per share - basic and diluted | (0.01 | ) | (-) | 100 | (0.02 | ) | (0.01 | ) | 100 | |||||||||
| Capital expenditures (1) | 64,952 | 34,656 | 87 | 84,497 | 74,613 | 13 | ||||||||||||
| Adjusted working capital (deficiency) (1) | (18,637 | ) | 67,589 | (128 | ) | |||||||||||||
| Common shares outstanding (000s) | ||||||||||||||||||
| Weighted average - basic and diluted | 530,398 | 478,731 | 11 | 529,804 | 439,055 | 21 | ||||||||||||
| End of period - basic | 530,670 | 528,650 | - | |||||||||||||||
| End of period - fully diluted | 615,930 | 609,989 | 1 | |||||||||||||||
(1) See "Non-GAAP and Other Financial Measures" section.
(2) See "Test Results and Initial Production Rates" section.
| Three Months Ended | Year Ended | |||||||||||||||||
| OPERATING RESULTS (1) | December 31 | December 31 | ||||||||||||||||
| 2024 | 2023 | % Change | 2024 | 2023 | % Change | |||||||||||||
| Daily production (2) | ||||||||||||||||||
| Oil and condensate (bbls/d) | 473 | 419 | 13 | 320 | 139 | 130 | ||||||||||||
| Other NGLs (bbls/d) | 29 | 28 | 4 | 34 | 16 | 113 | ||||||||||||
| Oil and NGLs (bbls/d) | 502 | 447 | 12 | 354 | 155 | 128 | ||||||||||||
| Natural gas (mcf/d) | 3,490 | 2,858 | 22 | 3,648 | 1,624 | 125 | ||||||||||||
| Oil equivalent (boe/d) | 1,084 | 923 | 17 | 962 | 426 | 126 | ||||||||||||
| Oil and natural gas sales | ||||||||||||||||||
| Oil and condensate ($/bbl) | 87.06 | 87.38 | (-) | 89.46 | 88.94 | 1 | ||||||||||||
| Other NGLs ($/bbl) | 33.28 | 32.32 | 3 | 33.22 | 33.22 | - | ||||||||||||
| Oil and NGLs ($/bbl) | 83.97 | 83.88 | - | 83.99 | 83.28 | 1 | ||||||||||||
| Natural gas ($/mcf) | 2.07 | 2.86 | (28 | ) | 2.14 | 3.26 | (34 | ) | ||||||||||
| Oil equivalent ($/boe) | 45.57 | 49.47 | (8 | ) | 39.01 | 42.82 | (9 | ) | ||||||||||
| Royalties | ||||||||||||||||||
| Oil and NGLs ($/bbl) | 16.86 | 19.38 | (13 | ) | 18.70 | 20.24 | (8 | ) | ||||||||||
| Natural gas ($/mcf) | 0.13 | 0.26 | (50 | ) | 0.21 | 0.57 | (63 | ) | ||||||||||
| Oil equivalent ($/boe) | 8.22 | 10.20 | (19 | ) | 7.66 | 9.57 | (20 | ) | ||||||||||
| Operating expenses | ||||||||||||||||||
| Oil and NGLs ($/bbl) | 8.34 | 11.57 | (28 | ) | 9.47 | 13.25 | (29 | ) | ||||||||||
| Natural gas ($/mcf) | 1.25 | 1.28 | (2 | ) | 1.58 | 2.21 | (29 | ) | ||||||||||
| Oil equivalent ($/boe) | 7.88 | 9.57 | (18 | ) | 9.47 | 13.25 | (29 | ) | ||||||||||
| Net transportation expenses (3) | ||||||||||||||||||
| Oil and NGLs ($/bbl) | 5.54 | 4.95 | 12 | 3.46 | 4.10 | (16 | ) | |||||||||||
| Natural gas ($/mcf) | 0.76 | 0.81 | (6 | ) | 0.73 | 1.12 | (35 | ) | ||||||||||
| Oil equivalent ($/boe) | 5.01 | 4.92 | 2 | 4.04 | 5.75 | (30 | ) | |||||||||||
| Operating netback (loss) (3) | ||||||||||||||||||
| Oil and NGLs ($/bbl) | 53.23 | 47.98 | 11 | 52.36 | 45.69 | 15 | ||||||||||||
| Natural gas ($/mcf) | (0.07 | ) | 0.51 | (114 | ) | (0.38 | ) | (0.64 | ) | (41 | ) | |||||||
| Oil equivalent ($/boe) | 24.46 | 24.78 | (1 | ) | 17.84 | 14.25 | 25 | |||||||||||
| Depletion and depreciation ($/boe) | (10.76 | ) | (12.18 | ) | (12 | ) | (13.59 | ) | (14.93 | ) | (9 | ) | ||||||
| General and administrative expenses ($/boe) | (15.46 | ) | (10.77 | ) | 44 | (14.34 | ) | (27.08 | ) | (47 | ) | |||||||
| Share based compensation ($/boe) | (7.08 | ) | (16.31 | ) | (57 | ) | (11.12 | ) | (23.49 | ) | (53 | ) | ||||||
| Loss on lease termination ($/boe) | (2.02 | ) | - | 100 | (0.57 | ) | - | 100 | ||||||||||
| Finance expense ($/boe) | (18.02 | ) | (1.28 | ) | 1,308 | (6.33 | ) | (3.09 | ) | 105 | ||||||||
| Finance income ($/boe) | 3.65 | 10.01 | (64 | ) | 8.23 | 18.75 | (56 | ) | ||||||||||
| Unutilized transportation ($/boe) | (3.88 | ) | (3.08 | ) | 26 | (5.37 | ) | (6.65 | ) | (19 | ) | |||||||
| Net loss ($/boe) | (29.11 | ) | (8.83 | ) | 230 | (25.25 | ) | (42.24 | ) | (40 | ) | |||||||
(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:
| Liquids | |
| Bbls | Barrels |
| Bbls/d | Barrels per day |
| NGLs | Natural gas liquids (includes condensate, pentane, butane, propane, and ethane) |
| Condensat | 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 |
| 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 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:
| Three Months Ended | Year Ended | |||||||||||
| December 31 | December 31 | |||||||||||
| ($000s) | 2024 | 2023 | 2024 | 2023 | ||||||||
| Cash flow from (used in) operating activities | 3,157 | (404 | ) | 2,203 | (4,234 | ) | ||||||
| Add (deduct): | ||||||||||||
| Decommissioning expenditures | 161 | 206 | 1,427 | 1,883 | ||||||||
| Change in restricted cash deposits | (5,361 | ) | - | (2,376 | ) | (784 | ) | |||||
| Change in non-cash working capital | 2,425 | 1,948 | 261 | 2,802 | ||||||||
| Adjusted funds flow (used) (non-GAAP) | 382 | 1,750 | 1,515 | (333 | ) | |||||||
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:
| Three Months Ended | Year Ended | |||||||||||
| December 31 | December 31 | |||||||||||
| ($000s) | 2024 | 2023 | 2024 | 2023 | ||||||||
| Transportation expenses | 887 | 680 | 3,313 | 1,930 | ||||||||
| Unutilized transportation | (387 | ) | (262 | ) | (1,891 | ) | (1,035 | ) | ||||
| Net transportation expenses (non-GAAP) | 500 | 418 | 1,422 | 895 | ||||||||
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:
| Three Months Ended | Year Ended | |||||||||||
| December 31 | December 31 | |||||||||||
| ($000s) | 2024 | 2023 | 2024 | 2023 | ||||||||
| Oil and natural gas sales | 4,544 | 4,204 | 13,736 | 6,663 | ||||||||
| Royalties | (820 | ) | (866 | ) | (2,698 | ) | (1,489 | ) | ||||
| Operating expenses | (786 | ) | (813 | ) | (3,335 | ) | (2,062 | ) | ||||
| Net transportation expenses | (500 | ) | (418 | ) | (1,422 | ) | (895 | ) | ||||
| Operating netback (non-GAAP) | 2,438 | 2,107 | 6,281 | 2,217 | ||||||||
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:
| Three Months Ended | Year Ended | |||||||||||
| December 31 | December 31 | |||||||||||
| ($000s) | 2024 | 2023 | 2024 | 2023 | ||||||||
| Capital expenditures – property, plant, and equipment | 233 | 4,584 | 1,206 | 26,928 | ||||||||
| Capital expenditures – exploration and evaluation assets | 64,719 | 30,072 | 83,291 | 47,685 | ||||||||
| Capital expenditures (non-GAAP) | 64,952 | 34,656 | 84,497 | 74,613 | ||||||||
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.
| ($000s) | December 31, 2024 | December 31, 2023 | ||||
| Current assets | 11,579 | 87,616 | ||||
| Less: | ||||||
| Current liabilities | (37,234 | ) | (28,754 | ) | ||
| Working capital (deficiency) | (25,655 | ) | 58,862 | |||
| Add: | ||||||
| Restricted cash deposits | 4,900 | 6,784 | ||||
| Current portion of decommissioning obligations | 2,118 | 1,943 | ||||
| Adjusted working capital (deficiency) (Capital management measure) | (18,637 | ) | 67,589 |
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:
| Three Months Ended | Year Ended | |||||||||||
| December 31 | December 31 | |||||||||||
| Sales Volumes by Product Type | 2024 | 2023 | 2024 | 2023 | ||||||||
| Condensate (bbls/d) | 22 | 12 | 32 | 7 | ||||||||
| Other NGLs (bbls/d) | 29 | 28 | 35 | 16 | ||||||||
| NGLs (bbls/d) | 51 | 40 | 67 | 23 | ||||||||
| Tight oil (bbls/d) | 451 | 407 | 287 | 132 | ||||||||
| Condensate (bbls/d) | 22 | 12 | 32 | 7 | ||||||||
| Oil and condensate (bbls/d) | 473 | 419 | 319 | 139 | ||||||||
| Other NGLs (bbls/d) | 29 | 28 | 35 | 16 | ||||||||
| Oil and NGLs (bbls/d) | 502 | 447 | 354 | 155 | ||||||||
| Shale gas (mcf/d) | 3,490 | 2,858 | 3,648 | 1,624 | ||||||||
| Natural gas (mcf/d) | 3,490 | 2,858 | 3,648 | 1,624 | ||||||||
| Oil equivalent (boe/d) | 1,084 | 923 | 962 | 426 | ||||||||
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.
Further Information
For additional information, please contact:
Coelacanth Energy Inc.
Suite 2110, 530 - 8th Avenue SW
Calgary, Alberta T2P 3S8
Phone: (403) 705-4525
www.coelacanth.ca
Mr. Robert J. Zakresky
President and Chief Executive Officer
Mr. Nolan Chicoine
Vice President, Finance and Chief Financial Officer
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
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TSX Venture Exchange: BSK
Frankfurt Stock Exchange: MAL2
Blue Sky Uranium Corp. (TSXV: BSK) (FSE: MAL2) ("Blue Sky" or the "Company") is pleased to announce that due to continued strong demand, the Company has increased the non-brokered private placement offering (the " Offering ") to up to $1,649,800 in aggregate gross proceeds. All other terms of the Offering will remain the same as originally announced in the Company's News Release dated March 27, 2025 .
The Company further announces that it has closed the second and final tranche of the non-brokered private placement through the issuance of 8,660,000 units at a subscription price of $0.05 per Unit for aggregate gross proceeds to the Company of $433,000 . In total, the Company issued 32,996,000 Units for total gross proceeds of $1,649,800 .
Each Unit consists of one common share and one warrant (a " Warrant "). Each Warrant will entitle the holder thereof to purchase one additional common share in the capital of the Company at $0.07 per share for four years from the date of issue, expiring on April 16, 2029 for this tranche.
Finder's fees of $3,500 are payable in cash on a portion of the private placement to parties at arm's length to the Company. In addition, 70,000 non-transferable finder's warrants are issuable (the " Finder's Warrants "). Each Finder's Warrant entitles a finder to purchase one common share at a price of $0.05 per share for four years from the date of issue, expiring on April 16, 2029 for this tranche. In total, cash finders' fees of $28,560 were paid and 571,200 Finders' Warrants were issued for the Offering.
No insiders participated in this tranche.
This Offering is subject to regulatory approval and all securities to be issued pursuant to the Offering in this final tranche are subject to a four-month hold period under applicable Canadian securities laws expiring on August 16, 2025 . The proceeds of the Offering will be used for general working capital.
About Blue Sky Uranium Corp.
Blue Sky Uranium Corp. is a leader in uranium discovery in Argentina . The Company's objective is to deliver exceptional returns to shareholders by rapidly advancing a portfolio of surficial uranium deposits into low-cost producers, while respecting the environment, the communities, and the cultures in all the areas in which we work. Blue Sky has the exclusive right to properties in two provinces in Argentina . The Company's flagship Amarillo Grande Project was an in-house discovery of a new district that has the potential to be both a leading domestic supplier of uranium to the growing Argentine market and a new international market supplier. The Company is a member of the Grosso Group, a resource management group that has pioneered exploration in Argentina since 1993.
ON BEHALF OF THE BOARD
"Nikolaos Cacos"
______________________________________
Nikolaos Cacos , President, CEO and Director
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.
The securities being offered have not been, nor will they be registered under the United States Securities Act of 1933, as amended, or state securities laws and may not be offered or sold within the United States or to, or for the account or benefit of, U.S. persons absent U.S. federal and state registration or an applicable exemption from the U.S. registration requirements. This release does not constitute an offer for sale of securities in the United States.
SOURCE Blue Sky Uranium Corp.
View original content to download multimedia: http://www.newswire.ca/en/releases/archive/April2025/16/c0748.html
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TSX Venture Exchange (TSX-V): BSK
Frankfurt Stock Exchange (FSE): MAL2
OTCQB Venture Market (OTC): BKUCF
Blue Sky Uranium Corp. (TSXV: BSK) (FSE: MAL2) (OTC: BKUCF), ("Blue Sky" or the "Company") is pleased to announce that due to continued strong demand, the Company has increased the non-brokered private placement offering (the " Offering ") to up to $1,649,800 in aggregate gross proceeds. All other terms of the Offering will remain the same as originally announced in the Company's News Release dated March 27, 2025 .
The Company further announces that it has closed the second and final tranche of the non-brokered private placement through the issuance of 8,660,000 units at a subscription price of $0.05 per Unit for aggregate gross proceeds to the Company of $433,000 . In total, the Company issued 32,996,000 Units for total gross proceeds of $1,649,800 .
Each Unit consists of one common share and one warrant (a " Warrant "). Each Warrant will entitle the holder thereof to purchase one additional common share in the capital of the Company at $0.07 per share for four years from the date of issue, expiring on April 16, 2029 for this tranche.
Finder's fees of $4,900 are payable in cash on a portion of the private placement to parties at arm's length to the Company. In addition, 98,000 non-transferable finder's warrants are issuable (the " Finder's Warrants "). Each Finder's Warrant entitles a finder to purchase one common share at a price of $0.05 per share for four years from the date of issue, expiring on April 16, 2029 for this tranche. In total, cash finders' fees of $29,960 were paid and 599,200 Finders' Warrants were issued for the Offering.
No insiders participated in this tranche.
This Offering is subject to regulatory approval and all securities to be issued pursuant to the Offering in this final tranche are subject to a four-month hold period under applicable Canadian securities laws expiring on August 16, 2025 . The proceeds of the Offering will be used for general working capital.
About Blue Sky Uranium Corp.
Blue Sky Uranium Corp. is a leader in uranium discovery in Argentina . The Company's objective is to deliver exceptional returns to shareholders by rapidly advancing a portfolio of surficial uranium deposits into low-cost producers, while respecting the environment, the communities, and the cultures in all the areas in which we work. Blue Sky has the exclusive right to properties in two provinces in Argentina . The Company's flagship Amarillo Grande Project was an in-house discovery of a new district that has the potential to be both a leading domestic supplier of uranium to the growing Argentine market and a new international market supplier. The Company is a member of the Grosso Group, a resource management group that has pioneered exploration in Argentina since 1993.
ON BEHALF OF THE BOARD
"Nikolaos Cacos"
______________________________________
Nikolaos Cacos , President, CEO and Director
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.
The securities being offered have not been, nor will they be registered under the United States Securities Act of 1933, as amended, or state securities laws and may not be offered or sold within the United States or to, or for the account or benefit of, U.S. persons absent U.S. federal and state registration or an applicable exemption from the U.S. registration requirements. This release does not constitute an offer for sale of securities in the United States .
SOURCE Blue Sky Uranium Corp.
View original content to download multimedia: http://www.newswire.ca/en/releases/archive/April2025/16/c5118.html
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GoviEx Uranium Inc. (TSXV: GXU) (OTCQB: GVXXF) ("GoviEx" or "the Company") is pleased to announce that it has further advanced the development of its Muntanga Uranium Project in Zambia with the filing of its draft Environmental and Social Impact Assessment ("ESIA") with the Zambian Environmental Management Agency ("ZEMA").
This submission marks a key step in the project's transition from feasibility towards execution. With the draft ESIA now submitted, ZEMA will undertake a review of the document and provide comments and guidance to GoviEx. This feedback will inform the final ESIA, which GoviEx will then resubmit for final approval, which is expected in the second half of 2025.
The filing of the draft ESIA follows the recently completed Feasibility Study, which confirmed Muntanga as a robust, shallow open-pit, heap leach operation with a projected 12-year mine life, low operating costs, and strong financial returns - including an after-tax NPV8% of USD 243 million1 and an internal rate of return (IRR) of 20.8%.2
Daniel Major, CEO of GoviEx, commented:
"The momentum behind the Muntanga Project continues to build. With today's draft ESIA submission, we are taking another significant step toward making Muntanga a reality. This progress demonstrates our dedication to delivering one of the few near-term uranium projects with potential to help meet growing global demand, while also ensuring environmental and social responsibility. We are also making solid progress on the financing front, with strong early-stage interest that reflects confidence in the quality and potential of the Muntanga Project."
Muntanga is strategically positioned to supply both Western and non-Western nuclear markets, benefitting from Zambia's excellent infrastructure, pro mining government, proximity to export routes, and domestic surplus of sulfuric acid - a key reagent in uranium recovery. With a rapid construction timeline and expected uranium production within four months of mining commencement, Muntanga is one of the few near-term uranium projects capable of helping bridge the global supply gap in a tightening nuclear fuel market. Production is expected to begin in 2028, with discussions currently underway with potential off-takers.
Qualified Person Statement
The scientific and technical information in this release has been reviewed, verified, and approved by Mr. Jerome Randabel, MAIG, Chief Geologist of GoviEx, a Qualified Person as defined in Canadian National Instrument 43-101 "Standards of Disclosure for Mineral Projects".
Notes:
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.
About GoviEx Uranium Inc.
GoviEx (TSXV: GXU) (OTCQB: GVXXF), is a mineral resource company focused on the exploration and development of uranium properties in Africa. GoviEx's principal objective is to become a significant uranium producer through the continued exploration and development of its mine-permitted Muntanga Project in Zambia.
Contact Information
Isabel Vilela, Head of Corporate Communications
Daniel Major, Chief Executive Officer
Tel: +1-604-681-5529 Email: info@goviex.com Web: www.goviex.com
Cautionary Statement Regarding Forward-Looking Information
This news release may contain "forward-looking information" and "forward-looking statements" (collectively "forward-looking statements") within the meaning of applicable securities laws. All information and statements other than statements of current or historical facts contained in this news release are forward-looking information. Forward-looking statements are subject to various risks and uncertainties concerning the specific factors disclosed here and elsewhere in GoviEx's periodic filings with Canadian securities regulators. When used in this news release, words such as "will", "could", "plan", "estimate", "expect", "intend", "may", "potential", "should," and similar expressions, are forward-looking statements. Information provided in this document is necessarily summarized and may not contain all available material information. Forward-looking statements include those in relation to: (i) the Muntanga Project's transition from feasibility towards execution; (ii) the method and timing of any development and mining operations at Muntanga, including expected uranium production within four months of mining commencement and the target production start in 2028; (iii) the continued engagement program with potential off-takers; (iv) the expected timing for final approval of the Environmental and Social Impact Assessment (ESIA) in the second half of 2025; and (v) Muntanga emerging as one of the few near-term uranium projects with the potential to help address the uranium supply gap, with potential to supply both Western and non-Western markets. Although GoviEx believes the expectations reflected in such forward-looking statements are based on reasonable assumptions, it can give no assurances that its expectations will be achieved. Such assumptions, which may prove incorrect, include the following: (i) that GoviEx will successfully file the final ESIA as and when anticipated; that GoviEx will successfully raise required financing for the Muntanga Project; (ii) that the current uranium upcycle will continue and expand; (iii) that the integration of nuclear power into power grids worldwide will continue as a clean energy alternative; and (iv) that the price of uranium will remain sufficiently high and the costs of advancing GoviEx's mining projects will remain sufficiently low so as to permit GoviEx to implement its business plans in a profitable manner. Factors that could cause actual results to differ materially from expectations include: (i) the inability of the Company to file the final ESIA for any reason; (ii) the inability of the Company to raise financing for its Muntanga Project for any reason; (iii) a regression in the uranium market price; (iv) an inability or unwillingness to include or increase nuclear power generation by major markets; (v) potential delays due to new or ongoing health or environmental restrictions; (vi) the failure of GoviEx's projects, for technical, logistical, labour-relations, political, or other reasons; (vii) a decrease in the price of uranium below what is necessary to sustain GoviEx's operations; (viii) an increase in GoviEx's operating costs above what is necessary to sustain its operations; (ix) accidents, labour disputes, or the materialization of similar risks; (x) a deterioration in capital market conditions that prevents GoviEx from raising the funds it requires on a timely basis; (xi) political instability in the jurisdictions where GoviEx operates; and (xii) generally, GoviEx's inability to develop and implement a successful business plan for any reason. In addition, the factors described or referred to in the section entitled "Risk Factors" in the MD&A for the year ended December 31, 2023, as well as the Annual Information Form for the year ended December 31, 2023, of GoviEx, which are available on the SEDAR+ website at www.sedarplus.ca, should be reviewed in conjunction with the information found in this news release. Although GoviEx has attempted to identify important factors that could cause actual results, performance, or achievements to differ materially from those contained in the forward-looking statements, there can be other factors that cause results, performance, or achievements not to be as anticipated, estimated, or intended. There can be no assurance that such information will prove to be accurate or that management's expectations or estimates of future developments, circumstances, or results will materialize. As a result of these risks and uncertainties, no assurance can be given that any events anticipated by the forward-looking information in this news release will transpire or occur, or, if any of them do so, what benefits GoviEx will derive therefrom. Accordingly, readers should not place undue reliance on forward-looking statements. The forward-looking statements in this news release are made as of the date of this news release, and GoviEx disclaims any intention or obligation to update or revise such information, except as required by applicable law.
Cautionary Note to United States Persons:
The disclosure contained herein does not constitute an offer to sell or the solicitation of an offer to buy securities of GoviEx.
Safe Harbor Statement under the United States Private Securities Litigation Reform Act of 1995: Except for the statements of historical fact contained herein, the information presented constitutes "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements including but not limited to those referenced above collectively as "forward-looking statements" under the "Cautionary Statement Regarding Forward-Looking Information" involve known and unknown risks, uncertainties and other factors which may cause the actual results, the performance or achievements of GoviEx to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. There can be no assurance that such statements will prove to be accurate as actual results, and future events could differ materially from those anticipated in such statements. Accordingly, readers should not place undue reliance on forward-looking statements.
To view the source version of this press release, please visit https://www.newsfilecorp.com/release/248709
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Canadian Natural Resources Limited (TSX: CNQ) (NYSE: CNQ) ("Canadian Natural" or the "Company") announces that it has amended its Amended, Compiled and Restated Stock Option Plan (the "Plan") to clarify that the amendment provisions of the Plan require shareholder approval for any amendments to such provisions (the "Amendment"). The Amendment updates the disclosure on page 16 and Schedule D of Canadian Natural's proxy statement and management information circular dated March 19, 2025 (the "Circular") and is effective as of the date hereof.
Canadian Natural's shareholders are being asked to approve all unallocated stock options pursuant to the Plan, as modified by the Amendment, at the Company's upcoming annual and special meeting of shareholders to be held on May 8, 2025 at 11:00 am (MDT). Canadian Natural believes that the Amendment is consistent with the policies of Institutional Shareholder Services ("ISS") and encourages all shareholders to vote FOR the approval of the unallocated stock options under the Plan, as modified by the Amendment, all as more particularly described in the Circular.
Canadian Natural is a senior crude oil and natural gas production company, with continuing operations in its core areas located in Western Canada, the U.K. portion of the North Sea and Offshore Africa.
| Canadian Natural Resources LIMITED T (403) 517-6700 F (403) 517-7350 E ir@cnrl.com 2100, 855 - 2 Street S.W. Calgary, Alberta, T2P 4J8 www.cnrl.com | ||
| SCOTT G. STAUTH President MARK A. STAINTHORPE Chief Financial Officer LANCE J. CASSON Manager, Investor Relations Trading Symbol - CNQ Toronto Stock Exchange New York Stock Exchange |
Certain information regarding the Company contained herein may constitute forward-looking statements under applicable securities laws. Such statements are subject to known or unknown risks and uncertainties that may cause actual results to differ materially from those anticipated or implied in the forward-looking statements. The Company does not undertake to update forward-looking statements except as required by applicable securities laws. Refer to our website for detailed forward-looking statements and notes regarding Non-GAAP and Other Financial Measures at www.cnrl.com.
To view the source version of this press release, please visit https://www.newsfilecorp.com/release/248645
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