Coelacanth Announces 2024 Year-End Reserves

Coelacanth Announces 2024 Year-End Reserves

 

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)

 
                                        
Working Interest Reserves (2)Tight Oil
(Mbbl)
Shale
Natural Gas
(Mmcf)
NGLs
(Mbbl)
Total Oil Equivalent
(Mboe) (3)
Proved



Producing3448,0971501,843
Developed non-producing1,87438,8627209,071
Undeveloped1,13727,3245066,197
Total proved3,35574,2831,37617,111
Probable2,15444,54382510,403
Total proved & probable5,509118,8262,20127,515
 

 

 

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




Producing21,61517,65514,82712,76511,220
Developed non-producing131,34697,17974,10557,82545,878
Undeveloped93,06863,38944,90332,68924,196
Total proved246,030178,224133,834103,27981,294
Probable221,362147,285105,80680,43163,701
Total proved & probable467,391325,509239,640183,710144,995
 

 

 

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:

 
                                                                        
YearWTI Oil @ Cushing
($US / Bbl)
Edmonton Light Oil
($Cdn / Bbl)
AECO Natural Gas
($Cdn / Mmbtu)
Chicago Natural Gas
($US / Mmbtu)
Foreign Exchange
(Cdn$/US$)
202571.2591.332.052.790.7050
202673.5093.323.003.700.7300
202776.0096.453.504.010.7500
202878.5399.824.004.100.7500
202980.10101.804.084.180.7500
203081.70103.844.164.270.7500
203183.34105.924.244.350.7500
203285.00108.044.334.450.7500
203386.70110.204.414.540.7500
203488.44112.404.504.630.7500
Escalate thereafter (1)2.0% per year2.0% per year2.0% per year2.0% 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 CategoryRLI
Proved plus Probable Reserves69.0
Proved Reserves42.9
 

 

 

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 ProvedTight 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 ProbableTight OilShale
Natural Gas
NGLsTotal 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)202420232022
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

 
                  
Bblbarrel
Mbblthousands of barrels
MMbtumillions of British thermal units
Mcfthousand cubic feet
MMcfmillion cubic feet
NGLsnatural gas liquids
BOEbarrel of oil equivalent
MBOEthousands of barrels of oil equivalent
WTIWest 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

 
 

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

 

 

 

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FINANCIAL RESULTS
Three Months Ended
 
March 31
($000s, except per share amounts)
 2025 

 2024 

 % Change  
 
 

 

 
Oil and natural gas sales
2,666

3,666

(27)
 
 

 

 
Cash flow from operating activities
981

3,256

(70)
Per share - basic and diluted (1)
-

0.01

(100)
 
 

 

 
Adjusted funds flow (used) (1)
(1,440)
1,078

(234)
Per share - basic and diluted
(-)
-

(-)
 
 

 

 
Net loss
(3,617)
(1,201)
201
Per share - basic and diluted
(0.01)
(-)
100
 
 

 

 
Capital expenditures (1)
25,701

1,263

1,935
 
 

 

 
Adjusted working capital (deficiency) (1)
(25,710)
67,139

(138)
 
 

 

 
Common shares outstanding (000s)
 

 

 
Weighted average - basic and diluted
531,445

529,196

-
 
 

 

 
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679

248

9,192

2,459

274

  

 

 

 

 

 
Cash flow used in operating activities (3,730)
(2,553)
46

(954)
(3,830)
(75)
Per share - basic and diluted (1) (0.01)
(0.01)
-

(-)

(0.01)
(100)

  

 

 

 

 

 
 Adjusted funds flow (used) (1) (207)
(773)
(73)
1,133

(2,083)
(154)
Per share - basic and diluted (-)

(-)

-

-

(-)

-

  

 

 

 

 

 
Net loss (2,464)
(1,869)
32

(5,994)
(5,823)
3
Per share - basic and diluted (-)

(-)

-

(0.01)
(0.01)
-

  

 

 

 

 

 
 Capital expenditures (1) 15,760

31,176

(49)
19,545

39,957

(51)

  

 

 

 

 

 
 Adjusted working capital (1)  

 

 

47,264

23,516

101

  

 

 

 

 

 
Common shares outstanding (000s)  

 

 

 

 

 
Weighted average - basic and diluted 530,212

426,476

24

529,605

425,685

24

  

 

 

 

 

 
End of period - basic  

 

 

530,267

426,670

24
End of period - fully diluted  

 

 

617,214

469,781

31
   

 

 

 

 

 
(1) See "Non-GAAP and Other Financial Measures" section.
 

 

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Skyharbour Partner Company Terra Clean Energy Announces Immediate Follow-Up Summer Drill Program on the Back of Drill Results from Winter Program at South Falcon East Uranium Project

Skyharbour Partner Company Terra Clean Energy Announces Immediate Follow-Up Summer Drill Program on the Back of Drill Results from Winter Program at South Falcon East Uranium Project

 

Skyharbour Resources Ltd. (TSX-V: SYH ) (OTCQX: SYHBF ) (Frankfurt: SC1P ) ( " Skyharbour " or the " Company ") is pleased to report that its partner company Terra Clean Energy Corp. ("Terra", previously Tisdale Clean Energy) announces results from its Winter 2025 drill program and provides an update on the upcoming summer drill program at the South Falcon East Uranium Project (the "Property"), which hosts the Fraser Lakes B Uranium Deposit. The Property lies 18 km outside the edge of the Athabasca Basin, approximately 50 km east of the Key Lake mill and former mine. Skyharbour optioned the Project to Terra, and under the Option Agreement, assuming the 75% interest is earned, Terra will fund exploration expenditures totaling CAD $10,500,000, as well as pay Skyharbour CAD $11,100,000 in cash, of which $6,500,000 can be settled for shares in the capital of Terra ("Shares") over the earn-in period.

 

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Stallion Uranium Refines Coyote Target with Highly Conductive Anomalies from Ground EM Survey

Stallion Uranium Refines Coyote Target with Highly Conductive Anomalies from Ground EM Survey

 

Stallion Uranium Corp. (the " Company " or " Stallion ") ( TSX-V: STUD ; OTCQB: STLNF ; FSE: FE0 ) is pleased to announce the results from a Stepwise Moving Loop, Time Domain Electromagnetic (" SWML-TDEM ") survey completed over the high-priority Coyote Target on its Moonlite Project (Figure 1). The Coyote Target, located within the Southwestern Athabasca Basin spans claims held in partnership with Atha Energy Corp. (" Atha Energy ") ( TSX-V: SASK ) as well as claims that are 100% owned by Stallion Uranium.

 

  "These results confirm the presence of strong basement conductors beneath the Athabasca Basin sandstone, with characteristics consistent with major uranium discoveries," said Darren Slugoski, VP Exploration for Stallion Uranium. "Conductor - Coyote_14.25S, in particular, stands out as a high-priority drill target, supported by both strong geophysical response and a coincident gravity low; suggesting possible uranium alteration."  

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Stallion Uranium Completes Shares for Debt

Stallion Uranium Completes Shares for Debt

 

Stallion Uranium Corp. (the " Company " or " Stallion " ) ( TSX-V: STUD ; OTCQB: STLNF ; FSE: FE0 ) is pleased to announce that, further to its news release dated May 22, 2025, the Company has settled its outstanding debt with Atha Energy Corp. ("Atha") on July 16, 2025 and issued 802,809 common shares of the Company to Atha at a deemed price of $0.135 per share.

 

  About Stallion Uranium Corp.  

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Blue Sky Uranium Extends Non-Brokered Private Placement

Blue Sky Uranium Extends Non-Brokered Private Placement

 
 
 

  Blue Sky Uranium Corp. logo (CNW Group/Blue Sky Uranium Corp.) 

 
 

  /NOT FOR DISTRIBUTION TO THE UNITED   STATES OR THROUGH U.S.   NEWSWIRE   SERVICES/  

 

 

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Homerun Resources Inc. Announces Update on European Financial Markets Advisory

Homerun Resources Inc. Announces Update on European Financial Markets Advisory

Homerun Resources Inc. (TSXV: HMR,OTC:HMRFF) (OTCQB: HMRFF) ("Homerun" or the "Company") announces that, further to its April 2, 2025 news release, the Company will not be proceeding with the previously contemplated engagement of DGWA GmbH as a European financial markets' adviser. The Company is currently advancing other European financing and advisory relationships.

About Homerun (www.homerunresources.com)
Homerun (TSXV: HMR,OTC:HMRFF) is a vertically integrated materials leader revolutionizing green energy solutions through advanced silica technologies. As an emerging force outside of China for high-purity quartz (HPQ) silica innovation, the Company controls the full industrial vertical from raw material extraction to cutting-edge solar, battery and energy storage solutions. Our dual-engine vertical integration strategy combines:

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Skyharbour's Partner Company UraEx Resources Commences Summer 2025 Drilling Program at South Dufferin Uranium Project, Athabasca Basin, Saskatchewan

Skyharbour's Partner Company UraEx Resources Commences Summer 2025 Drilling Program at South Dufferin Uranium Project, Athabasca Basin, Saskatchewan

 

Skyharbour Resources Ltd. (TSX-V: SYH ) (OTCQX: SYHBF ) (Frankfurt: SC1P ) ("Skyharbour" or the "Company") is pleased to announce that its earn-in option partner, UraEx Resources Inc. ("UraEx"), has commenced an inaugural 2,600-metre diamond drilling program at the South Dufferin Uranium Project ("South Dufferin" or the "Property") located immediately south of the southern margin of the Athabasca Basin, proximal to Cameco's Centennial deposit. UraEx can earn an initial 51% in the Property through CAD $4,600,000 in combined project consideration and up to 100% through $9,800,000 in combined project consideration consisting of cash and share payments as well as exploration expenditures over a five-year period.

 

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