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Coelacanth Energy Inc. (TSXV: CEI,OTC:CEIEF) ("Coelacanth" or the "Company") has provided an Operations Update, Reserve Report, and Resource Report.
OPERATIONS UPDATE
Coelacanth Energy (TSXV:CEI) is a junior oil and natural gas exploration and development company exploring the prolific Montney region in northeastern British Columbia, Canada. Coelacanth is strategically positioned to harness the potential of one of the most resource-rich natural gas basins in North America with a substantial landholding of approximately 150 net sections in the Two Rivers area of Montney.
The company is in the process of deploying $ 80 million to facilitate the smooth transition from exploration to production. Coelacanth’s financial health is further evidenced by its $64.4 million in working capital as of Q2 2024.
Coelacanth’s landholdings are strategically located in the Two Rivers area of Montney, giving it access to a highly productive portion of the basin. Unlike many junior exploration companies, Coelacanth is drill-ready, positioning it favorably among its peers. By securing significant infrastructure and landholdings, Coelacanth ensures its ability to tap into the natural gas and oil resources that lie beneath its properties, a key advantage in the competitive Montney region.
Company Highlights
- The company holds approximately 150 net sections of land in the Two Rivers area, a prolific oil and liquids rich natural gas region.
- Coelacanth is fully permitted and financially secure, with $64.4 million in working capital as of Q2 2024 and a $52 million credit facility with its main lender.
- The company is spending approximately $80 million to construct pipeline and facility infrastructure to bring production on in April 2025.
- The company’s strategic location in Montney places it near major producers like ARC Resources, Tourmaline Oil Corp, Shell, and ConocoPhillips.
- Two Rivers East, its primary project, boasts 1,532 (thousand barrels of oil equivalent) mboe per well in proved and probable reserves.
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Coelacanth Energy
Investment Insight
Coelacanth Energy presents strong growth potential in the Canadian light oil and natural gas sector with encouraging well test results, a robust infrastructure buildout, and a management team with a track record of repeated success, making it a compelling growth story.
Overview
Coelacanth Energy (TSXV:CEI) is a junior oil and natural gas exploration and development company, focusing primarily on the prolific Montney region in northeastern British Columbia, Canada. With a substantial landholding of approximately 150 net sections in the Two Rivers area of Montney, Coelacanth is strategically positioned to harness the potential of one of the most resource-rich natural gas basins in North America.
Coelacanth distinguishes itself with a two-pronged strategy: near-term production growth and long-term resource development. Supported by advanced geological delineation and a robust infrastructure buildout, the company is poised to scale efficiently as it transitions from exploration to production.
Backed by a management team that has built and sold six successful oil and gas companies, Coelacanth is focused on delivering returns through disciplined capital deployment and operational execution.
The Montney Advantage
The Montney Formation spans British Columbia and Alberta and is known for its high levels of recoverable natural gas and liquids. Montney has attracted numerous large oil and gas producers, including companies like Canadian Natural Resources (CNQ), Shell, ARC Resources (ARX), Tourmaline Oil Corp (TOU), and ConocoPhillips (COP). The presence of such large players highlights the importance of this region in contributing to both the Canadian and global energy markets.
Coelacanth’s landholdings are strategically located in the Two Rivers area of Montney, giving it access to a highly productive portion of the basin. Unlike many junior exploration companies, Coelacanth is drill-ready, positioning it favorably among its peers. By securing significant infrastructure and landholdings, Coelacanth ensures its ability to tap into the natural gas and oil resources that lie beneath its properties, a key advantage in the competitive Montney region.
Company Highlights
- Over 150 net sections of contiguous land in the Two Rivers area, located in the Montney geological fairway, a prolific oil and liquids-rich natural gas region.
- Strategic proximity to major producers like ARC Resources, Tourmaline Oil Corp, Shell and ConocoPhillips.
- Fully permitted and funded infrastructure development program, with first production from Two Rivers East Pad started in June 2025 and expected to ramp through the summer.
- Phase 1 facilities will support initial production of 8,000 boe/d; Phase 2 will add compression and double total capacity by Q4 2025.
- Nine wells have been drilled and tested at the 5-19 pad, collectively flowing at over 11,000 boe/d in flush test rates.
- Estimated production growth: 4,000 boe/d in 2025; 11,000 boe/d in 2026; 15,000 boe/d in 2027.
Key Projects
Two Rivers East and Two Rivers West
The Two Rivers Montney development is the cornerstone of Coelacanth’s growth strategy. This multi-zone resource play features Lower, Upper, Basal and Middle Montney formations, offering significant running room for future development. The company has drilled and tested nine wells on the 5-19 pad (seven Lower Montney, one Upper, one Basal), yielding impressive flush production test rates totaling more than 11,000 boe/d, on a combined basis. Some wells tested at over 1,200 boepd with 50 percent light oil, highlighting strong liquids yields.
Two Rivers Asset Advantage
Two Rivers East started first production in June 2025, with production to be systematically ramped up over the summer. This production is supported by a new Phase 1 facility capable of processing 30 mmcf/d of gas and associated oil. Phase 2, planned for late 2025, will double capacity with added compression.
The Two Rivers West project, already in production, complements the East project with upside in the Upper Montney and delineation potential across additional benches. Test wells have demonstrated commercial deliverability and support long-term production sustainability.
Market Access and Takeaway Agreements
Coelacanth has secured long-term gas takeaway for its growing production base. The company holds firm commitments for up to 100 mmcf/d of natural gas takeaway capacity and has secured processing capacity of up to 60 mmcf/d at a third-party facility. Oil and condensate produced from the Montney light oil window can be trucked to regional terminals or connected via infrastructure to major hubs including Fort Saskatchewan, Edmonton and Prince George.
On the gas side, Coelacanth has egress options through pipelines such as NGTL, Westcoast and Alliance, and is strategically positioned to benefit from future access to LNG Canada via the Coastal GasLink system.
Board and Management
Rob Zakresky – President and CEO
Rob Zakresky has a significant background in the oil and gas sector, previously serving as the president and CEO of Leucrotta Exploration as well as five additional predecessor companies. He has been with Coelacanth Energy since its inception and is recognized for his strategic leadership and focus on enhancing shareholder value. His expertise in financial management and operations is reflected in his approach to driving the company's growth.
Bret Kimpton – Vice-president of Operations and COO
Bret Kimpton joined Coelacanth Energy in 2022, bringing a wealth of experience from his previous role as vice president of production at Storm Resources, where he contributed to significant production growth. He has a strong background in construction and operations, especially in the Montney region of British Columbia, managing various fields. His role at Coelacanth focuses on overseeing operational efficiency and implementing the company's growth strategies.
Nolan Chicoine – Vice-president of Finance and CFO
Nolan Chicoine has also been with Coelacanth Energy since its inception. His responsibilities encompass financial oversight, including financial planning, reporting, and analysis. He plays a crucial role in aligning the financial strategies with the company's operational goals. His background includes significant experience in financial management as CFO for Leucrotta Exploration, Crocotta Energy, and Chamaelo Energy.
Jody Denis – Vice-president of Drilling & Completions
Jody Denis is the former drilling, engineering & operations engineer at Leucrotta Exploration. Prior to that, he was senior operations advisor at Black Swan Energy, drilling manager at ARC Resources, and drilling and completions manager at Birchcliff Energy.
John Fur – Vice-president Geosciences
John Fur is the former manager, exploration of Leucrotta Exploration, and former senior geophysicist at Crocotta Energy, Chamaelo Energy, Chamaelo Exploration, Viracocha Energy, Canadian Natural Resources, Post Energy, Amber Energy and Husky Oil.
Light oil & Natural gas exploration and production in the prolific Montney region in British Columbia
Coelacanth Energy Inc. Announces Operations Update, Revised Reserve Report and Initial Resource Report
Coelacanth completed and commissioned its new battery facility in early June and subsequently started to systematically place the 9 previously drilled Montney wells from the 5-19 pad on production. Although Coelacanth has chosen to moderate the pace of wells brought on-stream because of low natural gas prices at the Station 2 hub, the results to date have exceeded expectations.
Lower Montney
Three Lower Montney wells (D5-19, E5-19, F5-19) were placed on production this summer and have meaningful initial production data as follows:
- D5-19 has a completed lateral length of 3,180 metres and had sales production for its initial 30-day period of 1,037 boe/d (57% liquids) comprised of 546 bbls/d of light oil, 2,659 mmcf/d of natural gas and 48 bbls/d of natural gas liquids.
- E5-19 has a completed lateral length of 2,775 metres and had sales production for its initial 30-day period of 1,346 boe/d (67% liquids) comprised of 854 bbls/d of light oil, 2,660 mmcf/d of natural gas and 49 bbls/d of natural gas liquids.
- F5-19 has a completed lateral length of 2,800 metres and had sales production for its initial 22-day period of 1,323 boe/d (61% liquids) comprised of 745 bbls/d of light oil, 3,121 mmcf/d of natural gas and 58 bbls/d of natural gas liquids.
The wells have exceeded initial production on a proved plus probable basis (2P) as booked by GLJ Ltd. ("GLJ") in its independent evaluation for Coelacanth.
GLJ RESERVE REPORT DATED EFFECTIVE JUNE 30, 2025
Coelacanth has updated its previously disclosed 2024 year-end reserves report as independently evaluated by GLJ. The new GLJ reserves report is effective June 30, 2025 and is a mechanical update to the prior report (the "Reserve Report"). The mechanical update does not change the production profiles provided in the 2024 year-end report but does provide the following:
- Reclassification of reserves on all 9 Montney wells on the 5-19 pad (8.7 million boe) from non-producing status (Proved Non-Producing and Probable Non-Producing) to producing status (Proved Producing and Probable Producing) given Coelacanth's new battery facility is complete and all wells are now capable of production.
- Rescheduled timing of wells being placed on production.
- Removal of $37.5 million of future development capital pertaining to facility and other capital booked prior to the July 1, 2025 effective date.
- Updated future pricing reflecting GLJ's latest price forecast.
The Report increases the overall reserve value by $40.4 million from the year-end report but more importantly increases the producing status reserves by $107.4 million (estimated future net revenues before taxes discounted at 10%). Coelacanth believes the July 1, 2025 updated GLJ Report better reflects the current status of the Company given the changes as noted above.
Congruent with the prior report, GLJ has placed reserves on less than 10 net sections of land and predominantly in the Lower Montney leaving room to expand the reserve base both aerially and vertically.
Reserves Summary
Coelacanth's June 30, 2025 reserves as prepared by GLJ effective June 30, 2025 and based on the GLJ (2025-07) future price forecast are as follows: (1)
| Working Interest Reserves (2) | Tight Oil (Mbbl) | Shale Natural Gas (Mmcf) | NGLs (Mbbl) | Total Oil Equivalent (Mboe) (3) |
| Proved | ||||
| Producing | 2,017 | 45,129 | 836 | 10,374 |
| Developed non-producing | - | - | - | - |
| Undeveloped | 1,256 | 28,336 | 525 | 6,504 |
| Total proved | 3,273 | 73,465 | 1,361 | 16,878 |
| Probable | 2,157 | 44,640 | 827 | 10,424 |
| Total proved & probable | 5,430 | 118,105 | 2,188 | 27,302 |
| 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. |
Reserves Values
The estimated future net revenues before taxes associated with Coelacanth's reserves effective June 30, 2025 and based on the GLJ (2025-07) future price forecast are summarized in the following table: (1,2,3)
| Discount factor per year | |||||
| ($000s) | 0% | 5% | 10% | 15% | 20% |
| Proved | |||||
| Producing | 176,441 | 144,557 | 122,202 | 105,937 | 93,680 |
| Developed non-producing | - | - | - | - | - |
| Undeveloped | 97,882 | 68,628 | 49,981 | 37,384 | 28,424 |
| Total proved | 274,323 | 213,185 | 172,183 | 143,321 | 122,104 |
| Probable | 214,074 | 146,438 | 107,868 | 83,914 | 67,902 |
| Total proved & probable | 488,397 | 359,623 | 280,051 | 227,235 | 190,006 |
| Notes: | |
| (1) | Numbers may not add due to rounding. |
| (2) | The estimated future net revenues are stated prior to provision for interest, debt service charges or general and administrative expenses and after deduction of royalties, operating costs, estimated well abandonment and reclamation costs and estimated future capital expenditures. |
| (3) | The estimated future net revenue contained in the table does not necessarily represent the fair market value of the reserves. There is no assurance that the forecast price and cost assumptions contained in the GLJ Report will be attained and variations could be material. The recovery and reserve estimates described herein are estimates only. Actual reserves may be greater or less than those calculated. |
Price Forecast
The GLJ (2025-07) price forecast is as follows:
| Year | WTI Oil @ Cushing ($US / Bbl) | Edmonton Light Oil ($Cdn / Bbl) | AECO Natural Gas ($Cdn / Mmbtu) | Chicago Natural Gas ($US / Mmbtu) | Foreign Exchange (Cdn$/US$) |
| 2025 Q3-Q4 | 65.00 | 84.93 | 2.20 | 3.55 | 0.7300 |
| 2026 | 70.00 | 90.54 | 3.46 | 4.35 | 0.7400 |
| 2027 | 73.50 | 94.00 | 3.50 | 4.01 | 0.7500 |
| 2028 | 76.41 | 96.99 | 3.85 | 4.10 | 0.7500 |
| 2029 | 77.94 | 98.92 | 3.92 | 4.18 | 0.7500 |
| 2030 | 79.49 | 100.89 | 4.00 | 4.27 | 0.7500 |
| 2031 | 81.08 | 102.91 | 4.08 | 4.35 | 0.7500 |
| 2032 | 82.71 | 104.99 | 4.16 | 4.45 | 0.7500 |
| 2033 | 84.36 | 107.08 | 4.25 | 4.54 | 0.7500 |
| 2034 | 86.05 | 109.21 | 4.33 | 4.63 | 0.7500 |
| Escalate thereafter (1) | 2.0% per year | 2.0% per year | 2.0% per year | 2.0% per year |
| (1) | Escalated at two per cent per year starting in 2035 in the July 1, 2025 GLJ price forecast with the exception of foreign exchange, which remains flat. |
GLJ RESOURCE REPORT
GLJ has provided a Resource Report effective June 30, 2025 on Coelacanth's Two Rivers Montney lands encompassing approximately 150 net sections over 4 identified Montney zones (the "Resource Report"). As displayed below, Coelacanth has an estimated 6.9 billion barrels of Discovered Petroleum Initially-In-Place (PIIP) and 5.9 trillion cubic feet of Discovered Gas PIIP. The Resource Report also estimates 8.3 billion barrels of Undiscovered Petroleum PIIP and 7.1 trillion cubic feet of Undiscovered Gas PIIP in place on its lands.
To date, Coelacanth has focused to varying degrees on 3 of the 4 Montney zones (Upper, Lower, Basal) with extensive mapping, core work, and placement of horizontal wells in all 3 zones to help determine economics and ultimate recoveries of the resource. The Middle Montney has had minimal work performed on it to date and is listed as undiscovered at this point. Coelacanth will perform additional work on the middle Montney in the future to better understand its commerciality.
The Resource Report not only portrays how large the Coelacanth's Montney resource in place is, but will be used as a tool in determining well spacing, frac design and ultimate well recoveries to aid in the overall development of Coelacanth's Two Rivers project.
| Zone | Discovered Oil PIIP (Billion Bbls) | Undiscovered Oil PIIP (Billion Bbls) |
| Upper Montney | 2.5 | 0.2 |
| Middle Montney | - | 5.0 |
| Lower Montney | 3.0 | 0.2 |
| Basal Montney | 1.3 | 2.9 |
| Total Montney(1) | 6.9 | 8.3 |
| (1) | Numbers may not add due to rounding |
| Zone | Discovered Gas PIIP (Trillion cubic feet) | Undiscovered Gas PIIP (Trillion cubic feet) |
| Upper Montney | 2.1 | 0.1 |
| Middle Montney | - | 4.2 |
| Lower Montney | 2.6 | 0.2 |
| Basal Montney | 1.1 | 2.5 |
| Total Montney(1) | 5.9 | 7.1 |
| (1) | Numbers may not add due to rounding |
Overall, Coelacanth is very pleased with its well results to date and is looking forward to establishing the ultimate recoverable reserves while increasing booked reserves and on its large Two Rivers Montney Resource for the benefit of its stakeholders.
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) |
| WTI | West Texas Intermediate at Cushing, Oklahoma |
| Natural Gas | |
| Mcf | Thousands of cubic feet |
| Mcf/d | Thousands of cubic feet per day |
| MMcf/d | Millions of cubic feet per day |
| MMbtu | Millions of British thermal units |
| 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.
Product Types
The Company uses the following references to sales volumes in the news release:
Natural gas (and gas) refers to shale gas
Oil refers to tight oil
NGLs refers to butane, propane and pentanes combined
Liquids 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.
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, oil and natural gas resources, 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.
Resources Data
Total Petroleum Initially-In-Place (PIIP) is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered (equivalent to "total resources").
Discovered Petroleum Initially-In-Place (equivalent to discovered resources) is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of discovered petroleum initially in place includes production, reserves, and contingent resources; the remainder is unrecoverable.
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 further classified according to the level of certainty associated with the estimates and may be subclassified based on development and production status. [Reserves are further defined below].
Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political, and regulatory matters, or a lack of markets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. Contingent Resources are further classified in accordance with the level of certainty associated with the estimates and may be subclassified based on project maturity and/or characterized by their economic status.
Undiscovered Petroleum Initially-In-Place (equivalent to undiscovered resources) is that quantity of petroleum that is estimated, on a given date, to be contained in accumulations yet to be discovered. The recoverable portion of undiscovered petroleum initially in place is referred to as "prospective resources," the remainder as "unrecoverable."
Prospective Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development. Prospective Resources are further subdivided in accordance with the level of certainty associated with recoverable estimates assuming their discovery and development and may be subclassified based on project maturity.
There is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources. The key variables relevant to the evaluation are porosity, reservoir thickness, pressure, water saturation and gas composition which have increasing uncertainty, both positive and negative, with distance from existing wells.
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").
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.
Initial Production Rates
The D5-19 Lower Montney well was tied into the 16-03 facility, and produced an average rate of 546 bbl/d oil, 2,659 mcf/d natural gas, and 48 bbl/d NGLs, for a total average rate of 1,037 boe/d, on a sales basis, over the first 30 days of in-line production (IP30)
The E5-19 Lower Montney well was tied into the 16-03 facility, and produced an average rate of 854 bbl/d oil, 2,660 mcf/d natural gas, and 49 bbl/d NGLs, for a total average rate of 1,346 boe/d, on a sales basis, over the first 30 days of in-line production (IP30)
The F5-19 Lower Montney well was tied into the 16-03 facility, and produced an average rate of 745 bbl/d oil, 3,121 mcf/d natural gas, and 58 bbl/d NGLs, for a total average rate of 1,037 boe/d, on a sales basis, over the first 22 days of in-line production
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
Mr. Robert J. Zakresky
President and Chief Executive Officer
Mr. Nolan Chicoine
Vice President, Finance and Chief Financial Officer
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Coelacanth Announces Q2 2025 Financial and Operating Results
Coelacanth Energy Inc. (TSXV: CEI,OTC:CEIEF) ("Coelacanth" or the "Company") is pleased to announce its financial and operating results for the three and six months ended June 30, 2025. All dollar figures are Canadian dollars unless otherwise noted.
| FINANCIAL RESULTS | Three Months Ended | Six Months Ended | ||||||||||||||||
| June 30 | June 30 | |||||||||||||||||
| ($000s, except per share amounts) | 2025 | 2024 | % Change | 2025 | 2024 | % Change | ||||||||||||
| Oil and natural gas sales | 4,828 | 3,164 | 53 | 7,494 | 6,830 | 10 | ||||||||||||
| Cash flow from (used in) operating activities | (1,826 | ) | (480 | ) | 280 | (845 | ) | 2,776 | (130 | ) | ||||||||
| Per share - basic and diluted (1) | (-) | (-) | - | (-) | 0.01 | (100 | ) | |||||||||||
| Adjusted funds flow (used) (1) | (600 | ) | 262 | (329 | ) | (2,040 | ) | 1,340 | (252 | ) | ||||||||
| Per share - basic and diluted | (-) | - | (-) | (-) | - | (-) | ||||||||||||
| Net loss | (3,464 | ) | (2,329 | ) | 49 | (7,081 | ) | (3,530 | ) | 101 | ||||||||
| Per share - basic and diluted | (0.01 | ) | (-) | 100 | (0.01 | ) | (0.01 | ) | - | |||||||||
| Capital expenditures (1) | 14,273 | 2,522 | 466 | 39,974 | 3,785 | 956 | ||||||||||||
| Adjusted working capital (deficiency) (1) | (41,901 | ) | 64,386 | (165 | ) | |||||||||||||
| Common shares outstanding (000s) | ||||||||||||||||||
| Weighted average - basic and diluted | 532,274 | 529,400 | 1 | 531,862 | 529,298 | - | ||||||||||||
| End of period - basic | 532,866 | 530,126 | 1 | |||||||||||||||
| End of period - fully diluted | 591,544 | 617,804 | (4 | ) | ||||||||||||||
(1) See "Non-GAAP and Other Financial Measures" section.
| Three Months Ended | Six Months Ended | |||||||||||||||||
| OPERATING RESULTS (1) | June 30 | June 30 | ||||||||||||||||
| 2025 | 2024 | % Change | 2025 | 2024 | % Change | |||||||||||||
| Daily production (2) | ||||||||||||||||||
| Oil and condensate (bbls/d) | 539 | 284 | 90 | 362 | 292 | 24 | ||||||||||||
| Other NGLs (bbls/d) | 27 | 39 | (31 | ) | 26 | 38 | (32 | ) | ||||||||||
| Oil and NGLs (bbls/d) | 566 | 323 | 75 | 388 | 330 | 18 | ||||||||||||
| Natural gas (mcf/d) | 3,861 | 3,724 | 4 | 3,588 | 3,829 | (6 | ) | |||||||||||
| Oil equivalent (boe/d) | 1,210 | 944 | 28 | 986 | 968 | 2 | ||||||||||||
| Oil and natural gas sales | ||||||||||||||||||
| Oil and condensate ($/bbl) | 82.58 | 97.76 | (16 | ) | 84.51 | 91.34 | (7 | ) | ||||||||||
| Other NGLs ($/bbl) | 26.96 | 33.26 | (19 | ) | 32.19 | 33.99 | (5 | ) | ||||||||||
| Oil and NGLs ($/bbl) | 79.91 | 89.86 | (11 | ) | 81.01 | 84.73 | (4 | ) | ||||||||||
| Natural gas ($/mcf) | 2.02 | 1.55 | 30 | 2.77 | 2.50 | 11 | ||||||||||||
| Oil equivalent ($/boe) | 43.86 | 36.85 | 19 | 41.97 | 38.76 | 8 | ||||||||||||
| Royalties | ||||||||||||||||||
| Oil and NGLs ($/bbl) | 17.65 | 21.97 | (20 | ) | 17.20 | 21.36 | (19 | ) | ||||||||||
| Natural gas ($/mcf) | - | 0.09 | (100 | ) | 0.30 | 0.30 | - | |||||||||||
| Oil equivalent ($/boe) | 8.26 | 7.86 | 5 | 7.85 | 8.48 | (7 | ) | |||||||||||
| Operating expenses | ||||||||||||||||||
| Oil and NGLs ($/bbl) | 10.82 | 10.34 | 5 | 10.77 | 10.11 | 7 | ||||||||||||
| Natural gas ($/mcf) | 1.81 | 1.72 | 5 | 1.80 | 1.69 | 7 | ||||||||||||
| Oil equivalent ($/boe) | 10.86 | 10.34 | 5 | 10.77 | 10.11 | 7 | ||||||||||||
| Net transportation expenses (3) | ||||||||||||||||||
| Oil and NGLs ($/bbl) | 4.43 | 2.10 | 111 | 3.86 | 2.28 | 69 | ||||||||||||
| Natural gas ($/mcf) | 0.70 | 0.72 | (3 | ) | 0.74 | 0.70 | 6 | |||||||||||
| Oil equivalent ($/boe) | 4.33 | 3.55 | 22 | 4.20 | 3.54 | 19 | ||||||||||||
| Operating netback (loss) (3) | ||||||||||||||||||
| Oil and NGLs ($/bbl) | 47.01 | 55.45 | (15 | ) | 49.18 | 50.98 | (4 | ) | ||||||||||
| Natural gas ($/mcf) | (0.49 | ) | (0.98 | ) | (50 | ) | (0.07 | ) | (0.19 | ) | (63 | ) | ||||||
| Oil equivalent ($/boe) | 20.41 | 15.10 | 35 | 19.15 | 16.63 | 15 | ||||||||||||
| Depletion and depreciation ($/boe) | (12.76 | ) | (14.85 | ) | (14 | ) | (13.35 | ) | (14.63 | ) | (9 | ) | ||||||
| General and administrative expenses ($/boe) | (13.69 | ) | (15.17 | ) | (10 | ) | (16.78 | ) | (14.50 | ) | 16 | |||||||
| Stock based compensation ($/boe) | (10.31 | ) | (14.50 | ) | (29 | ) | (13.43 | ) | (12.25 | ) | 10 | |||||||
| Finance expense ($/boe) | (13.02 | ) | (1.53 | ) | 751 | (12.96 | ) | (1.29 | ) | 905 | ||||||||
| Finance income ($/boe) | 0.64 | 9.89 | (94 | ) | 0.96 | 10.25 | (91 | ) | ||||||||||
| Unutilized transportation ($/boe) | (2.75 | ) | (6.07 | ) | (55 | ) | (3.25 | ) | (4.24 | ) | (23 | ) | ||||||
| Net loss ($/boe) | (31.48 | ) | (27.13 | ) | 16 | (39.66 | ) | (20.03 | ) | 98 | ||||||||
(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 unaudited condensed interim financial statements and related Management's Discussion and Analysis ("MD&A") for the three and six months ended June 30, 2025, which are available for review under the Company's profile on SEDAR+ at www.sedarplus.ca.
OPERATIONS UPDATE
Coelacanth has surpassed many milestones over its initial three years including:
- Drilling and testing successful test pads at both Two Rivers East and West in multiple zones.
- Completing significant infrastructure including a facility capable of ultimately handling 16,000 boe/d and over 23 miles of pipelines to connect wells and facilities to major gathering systems.
- Obtaining core, pressure and other data that are invaluable in helping define commerciality to the multiple Montney horizons mapped over Coelacanth's 150 section contiguous land block.
Wells recently placed on production from our 5-19 pad have exceeded expectations and we look forward to placing all our wells on production by October 1, 2025 once all planned third party outages and /or major pipeline maintenance is completed in September. Coelacanth will calibrate production to the type curves in our independent reserve report and recently released resource report to determine ultimate recoveries and provide insights into potential drilling and completion optimizations.
Over the next few years, Coelacanth will continue with its business plan that incorporates:
- Systematically developing the resource using pad development and horizontal multi-frac technology to increase production and maximize cash flow and investment returns.
- Delineating the lands with vertical and horizontal wells to help in quantifying and understanding the commerciality of its large Montney resource base that includes up to four Montney benches over its 150 contiguous sections of land.
- Developing and licensing a flexible infrastructure plan that will allow for the resource to be scaled to a much larger production base.
Coelacanth has licensed additional locations on the 5-19 pad, is in the process of licensing additional development pads, delineation locations and additional infrastructure to grow beyond current plant capacity. While commodity prices and available capital will dictate the pace of execution of the business plan, we are very pleased with the results to date and look forward to reporting on new developments as they arise.
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) |
| Condensate | Pentane and heavier hydrocarbons |
| Natural Gas | |
| Mcf | Thousands of cubic feet |
| Mcf/d | Thousands of cubic feet per day |
| MMcf/d | Millions of cubic feet per day |
| MMbtu | Million of British thermal units |
| MMbtu/d | Million of British thermal units per day |
| 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 | Six Months Ended | |||||||||||
| June 30 | June 30 | |||||||||||
| ($000s) | 2025 | 2024 | 2025 | 2024 | ||||||||
| Cash flow from (used in) operating activities | (1,826 | ) | (480 | ) | (845 | ) | 2,776 | |||||
| Add (deduct): | ||||||||||||
| Decommissioning expenditures | 48 | 328 | 187 | 476 | ||||||||
| Change in restricted cash deposits | - | 422 | - | 846 | ||||||||
| Change in non-cash working capital | 1,178 | (8 | ) | (1,382 | ) | (2,758 | ) | |||||
| Adjusted funds flow (used) (non-GAAP) | (600 | ) | 262 | (2,040 | ) | 1,340 | ||||||
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 | Six Months Ended | |||||||||||
| June 30 | June 30 | |||||||||||
| ($000s) | 2025 | 2024 | 2025 | 2024 | ||||||||
| Transportation expenses | 779 | 826 | 1,330 | 1,371 | ||||||||
| Unutilized transportation | (303 | ) | (522 | ) | (580 | ) | (747 | ) | ||||
| Net transportation expenses (non-GAAP) | 476 | 304 | 750 | 624 | ||||||||
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 | Six Months Ended | |||||||||||
| June 30 | June 30 | |||||||||||
| ($000s) | 2025 | 2024 | 2025 | 2024 | ||||||||
| Oil and natural gas sales | 4,828 | 3,164 | 7,494 | 6,830 | ||||||||
| Royalties | (910 | ) | (674 | ) | (1,401 | ) | (1,495 | ) | ||||
| Operating expenses | (1,195 | ) | (888 | ) | (1,923 | ) | (1,782 | ) | ||||
| Net transportation expenses | (476 | ) | (304 | ) | (750 | ) | (624 | ) | ||||
| Operating netback (non-GAAP) | 2,247 | 1,298 | 3,420 | 2,929 | ||||||||
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: hello
| Three Months Ended | Six Months Ended | |||||||||||
| June 30 | June 30 | |||||||||||
| ($000s) | 2025 | 2024 | 2025 | 2024 | ||||||||
| Capital expenditures – property, plant, and equipment | 370 | 184 | 1,038 | 577 | ||||||||
| Capital expenditures – exploration and evaluation assets | 13,903 | 2,338 | 38,936 | 3,208 | ||||||||
| Capital expenditures (non-GAAP) | 14,273 | 2,522 | 39,974 | 3,785 | ||||||||
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 (deficiency) is calculated as current assets and restricted cash deposits less current liabilities, excluding the current portion of decommissioning obligations.
| ($000s) | June 30, 2025 | December 31, 2024 | ||||
| Current assets | 6,439 | 11,579 | ||||
| Less: | ||||||
| Current liabilities | (53,926 | ) | (37,234 | ) | ||
| Working capital deficiency | (47,487 | ) | (25,655 | ) | ||
| Add: | ||||||
| Restricted cash deposits | 4,900 | 4,900 | ||||
| Current portion of decommissioning obligations | 686 | 2,118 | ||||
| Adjusted working capital deficiency (Capital management measure) | (41,901 | ) | (18,637 | ) | ||
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.
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 | Six Months Ended | |||
| June 30 | June 30 | |||
| Sales Volumes by Product Type | 2025 | 2024 | 2025 | 2024 |
| Condensate (bbls/d) | 17 | 56 | 17 | 38 |
| Other NGLs (bbls/d) | 27 | 39 | 26 | 38 |
| NGLs (bbls/d) | 44 | 95 | 43 | 76 |
| Tight oil (bbls/d) | 522 | 228 | 345 | 254 |
| Condensate (bbls/d) | 17 | 56 | 17 | 38 |
| Oil and condensate (bbls/d) | 539 | 284 | 362 | 292 |
| Other NGLs (bbls/d) | 27 | 39 | 26 | 38 |
| Oil and NGLs (bbls/d) | 566 | 323 | 388 | 330 |
| Shale gas (mcf/d) | 3,861 | 3,724 | 3,588 | 3,829 |
| Natural gas (mcf/d) | 3,861 | 3,724 | 3,588 | 3,829 |
| Oil equivalent (boe/d) | 1,210 | 944 | 986 | 968 |
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. 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/264010
News Provided by Newsfile via QuoteMedia
Coelacanth Announces Q1 2025 Financial and Operating Results
Coelacanth Energy Inc. (TSXV: CEI) ("Coelacanth" or the "Company") is pleased to announce its financial and operating results for the three months ended March 30, 2025. All dollar figures are Canadian dollars unless otherwise noted.
| FINANCIAL RESULTS | Three Months Ended | ||||||||
| March 31 | |||||||||
| ($000s, except per share amounts) | 2025 | 2024 | % Change | ||||||
| Oil and natural gas sales | 2,666 | 3,666 | (27 | ) | |||||
| Cash flow from operating activities | 981 | 3,256 | (70 | ) | |||||
| Per share - basic and diluted (1) | - | 0.01 | (100 | ) | |||||
| Adjusted funds flow (used) (1) | (1,440 | ) | 1,078 | (234 | ) | ||||
| Per share - basic and diluted | (- | ) | - | (- | ) | ||||
| Net loss | (3,617 | ) | (1,201 | ) | 201 | ||||
| Per share - basic and diluted | (0.01 | ) | (- | ) | 100 | ||||
| Capital expenditures (1) | 25,701 | 1,263 | 1,935 | ||||||
| Adjusted working capital (deficiency) (1) | (25,710 | ) | 67,139 | (138 | ) | ||||
| Common shares outstanding (000s) | |||||||||
| Weighted average - basic and diluted | 531,445 | 529,196 | - | ||||||
| End of period - basic | 532,202 | 529,392 | 1 | ||||||
| End of period - fully diluted | 624,877 | 618,165 | 1 | ||||||
(1) See "Non-GAAP and Other Financial Measures" section.
| Three Months Ended | |||||||||
| OPERATING RESULTS (1) | March 31 | ||||||||
| 2025 | 2024 | % Change | |||||||
| Daily production (2) | |||||||||
| Oil and condensate (bbls/d) | 184 | 300 | (39 | ) | |||||
| Other NGLs (bbls/d) | 25 | 37 | (32 | ) | |||||
| Oil and NGLs (bbls/d) | 209 | 337 | (38 | ) | |||||
| Natural gas (mcf/d) | 3,311 | 3,934 | (16 | ) | |||||
| Oil equivalent (boe/d) | 761 | 993 | (23 | ) | |||||
| Oil and natural gas sales | |||||||||
| Oil and condensate ($/bbl) | 90.21 | 85.30 | 6 | ||||||
| Other NGLs ($/bbl) | 38.01 | 34.79 | 9 | ||||||
| Oil and NGLs ($/bbl) | 84.03 | 79.82 | 5 | ||||||
| Natural gas ($/mcf) | 3.65 | 3.40 | 7 | ||||||
| Oil equivalent ($/boe) | 38.94 | 40.57 | (4 | ) | |||||
| Royalties | |||||||||
| Oil and NGLs ($/bbl) | 15.95 | 20.77 | (23 | ) | |||||
| Natural gas ($/mcf) | 0.64 | 0.51 | 25 | ||||||
| Oil equivalent ($/boe) | 7.18 | 9.08 | (21 | ) | |||||
| Operating expenses | |||||||||
| Oil and NGLs ($/bbl) | 10.63 | 9.89 | 7 | ||||||
| Natural gas ($/mcf) | 1.77 | 1.65 | 7 | ||||||
| Oil equivalent ($/boe) | 10.63 | 9.89 | 7 | ||||||
| Net transportation expenses (3) | |||||||||
| Oil and NGLs ($/bbl) | 2.27 | 2.45 | (7 | ) | |||||
| Natural gas ($/mcf) | 0.78 | 0.68 | 15 | ||||||
| Oil equivalent ($/boe) | 4.00 | 3.54 | 13 | ||||||
| Operating netback (3) | |||||||||
| Oil and NGLs ($/bbl) | 55.18 | 46.71 | 18 | ||||||
| Natural gas ($/mcf) | 0.46 | 0.56 | (18 | ) | |||||
| Oil equivalent ($/boe) | 17.13 | 18.06 | (5 | ) | |||||
| Depletion and depreciation ($/boe) | (14.30 | ) | (14.42 | ) | (1 | ) | |||
| General and administrative expenses ($/boe) | (21.76 | ) | (13.86 | ) | 57 | ||||
| Share based compensation ($/boe) | (18.46 | ) | (10.11 | ) | 83 | ||||
| Finance expense ($/boe) | (12.86 | ) | (1.06 | ) | 1,113 | ||||
| Finance income ($/boe) | 1.46 | 10.60 | (86 | ) | |||||
| Unutilized transportation ($/boe) | (4.05 | ) | (2.49 | ) | 63 | ||||
| Net loss ($/boe) | (52.84 | ) | (13.28 | ) | 298 | ||||
(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 unaudited condensed interim financial statements and related Management's Discussion and Analysis ("MD&A") for the three months ended March 31, 2025, which are available for review under the Company's profile on SEDAR+ at www.sedarplus.ca.
OPERATIONS UPDATE
Coelacanth has reached a major milestone in its development with the completion of the Two Rivers East facility (the "Facility"). The Facility was completed on budget and has moved to the testing and start-up phase. The capacity of the Facility is currently 8,000 boe/d but will be expanded in Q4 2025 to 16,000 boe/d with added compression. We expect production to start flowing imminently from the 5-19 pad and ramp up through the summer. As previously released, the 5-19 pad has 9 wells that tested over 11,000 boe/d (1) that will be brought on systematically to approach the phase I capacity of the plant prior to further drilling.
Over the next few years, Coelacanth will continue with its business plan that incorporates:
- Systematically developing the resource using pad development and horizontal multi-frac technology to increase production and maximize cash flow and investment returns.
- Delineating the lands with vertical and horizontal wells to help in quantifying and understanding the commerciality of its large Montney resource base that includes up to four Montney benches over its 150 contiguous sections of land.
- Developing and licensing a flexible infrastructure plan that will allow for the resource to be scaled to a much larger production base.
Coelacanth has licensed additional locations on the 5-19 pad, is in the process of licensing additional development pads, delineation locations and additional infrastructure to grow beyond current plant capacity. While commodity prices and available capital will dictate the pace of execution of the business plan, we are very pleased with the results to date and look forward to reporting on new developments as they 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) |
| Condensate | Pentane and heavier hydrocarbons |
Natural Gas
| Mcf | Thousands of cubic feet |
| Mcf/d | Thousands of cubic feet per day |
| MMcf/d | Millions of cubic feet per day |
| MMbtu | Million of British thermal units |
| MMbtu/d | Million of British thermal units per day |
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 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 operating activities as follows:
| Three Months Ended | |||||||||
| March 31 | |||||||||
| ($000s) | 2025 | 2024 | % Change | ||||||
| Cash flow from operating activities | 981 | 3,256 | (70 | ) | |||||
| Add (deduct): | |||||||||
| Decommissioning expenditures | 139 | 148 | (6 | ) | |||||
| Change in restricted cash deposits | - | 424 | (100 | ) | |||||
| Change in non-cash working capital | (2,560 | ) | (2,750 | ) | (7 | ) | |||
| Adjusted funds flow (used) (non-GAAP) | (1,440 | ) | 1,078 | (234 | ) | ||||
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 | ||||||
| March 31 | ||||||
| ($000s) | 2025 | 2024 | ||||
| Transportation expenses | 551 | 545 | ||||
| Unutilized transportation | (277 | ) | (225 | ) | ||
| Net transportation expenses (non-GAAP) | 274 | 320 | ||||
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 | ||||||
| March 31 | ||||||
| ($000s) | 2025 | 2024 | ||||
| Oil and natural gas sales | 2,666 | 3,666 | ||||
| Royalties | (491 | ) | (821 | ) | ||
| Operating expenses | (728 | ) | (894 | ) | ||
| Net transportation expenses | (274 | ) | (320 | ) | ||
| Operating netback (non-GAAP) | 1,173 | 1,631 | ||||
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 | ||||||
| March 31 | ||||||
| ($000s) | 2025 | 2024 | ||||
| Capital expenditures – property, plant, and equipment | 668 | 393 | ||||
| Capital expenditures – exploration and evaluation assets | 25,033 | 870 | ||||
| Capital expenditures (non-GAAP) | 25,701 | 1,263 | ||||
Capital Management Measures
Adjusted working capital
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) | March 31, 2025 | December 31, 2024 | ||||
| Current assets | 3,431 | 11,579 | ||||
| Less: | ||||||
| Current liabilities | (36,009 | ) | (37,234 | ) | ||
| Working capital deficiency | (32,578 | ) | (25,655 | ) | ||
| Add: | ||||||
| Restricted cash deposits | 4,900 | 4,900 | ||||
| Current portion of decommissioning obligations | 1,968 | 2,118 | ||||
| Adjusted working capital deficiency (Capital management measure) | (25,710 | ) | (18,637 | ) | ||
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.
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 | ||
| March 31 | ||
| Sales Volumes by Product Type | 2025 | 2024 |
| Condensate (bbls/d) | 18 | 19 |
| Other NGLs (bbls/d) | 25 | 37 |
| NGLs (bbls/d) | 43 | 56 |
| Tight oil (bbls/d) | 166 | 281 |
| Condensate (bbls/d) | 18 | 19 |
| Oil and condensate (bbls/d) | 184 | 300 |
| Other NGLs (bbls/d) | 25 | 37 |
| Oil and NGLs (bbls/d) | 209 | 337 |
| Shale gas (mcf/d) | 3,311 | 3,934 |
| Natural gas (mcf/d) | 3,311 | 3,934 |
| Oil equivalent (boe/d) | 761 | 993 |
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. 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/253761
News Provided by Newsfile via QuoteMedia
Coelacanth Announces Q4 2024 Financial and Operating Results
Coelacanth Energy Inc. (TSXV: CEI) ("Coelacanth" or the "Company") is pleased to announce its financial and operating results for the three months and year ended December 31, 2024. All dollar figures are Canadian dollars unless otherwise noted.
2024 HIGHLIGHTS
- Drilled and completed three Lower Montney wells and completed a previously drilled Upper Montney well on its 5-19 pad at Two Rivers East. Average test production from the three Lower Montney wells was 1,624 boe/d (61% light oil) and test production from the Upper Montney well was 1,338 boe/d (54% light oil). (2)
- Secured revolving bank credit facilities for a total of $52.0 million from a Canadian chartered bank.
- Substantially completed construction of pipelines to connect the 5-19 pad wells to the Two Rivers East facility.
- Initiated construction of its Two Rivers East facility for a Q2 2025 on-stream date.
| 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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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 | ||||
| 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
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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Charbone Hydrogen
Investor Insight
Charbone Hydrogen offers a compelling investment opportunity in the US$89 billion Ultra High Purity (UHP) and low-carbon intensity hydrogen market, leveraging a decentralized approach for scalable plant deployment and focusing on environmentally friendly production to reduce carbon footprints.
Overview
Charbone Hydrogen (TSXV:CH,OTCQB:CHHYF,FWB:K47) is an integrated company specialized in Ultra High Purity (UHP) hydrogen and the strategic distribution of industrial gases in North America and the Asia-Pacific region. It is developing a modular network of green hydrogen production while partnering with industry players to supply helium and other specialty gases without the need to build costly new plants. This disciplined strategy diversifies revenue streams, reduces risks, and increases flexibility.
Charbone has recently accelerated its growth trajectory, securing a US$50 million financing to expand across North America, executing a US$1 million collaboration agreement to advance a green hydrogen project in Malaysia, and achieving multiple milestones at its flagship Sorel-Tracy facility in Québec.
With its exclusive focus on UHP green hydrogen, Charbone is positioning itself as a first mover in a multi-billion-dollar market. Leveraging Canada’s abundant hydroelectric power and expanding nuclear capacity, Charbone plans to deliver sustainable hydrogen solutions that meet rising demand from both governments and global industries.
Company Highlights
- Canada’s only publicly listed green hydrogen company: Charbone Hydrogen offers investors unique exposure to the fast-growing hydrogen economy as a company focused on green hydrogen production and distribution.
- Building a North American green hydrogen pipeline: The company is advancing multiple projects, anchored by its flagship Sorel-Tracy facility in Québec, to establish a scalable production and distribution network.
- Well-financed for growth and expansion: Charbone secured a US$50 million financing, facilitated by US Capital Global, to accelerate funding of modular build-out and expand its footprint across North America.
- Expanding into international markets: Through a US$1 million master collaboration agreement, Charbone is supporting the deployment of a green hydrogen project in Malaysia, highlighting its global reach.
- Aligned with strong policy and market tailwinds: For years, Canada leaned on centralized, fossil-based reformers. That playbook is obsolete. Now, Quebec’s hydropower surplus runs electrolyzers that split H₂O into H₂ and O₂ with zero carbon footprint. Charbone’s plug-and-play approach repurposes proven gear, slashing lead times and trimming capex. Charbone is well-placed for long-term growth.
- Exclusive focus on ultra-pure green hydrogen production: Charbone is dedicated to producing hydrogen using renewable hydroelectric and nuclear energy — a critical pathway to decarbonization and huge demand of ultra-high purity hydrogen in electronics and military sectors.
Project Pipeline and Key Partnerships
Charbone forged strong partnerships to execute its business model. Here’s where it gets cool: renewable hydroelectricity powers electrolyzers that split water into hydrogen and oxygen. Purification skids then crank it up to 99.999% purity—true industrial grade. This hydrogen production model serves everything from fuel-cell fleets and semiconductor fabs to specialty metal processing and next-gen refueling stations.
Charbone isn’t flying solo. They’ve teamed up with:
- A leading Canadian energy distributor supplying the battle-tested equipment
- Hydro-Québec delivering clean, reliable electrons
- An ABB partnership to boost North American production networks
- Offtake and supply agreements with U.S. Tier-One industrial gases producer
- Public listings on TSX Venture, OTCQB, and Frankfurt for global financing access
This lineup de-risks the rollout and turbocharges their momentum.
Charbone has signed a memorandum of understanding (MoU) with ABB to collaborate on the development of up to 15 modular and scalable green hydrogen production facilities across North America over the next five years. Under the MOU, ABB will support CHARBONE in standardizing basic engineering for systems and components across its project portfolio to increase energy efficiency and reliability.
Among the sites covered by the collaboration is Charbone's flagship Sorel-Tracy facility near Montreal in Québec, Canada, which is currently under construction. The Sorel-Tracy facility is located on a 40,000-square-meter land parcel along Quebec Highway 30, known as the “Steel Highway” because of the numerous steel mills and process plants operating along the highway.
The construction of its Sorel-Tracy facility is being done in partnership with EBC, one of the largest construction companies in Quebec. EBC has a proven track record of designing and building facilities in Canada and the US. The partnership agreement gives EBC the right of first refusal to construct additional Sorel-Tracy phases, as well as one or all of Charbone’s facilities within the North American market.
In addition, Charbone has entered into several other strategic partnerships, all aimed at expanding its footprint in North America. The company entered into a special consultancy agreement with Enki GéoSolutions for potential partnership proposals as a co-operator and distributor of an emerging form of clean and renewable hydrogen, known as white or natural hydrogen.
In June 2024, Carbone executed a supply agreement for a complete containerized electrolyzer system ready for shipment to its flagship green hydrogen site in the City of Sorel-Tracy, Quebec. The electrolyzer has a higher capacity than originally planned and will significantly enhance initial operational capacity estimates. The company also acquired its first tube trailer for the transport and bulk delivery of compressed green hydrogen produced from the City of Sorel-Tracy, Quebec flagship project to local and domestic customers.
Charbone signed commercial supply agreements (CSAs) with a top-tier US industrial gas producer and distributor. The first CSA secures hydrogen supply ahead of Charbone’s own production, while the second expands its product offerings to include helium and other industrial gases. Positioned to capitalize on emerging North American opportunities, particularly in Canada, Charbone leverages its early-mover advantage to build strategic partnerships and strengthen its role in the low-carbon, high-purity hydrogen market.
Superior Plus
This partnership allows Charbone to sell hydrogen produced at the Sorel-Tracy facility to Certarus, a subsidiary of Superior Plus. Such supply agreements ensure that Charbone can generate cash flow immediately following the commencement of production.
Charbone Hydrogen entered into an off-take partnership with Certarus on the supply and
distribution of green hydrogen.
NEK Community Broadband
Another such supply agreement was signed in November 2023 with NEK Community Broadband, which ensures the supply of green hydrogen in the Northeast Kingdom of the state of Vermont (USA). NEK Broadband is building a high-speed broadband infrastructure and plans to install a hydrogen fuel cell backup system for a reliable power supply.
Oakland County Economic Development Department, Michigan
Further advancing its goal of US expansion, Charbone signed a memorandum of understanding in December 2023 with Michigan’s Oakland County Economic Development Department to set up Charbone’s first green hydrogen facility in the United States. Oakland County is home to major automakers, and a green hydrogen facility in their proximity will support the effort of producing environmentally friendly mobility options.
Being the only publicly listed green hydrogen player in Canada, Charbone offers investors a unique opportunity to participate in the rise of green hydrogen as a potential low-emitting alternative to fossil fuels.
Management Team
Dave Gagnon – Chairman and CEO
Dave Gagnon has been chairman and chief executive officer of Charbone Hydrogen Corporation since April 21, 2022. With over 20 years of executive leadership experience in Cleantech, Wind Power, Hydropower, Lithium Resources, and Industrial Gases, he has built a career focused on scaling innovative infrastructure, accelerating sustainable energy solutions, and leading cross-border growth initiatives in high-impact sectors.
Benoit Veilleux – Chief Financial Officer
Benoit Veilleux was appointed as the CFO of Charbone on August 15, 2022. Veilleux has over 15 years of experience in corporate accounting and finance. He began his professional career at KPMG in 2003, where he managed and coordinated audit teams for public companies until 2010. Since then, he has worked with a number of companies including Air Liquide Canada and the Hypertec Group.
Daniell Charette – Chief Operating Officer
Daniell Charette has been the chief operating officer of Charbone since February 2019. He brings over 25 years of experience in running and managing renewable energy companies. He has worked in senior leadership roles with several renewable companies including NEG Micon A/S, Vestas and Brookfield Power. He has served on various association boards and councils, including the Canadian Wind Energy Association, Association Québécoise des Producteurs d’Énergie Renouvelable, and Latin Wind Energy Association.
Francois Vitez – Director
Francois Vitez is a hydropower and energy storage expert with more than 24 years of experience in development, engineering and construction management as well as operations and maintenance of hydropower and energy storage projects in North America and internationally. He is a board member and chair of the Value of Hydropower committee at Waterpower Canada, vice-chair of the Energy Storage Association of Canada, board member of the California Energy Storage Association, and member of the International Hydropower Association.
Patrick Cuddihy – Industrial Gases Operations Team
Patrick Cuddihy is a seasoned operations leader with over 20 years of experience at Air Liquide Canada, to its hydrogen operations team. Patrick brings a wealth of expertise in managing industrial gas production and distribution, having held senior roles including network sales director for Quebec Region, general manager for Pacific Region, director of procurement services, and director of logistics and assets for the Eastern Region.
Charbone Hydrogene annonce des debentures convertibles de remplacement de 2M$
(TheNewswire)
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Brossard (Québec), le 18 septembre 2025 - TheNewswire - CORPORATION CHARBONE HYDROGÈNE (TSXV: CH,OTC:CHHYF , OTCQB: CHHYF, FSE: K47 ) (« Charbone » ou la « Société »), une compagnie spécialisée dans la production et la distribution d'hydrogène vert, est heureuse d'annoncer la signature de débentures convertibles de remplacement d'un montant de 2 050 000 $ (l' « Débentures de remplacement » ) en modifiant certaines modalités des débentures convertibles garanties de la Société (chacune, une « Débenture ») que la Société avait émises dans le cadre du placement privé de débentures d'un montant en principal total de 1 746 366 $ de débentures convertibles garanties à 12 %.
Avant l'entrée en vigueur des débentures de remplacement le 30 septembre 2025, les débentures étaient convertibles en actions ordinaires de Charbone (chacune, une « Action de Débenture »), à un prix de conversion par action de 0.10$, jusqu'à l'échéance.
En vertu des nouvelles Débentures de remplacement :
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La date d'échéance a été prolongée des 30 septembre et 31 octobre 2025 au 30 septembre 2026 ;
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Le solde convertible, passe de 1,7 millions de dollars à 2,1 millions de dollars au même taux annuel de 12 %, payable mensuellement ; et
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Le prix de conversion des débentures passe de 0,10$ par action à 0,07$ par action
Les nouvelles Débentures de remplacement seront assujetties à l'approbation de la Bourse de croissance TSX.
" Ces changements annoncés aujourd'hui aux débentures existantes offrent une nouvelle flexibilité de financement à Charbone en prolongeant considérablement les échéances et nous fournissent un financement supplémentaire pour compléter et exécuter l'acquisition de l'équipement opérationnel de production et de ravitaillement en hydrogène, annoncée le 5 septembre 2025 , a déclaré Benoit Veilleux, Chef de la direction financière et secrétaire corporatif de Charbone. " À mesure que nous gagnons en élan, nous travaillons continuellement à optimiser notre structure de capital et à faire progresser nos avantages de pionnier ainsi que les intérêts de nos actionnaires . "
À propos de Charbone Hydrogène Corporation
Charbone est une entreprise intégrée spécialisée dans l'hydrogène ultrapur (UHP) et la distribution stratégique de gaz industriels en Amérique du Nord et en Asie-Pacifique. Elle développe un réseau modulaire de production d'hydrogène vert tout en s'associant à des partenaires de l'industrie pour offrir de l'hélium et d'autres gaz spécialisés sans avoir à construire de nouvelles usines coûteuses. Cette stratégie disciplinée diversifie les revenus, réduit les risques et augmente sa flexibilité. Le groupe Charbone est coté en bourse en Amérique du Nord et en Europe sur la bourse de croissance TSX (TSXV: CH,OTC:CHHYF); sur les marchés OTC (OTCQB: CHHYF); et à la Bourse de Francfort (FSE: K47). Pour plus d'informations, visiter www.charbone.com .
Énoncés prospectifs
Le présent communiqué de presse contient des énoncés qui constituent de « l'information prospective » au sens des lois canadiennes sur les valeurs mobilières (« déclarations prospectives »). Ces déclarations prospectives sont souvent identifiées par des mots tels que « a l'intention », « anticipe », « s'attend à », « croit », « planifie », « probable », ou des mots similaires. Les déclarations prospectives reflètent les attentes, estimations ou projections respectives de la direction de Charbone concernant les résultats ou événements futurs, sur la base des opinions, hypothèses et estimations considérées comme raisonnables par la direction à la date à laquelle les déclarations sont faites. Bien que Charbone estime que les attentes exprimées dans les déclarations prospectives sont raisonnables, les déclarations prospectives comportent des risques et des incertitudes, et il ne faut pas se fier indûment aux déclarations prospectives, car des facteurs inconnus ou imprévisibles pourraient faire en sorte que les résultats réels soient sensiblement différents de ceux exprimés dans les déclarations prospectives. Des risques et des incertitudes liés aux activités de Charbone peuvent avoir une incidence sur les déclarations prospectives. Ces risques, incertitudes et hypothèses comprennent, sans s'y limiter, ceux décrits à la rubrique « Facteurs de risque » dans la déclaration de changement à l'inscription de la Société datée du 31 mars 2022, qui peut être consultée sur SEDAR à l'adresse www.sedar.com; ils pourraient faire en sorte que les événements ou les résultats réels diffèrent sensiblement de ceux prévus dans les déclarations prospectives.
Sauf si les lois sur les valeurs mobilières applicables l'exigent, Charbone ne s'engage pas à mettre à jour ni à réviser les déclarations prospectives.
Ni la Bourse de croissance TSX ni son fournisseur de services de réglementation (tel que ce terme est défini dans les politiques de la Bourse de croissance TSX) n'acceptent de responsabilité quant à la pertinence ou à l'exactitude du présent communiqué.
Pour contacter Corporation Charbone Hydrogène :
| Téléphone bureau: +1 450 678 7171 | ||
| Courriel: ir@charbone.com Benoit Veilleux Chef de la direction financière et secrétaire corporatif |
Copyright (c) 2025 TheNewswire - All rights reserved.
News Provided by TheNewsWire via QuoteMedia
CHARBONE Hydrogen Announces $2M Convertible Debentures Replacement
(TheNewswire)
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Brossard, Quebec, September 18, 2025 TheNewswire Charbone Hydrogen Corporation (TSXV: CH,OTC:CHHYF; OTCQB: CHHYF; FSE: K47) (the "Company" or "CHARBONE ") a company focused on green hydrogen production and distribution is pleased to announce the signature of Replacement Debentures of an amount of $2,050,000 (the "Replacement Debenture" ) by amending certain terms of the secured convertible debentures of the Company (each, a "Debenture" ) that the Company issued in connection with the private placement of debentures of an aggregate principal amount of $1,746,366 of 12% secured convertible debentures.
Before the Replacement Debenture took effect as of September 30, 2025, the Debentures were convertible into common shares of CHARBONE (each, a "Debenture Share" ) at a conversion price of $0.10 per share until maturity.
Under the new Replacement Debenture:
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The maturity date has been extended from September 30 and October 31, 2025 to September 30, 2026;
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The convertible balance moves from $1.7 million to $2.1 million with the same annual rate of 12%, payable monthly, and
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The conversion price of the Debentures moves from $0.10 per Debenture Share to $0.07 per Debenture Share
The new Replacement Debenture will be subject to the approval of the TSX Venture Exchange.
" These changes announce today to the existing debentures is providing a new financing flexibility to Charbone by extending significantly the maturities and provide us with additional financing to complete and execute the acquisition of the operational hydrogen production and refueling equipment, announced on September 5, 2025, " said Benoit Veilleux, Chief Financial Officer and Corporate Secretary of CHARBONE . " As we gain momentum, we are continuously working towards optimizing our capital structure and advance our first-mover advantages as well as our shareholder interests ."
About Charbone Hydrogen CORPORATION
CHARBONE is an integrated company specialized in Ultra High Purity (UHP) hydrogen and the strategic distribution of industrial gases in North America and the Asia-Pacific region. It is developing a modular network of green hydrogen production while partnering with industry players to supply helium and other specialty gases without the need to build costly new plants. This disciplined strategy diversifies revenue streams, reduces risks, and increases flexibility. The CHARBONE group is publicly listed in North America and Europe on the TSX Venture Exchange (TSXV: CH,OTC:CHHYF), the OTC Markets (OTCQB: CHHYF), and the Frankfurt Stock Exchange (FSE: K47). For more information, visit www.charbone.com .
Forward-Looking Statements
This news release contains statements that are "forward-looking information" as defined under Canadian securities laws ("forward-looking statements"). These forward-looking statements are often identified by words such as "intends", "anticipates", "expects", "believes", "plans", "likely", or similar words. The forward-looking statements reflect management's expectations, estimates, or projections concerning future results or events, based on the opinions, assumptions and estimates considered reasonable by management at the date the statements are made. Although Charbone believes that the expectations reflected in the forward-looking statements are reasonable, forward-looking statements involve risks and uncertainties, and undue reliance should not be placed on forward-looking statements, as unknown or unpredictable factors could cause actual results to be materially different from those reflected in the forward-looking statements. The forward-looking statements may be affected by risks and uncertainties in the business of Charbone. These risks, uncertainties and assumptions include, but are not limited to, those described under "Risk Factors" in the Corporation's Filing Statement dated March 31, 2022, which is available on SEDAR at www.sedar.com; they could cause actual events or results to differ materially from those projected in any forward-looking statements.
Except as required under applicable securities legislation, Charbone undertakes no obligation to publicly update or revise forward-looking information.
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 .
| Contact Charbone Hydrogen Corporation | |
| Telephone: +1 450 678 7171 | |
| Email: ir@charbone.com Benoit Veilleux CFO and Corporate Secretary | |
Copyright (c) 2025 TheNewswire - All rights reserved.
News Provided by TheNewsWire via QuoteMedia
Alvopetro Announces Q3 2025 Dividend of US$0.10 Per Share
Alvopetro Energy Ltd. (TSXV: ALV,OTC:ALVOF) (OTCQX: ALVOF) announces that our Board of Directors has declared a quarterly dividend of US$0.10 per common share, payable in cash on October 15, 2025 to shareholders of record at the close of business on September 30, 2025 . This dividend is designated as an "eligible dividend" for Canadian income tax purposes.
Dividend payments to non-residents of Canada will be subject to withholding taxes at the Canadian statutory rate of 25%. Shareholders may be entitled to a reduced withholding tax rate under a tax treaty between their country of residence and Canada. For further information, see Alvopetro's website at https://alvopetro.com/Dividends-Non-resident-Shareholders .
Corporate Presentation
Alvopetro's updated corporate presentation is available on our website at:
http://www.alvopetro.com/corporate-presentation .
Social Media
Follow Alvopetro on our social media channels at the following links:
X - https://x.com/AlvopetroEnergy
Instagram - https://www.instagram.com/alvopetro/
LinkedIn - https://www.linkedin.com/company/alvopetro-energy-ltd
Alvopetro Energy Ltd. is deploying a balanced capital allocation model where we seek to reinvest roughly half our cash flows into organic growth opportunities and return the other half to stakeholders. Alvopetro's organic growth strategy is to focus on the best combinations of geologic prospectivity and fiscal regime. Alvopetro is balancing capital investment opportunities in Canada and Brazil where we are building off the strength of our Caburé and Murucututu natural gas fields and the related strategic midstream infrastructure.
Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this news release.
All amounts contained in this new release are in United States dollars, unless otherwise stated and all tabular amounts are in thousands of United States dollars, except as otherwise noted.
Forward-Looking Statements and Cautionary Language
This news release contains forward-looking information within the meaning of applicable securities laws. The use of any of the words "will", "expect", "intend", "plan", "may", "believe", "estimate", "forecast", "anticipate", "should" and other similar words or expressions are intended to identify forward-looking information. Forward‐looking statements involve significant risks and uncertainties, should not be read as guarantees of future performance or results, and will not necessarily be accurate indications of whether or not such results will be achieved. A number of factors could cause actual results to vary significantly from the expectations discussed in the forward-looking statements. These forward-looking statements reflect current assumptions and expectations regarding future events. Accordingly, when relying on forward-looking statements to make decisions, Alvopetro cautions readers not to place undue reliance on these statements, as forward-looking statements involve significant risks and uncertainties. More particularly and without limitation, this news release contains forward-looking information concerning the Company's dividends, plans for dividends in the future, the timing and amount of such dividends and the expected tax treatment thereof. Forward-looking statements are necessarily based upon assumptions and judgments with respect to the future including, but not limited to the success of future drilling, completion, testing, recompletion and development activities and the timing of such activities, the performance of producing wells and reservoirs, well development and operating performance, expectations and assumptions concerning the timing of regulatory licenses and approvals, equipment availability, environmental regulation, including regulations relating to hydraulic fracturing and stimulation, the ability to monetize hydrocarbons discovered, the outlook for commodity markets and ability to access capital markets, foreign exchange rates, the outcome of any disputes, the outcome of redeterminations, general economic and business conditions, forecasted demand for oil and natural gas, the impact of global pandemics, weather and access to drilling locations, the availability and cost of labour and services, and the regulatory and legal environment and other risks associated with oil and gas operations. The reader is cautioned that assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be incorrect. Actual results achieved during the forecast period will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Current and forecasted natural gas nominations are subject to change on a daily basis and such changes may be material. In addition, the declaration, timing, amount and payment of future dividends remain at the discretion of the Board of Directors. Although we believe that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because we can give no assurance that they will prove to be correct. Since forward looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, risks associated with the oil and gas industry in general (e.g., 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 reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses, reliance on industry partners, availability of equipment and personnel, uncertainty surrounding timing for drilling and completion activities resulting from weather and other factors, changes in applicable regulatory regimes and health, safety and environmental risks), commodity price and foreign exchange rate fluctuations, market uncertainty associated with trade or tariff disputes, and general economic conditions. The reader is cautioned that assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be incorrect. Although Alvopetro believes that the expectations and assumptions on which such forward-looking information is based are reasonable, undue reliance should not be placed on the forward-looking information because Alvopetro can give no assurance that it will prove to be correct. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on factors that could affect the operations or financial results of Alvopetro are included in our AIF which may be accessed on Alvopetro's SEDAR+ profile at www.sedarplus.ca . The forward-looking information contained in this news release is made as of the date hereof and Alvopetro undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.
SOURCE Alvopetro Energy Ltd.
View original content: http://www.newswire.ca/en/releases/archive/September2025/15/c3517.html
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