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.
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Coelacanth presents a compelling investment opportunity with its ownership of approximately 150 net sections in the Montney Formation in the Two Rivers oil and liquids rich natural gas region, boasting $64.4 million in working capital and a strategic position near major producers.
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. This company sets itself apart with its well-structured growth strategy, financial stability, and commitment to sustainability, making it one of the promising junior players in the region.
Coelacanth Energy has established a strong foundation to deliver on its future production targets by ensuring it is fully permitted and funded to embark on its infrastructure developments. 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. This financial cushion not only supports ongoing infrastructure projects but also provides the company with the flexibility to expand its operations.
Capital deployed for project development will be allocated towards constructing processing facilities, pipelines, and necessary gathering lines, which are all crucial components for transporting and processing oil and gas. With processing contracts secured for up to 60 million cubic feet per day (mmcf/d) and long-term gas takeaway agreements for 100 mmcf/d, Coelacanth is well-positioned to scale its production quickly and efficiently. The company aims to have its infrastructure fully operational by mid April 2025, ramping up cashflow, marking a significant milestone in its transition to a full-scale production company.
The Montney Formation is recognized as one of the most significant natural gas reserves in North America, covering large portions of British Columbia and Alberta. Known for its high levels of natural gas and natural gas liquids (NGLs), 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.
Coelacanth Energy Inc. has adopted a well-defined two-pronged strategy for growth, which focuses on both immediate production goals and long-term resource development. This approach provides a balanced focus on infrastructure development and resource delineation.
Coelacanth is focused on delineating its land base resources alongside infrastructure development. This involves drilling wells to explore and prove the extent of hydrocarbon deposits across multiple zones within the Montney Formation. By continuing to delineate its resources, the company aims to demonstrate the productivity and economic viability of its assets, which is critical for long-term growth. The delineation process also helps Coelacanth de-risk its projects, ensuring that future drilling activities are economically sound.
Compelling test results and initial reserves bookings
The Two Rivers East project is Coelacanth’s primary development focus. This area has shown significant potential for oil and gas production, with initial tests yielding compelling results. The proved and probable reserves (P+P) for Two Rivers East are estimated at 1,532 mboe per well, with approximately 30 percent of the reserves comprising oil and NGLs. Initial production tests from wells in the Lower Montney zone have confirmed the commerciality of this resource, with one well producing 1,345 barrels of oil equivalent per day at (boepd) at 61 percent oil, and three others producing an average of approximately 1,300 boepd at averaging 38 percent oil. These results underscore the viability of Two Rivers East as a key asset for Coelacanth’s future growth.
The Two Rivers West project also holds considerable proved and probable reserves of approximately 1,148 mboe, 34 percent of which consist of oil and NGLs. Similar to Two Rivers East, initial production tests have demonstrated strong deliverability. For example, the Upper Montney well in this region produced an average of 1,284 boepd during its test phase. These tests indicate that the Two Rivers West project will contribute significantly to Coelacanth’s production capabilities as it continues to expand its operations.
Coelacanth’s strategic location in the Montney, coupled with large contiguous landholdings and established infrastructure, positions the company for long-term growth. The company’s land position in the light oil window of Montney further enhances its value, as light oil typically commands a premium over heavier oil grades. Coelacanth is the number one landholder in this lucrative area, providing it with a significant competitive edge.
Moreover, Coelacanth’s management team has a proven track record, having successfully built and sold six oil and gas companies prior to founding Coelacanth. This experience adds credibility to the company’s long-term growth strategy, instilling confidence that Coelacanth can replicate its past successes in the Montney region.
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 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 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.
Natural gas exploration and production in the prolific Montney region in British Columbia
Coelacanth Energy Inc. (TSXV: CEI) ("Coelacanth" or the "Company") is pleased to announce its financial and operating results for the three months and year ended December 31, 2024. All dollar figures are Canadian dollars unless otherwise noted.
2024 HIGHLIGHTS
| FINANCIAL RESULTS | Three Months Ended | Year Ended | ||||||||||||||||
| December 31 | December 31 | |||||||||||||||||
| ($000s, except per share amounts) | 2024 | 2023 | % Change | 2024 | 2023 | % Change | ||||||||||||
| Oil and natural gas sales | 4,544 | 4,204 | 8 | 13,736 | 6,663 | 106 | ||||||||||||
| Cash flow from (used in) operating activities | 3,157 | (404 | ) | (881 | ) | 2,203 | (4,234 | ) | (152 | ) | ||||||||
| Per share - basic and diluted (1) | 0.01 | (-) | (100 | ) | - | (0.01 | ) | (100 | ) | |||||||||
| Adjusted funds flow (used) (1) | 382 | 1,750 | (78 | ) | 1,515 | (333 | ) | (555 | ) | |||||||||
| Per share - basic and diluted | - | - | - | - | (-) | (-) | ||||||||||||
| Net loss | (2,903 | ) | (750 | ) | 287 | (8,897 | ) | (6,573 | ) | 35 | ||||||||
| Per share - basic and diluted | (0.01 | ) | (-) | 100 | (0.02 | ) | (0.01 | ) | 100 | |||||||||
| Capital expenditures (1) | 64,952 | 34,656 | 87 | 84,497 | 74,613 | 13 | ||||||||||||
| Adjusted working capital (deficiency) (1) | (18,637 | ) | 67,589 | (128 | ) | |||||||||||||
| Common shares outstanding (000s) | ||||||||||||||||||
| Weighted average - basic and diluted | 530,398 | 478,731 | 11 | 529,804 | 439,055 | 21 | ||||||||||||
| End of period - basic | 530,670 | 528,650 | - | |||||||||||||||
| End of period - fully diluted | 615,930 | 609,989 | 1 | |||||||||||||||
(1) See "Non-GAAP and Other Financial Measures" section.
(2) See "Test Results and Initial Production Rates" section.
| Three Months Ended | Year Ended | |||||||||||||||||
| OPERATING RESULTS (1) | December 31 | December 31 | ||||||||||||||||
| 2024 | 2023 | % Change | 2024 | 2023 | % Change | |||||||||||||
| Daily production (2) | ||||||||||||||||||
| Oil and condensate (bbls/d) | 473 | 419 | 13 | 320 | 139 | 130 | ||||||||||||
| Other NGLs (bbls/d) | 29 | 28 | 4 | 34 | 16 | 113 | ||||||||||||
| Oil and NGLs (bbls/d) | 502 | 447 | 12 | 354 | 155 | 128 | ||||||||||||
| Natural gas (mcf/d) | 3,490 | 2,858 | 22 | 3,648 | 1,624 | 125 | ||||||||||||
| Oil equivalent (boe/d) | 1,084 | 923 | 17 | 962 | 426 | 126 | ||||||||||||
| Oil and natural gas sales | ||||||||||||||||||
| Oil and condensate ($/bbl) | 87.06 | 87.38 | (-) | 89.46 | 88.94 | 1 | ||||||||||||
| Other NGLs ($/bbl) | 33.28 | 32.32 | 3 | 33.22 | 33.22 | - | ||||||||||||
| Oil and NGLs ($/bbl) | 83.97 | 83.88 | - | 83.99 | 83.28 | 1 | ||||||||||||
| Natural gas ($/mcf) | 2.07 | 2.86 | (28 | ) | 2.14 | 3.26 | (34 | ) | ||||||||||
| Oil equivalent ($/boe) | 45.57 | 49.47 | (8 | ) | 39.01 | 42.82 | (9 | ) | ||||||||||
| Royalties | ||||||||||||||||||
| Oil and NGLs ($/bbl) | 16.86 | 19.38 | (13 | ) | 18.70 | 20.24 | (8 | ) | ||||||||||
| Natural gas ($/mcf) | 0.13 | 0.26 | (50 | ) | 0.21 | 0.57 | (63 | ) | ||||||||||
| Oil equivalent ($/boe) | 8.22 | 10.20 | (19 | ) | 7.66 | 9.57 | (20 | ) | ||||||||||
| Operating expenses | ||||||||||||||||||
| Oil and NGLs ($/bbl) | 8.34 | 11.57 | (28 | ) | 9.47 | 13.25 | (29 | ) | ||||||||||
| Natural gas ($/mcf) | 1.25 | 1.28 | (2 | ) | 1.58 | 2.21 | (29 | ) | ||||||||||
| Oil equivalent ($/boe) | 7.88 | 9.57 | (18 | ) | 9.47 | 13.25 | (29 | ) | ||||||||||
| Net transportation expenses (3) | ||||||||||||||||||
| Oil and NGLs ($/bbl) | 5.54 | 4.95 | 12 | 3.46 | 4.10 | (16 | ) | |||||||||||
| Natural gas ($/mcf) | 0.76 | 0.81 | (6 | ) | 0.73 | 1.12 | (35 | ) | ||||||||||
| Oil equivalent ($/boe) | 5.01 | 4.92 | 2 | 4.04 | 5.75 | (30 | ) | |||||||||||
| Operating netback (loss) (3) | ||||||||||||||||||
| Oil and NGLs ($/bbl) | 53.23 | 47.98 | 11 | 52.36 | 45.69 | 15 | ||||||||||||
| Natural gas ($/mcf) | (0.07 | ) | 0.51 | (114 | ) | (0.38 | ) | (0.64 | ) | (41 | ) | |||||||
| Oil equivalent ($/boe) | 24.46 | 24.78 | (1 | ) | 17.84 | 14.25 | 25 | |||||||||||
| Depletion and depreciation ($/boe) | (10.76 | ) | (12.18 | ) | (12 | ) | (13.59 | ) | (14.93 | ) | (9 | ) | ||||||
| General and administrative expenses ($/boe) | (15.46 | ) | (10.77 | ) | 44 | (14.34 | ) | (27.08 | ) | (47 | ) | |||||||
| Share based compensation ($/boe) | (7.08 | ) | (16.31 | ) | (57 | ) | (11.12 | ) | (23.49 | ) | (53 | ) | ||||||
| Loss on lease termination ($/boe) | (2.02 | ) | - | 100 | (0.57 | ) | - | 100 | ||||||||||
| Finance expense ($/boe) | (18.02 | ) | (1.28 | ) | 1,308 | (6.33 | ) | (3.09 | ) | 105 | ||||||||
| Finance income ($/boe) | 3.65 | 10.01 | (64 | ) | 8.23 | 18.75 | (56 | ) | ||||||||||
| Unutilized transportation ($/boe) | (3.88 | ) | (3.08 | ) | 26 | (5.37 | ) | (6.65 | ) | (19 | ) | |||||||
| Net loss ($/boe) | (29.11 | ) | (8.83 | ) | 230 | (25.25 | ) | (42.24 | ) | (40 | ) | |||||||
(1) See "Oil and Gas Terms" section.
(2) See "Product Types" section.
(3) See "Non-GAAP and Other Financial Measures" section.
Selected financial and operational information outlined in this news release should be read in conjunction with Coelacanth's audited financial statements and related Management's Discussion and Analysis ("MD&A") for the year ended December 31, 2024, which are available for review under the Company's profile on SEDAR+ at www.sedarplus.ca.
OPERATIONS UPDATE
In Q4 2024, Coelacanth achieved two more significant milestones in its vision of moving the Two Rivers Montney Project from a large Montney land block to a proven resource with decades of inventory.
In 2022 and 2023, Coelacanth was able to prove productivity in the Lower Montney over a significant portion of lands at Two Rivers that allowed for the decision to build-out infrastructure and to continue pad drilling at Two Rivers East. During 2024, Coelacanth completed the licensing phase of the infrastructure and started construction while also continuing to develop the Montney resource.
In Q4 2024, Coelacanth was able to substantially complete all pipelines required for its 5-19 pad that connected it from the pad to the future facility and then on to a midstream gathering system. Concurrently, Coelacanth completed a successful Upper Montney well at Two Rivers East and changed the completion design in the Lower Montney on the 5-19 pad. The Upper Montney completion proved significant productivity (previously announced test rate of 1,136 boe/d) (1) in a zone that can be mapped over a significant portion of Coelacanth's lands and should materially increase drilling inventory. The new Lower Montney completions yielded increased overall test rates as well as increasing the oil percentage (3-well average test rates previously announced at 1,624 boe/d with 61% light oil) (1) pointing to potentially higher per-well recoveries of oil and gas and corresponding per-well values than previously estimated.
Construction of the facility continued throughout Q1 2025 and is now substantially complete. With 9 wells and over 11,000 boe/d (1) of test production waiting on completion of the facility, we anticipate yet another major milestone will be reached imminently. We look forward to reporting updates on the Two Rivers East project as new developments arise.
(1) See "Test Results and Initial Production Rates" section for more details.
OIL AND GAS TERMS
The Company uses the following frequently recurring oil and gas industry terms in the news release:
| Liquids | |
| Bbls | Barrels |
| Bbls/d | Barrels per day |
| NGLs | Natural gas liquids (includes condensate, pentane, butane, propane, and ethane) |
| Condensat | Pentane and heavier hydrocarbons |
| Natural Gas | |
| Mcf | Thousands of cubic feet |
| Mcf/d | Thousands of cubic feet per day |
| MMcf/d | Millions of cubic feet per day |
| MMbtu | Million of British thermal units |
| MMbtu/d | Million of British thermal units per day |
| Oil Equivalent | |
| Boe | Barrels of oil equivalent |
| Boe/d | Barrels of oil equivalent per day |
Disclosure provided herein in respect of a boe may be misleading, particularly if used in isolation. A boe conversion rate of six thousand cubic feet of natural gas to one barrel of oil equivalent has been used for the calculation of boe amounts in the news release. This boe conversion rate is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
NON-GAAP AND OTHER FINANCIAL MEASURES
This news release refers to certain measures that are not determined in accordance with IFRS (or "GAAP"). These non-GAAP and other financial measures do not have any standardized meaning prescribed under IFRS and therefore may not be comparable to similar measures presented by other entities. The non-GAAP and other financial measures should not be considered alternatives to, or more meaningful than, financial measures that are determined in accordance with IFRS as indicators of the Company's performance. Management believes that the presentation of these non-GAAP and other financial measures provides useful information to shareholders and investors in understanding and evaluating the Company's ongoing operating performance, and the measures provide increased transparency to better analyze the Company's performance against prior periods on a comparable basis.
Non-GAAP Financial Measures
Adjusted funds flow (used)
Management uses adjusted funds flow (used) to analyze performance and considers it a key measure as it demonstrates the Company's ability to generate the cash necessary to fund future capital investments and abandonment obligations and to repay debt, if any. Adjusted funds flow (used) is a non-GAAP financial measure and has been defined by the Company as cash flow from (used in) operating activities excluding the change in non-cash working capital related to operating activities, movements in restricted cash deposits and expenditures on decommissioning obligations. Management believes the timing of collection, payment or incurrence of these items involves a high degree of discretion and as such may not be useful for evaluating the Company's cash flows. Adjusted funds flow (used) is reconciled from cash flow from (used) in operating activities as follows:
| Three Months Ended | Year Ended | |||||||||||
| December 31 | December 31 | |||||||||||
| ($000s) | 2024 | 2023 | 2024 | 2023 | ||||||||
| Cash flow from (used in) operating activities | 3,157 | (404 | ) | 2,203 | (4,234 | ) | ||||||
| Add (deduct): | ||||||||||||
| Decommissioning expenditures | 161 | 206 | 1,427 | 1,883 | ||||||||
| Change in restricted cash deposits | (5,361 | ) | - | (2,376 | ) | (784 | ) | |||||
| Change in non-cash working capital | 2,425 | 1,948 | 261 | 2,802 | ||||||||
| Adjusted funds flow (used) (non-GAAP) | 382 | 1,750 | 1,515 | (333 | ) | |||||||
Net transportation expenses
Management considers net transportation expenses an important measure as it demonstrates the cost of utilized transportation related to the Company's production. Net transportation expenses is calculated as transportation expenses less unutilized transportation and is calculated as follows:
| Three Months Ended | Year Ended | |||||||||||
| December 31 | December 31 | |||||||||||
| ($000s) | 2024 | 2023 | 2024 | 2023 | ||||||||
| Transportation expenses | 887 | 680 | 3,313 | 1,930 | ||||||||
| Unutilized transportation | (387 | ) | (262 | ) | (1,891 | ) | (1,035 | ) | ||||
| Net transportation expenses (non-GAAP) | 500 | 418 | 1,422 | 895 | ||||||||
Operating netback
Management considers operating netback an important measure as it demonstrates its profitability relative to current commodity prices. Operating netback is calculated as oil and natural gas sales less royalties, operating expenses, and net transportation expenses and is calculated as follows:
| Three Months Ended | Year Ended | |||||||||||
| December 31 | December 31 | |||||||||||
| ($000s) | 2024 | 2023 | 2024 | 2023 | ||||||||
| Oil and natural gas sales | 4,544 | 4,204 | 13,736 | 6,663 | ||||||||
| Royalties | (820 | ) | (866 | ) | (2,698 | ) | (1,489 | ) | ||||
| Operating expenses | (786 | ) | (813 | ) | (3,335 | ) | (2,062 | ) | ||||
| Net transportation expenses | (500 | ) | (418 | ) | (1,422 | ) | (895 | ) | ||||
| Operating netback (non-GAAP) | 2,438 | 2,107 | 6,281 | 2,217 | ||||||||
Capital expenditures
Coelacanth utilizes capital expenditures as a measure of capital investment on property, plant, and equipment, exploration and evaluation assets and property acquisitions compared to its annual budgeted capital expenditures. Capital expenditures are calculated as follows:
| Three Months Ended | Year Ended | |||||||||||
| December 31 | December 31 | |||||||||||
| ($000s) | 2024 | 2023 | 2024 | 2023 | ||||||||
| Capital expenditures – property, plant, and equipment | 233 | 4,584 | 1,206 | 26,928 | ||||||||
| Capital expenditures – exploration and evaluation assets | 64,719 | 30,072 | 83,291 | 47,685 | ||||||||
| Capital expenditures (non-GAAP) | 64,952 | 34,656 | 84,497 | 74,613 | ||||||||
Capital Management Measures
Adjusted working capital (deficiency)
Management uses adjusted working capital (deficiency) as a measure to assess the Company's financial position. Adjusted working capital is calculated as current assets and restricted cash deposits less current liabilities, excluding the current portion of decommissioning obligations.
| ($000s) | December 31, 2024 | December 31, 2023 | ||||
| Current assets | 11,579 | 87,616 | ||||
| Less: | ||||||
| Current liabilities | (37,234 | ) | (28,754 | ) | ||
| Working capital (deficiency) | (25,655 | ) | 58,862 | |||
| Add: | ||||||
| Restricted cash deposits | 4,900 | 6,784 | ||||
| Current portion of decommissioning obligations | 2,118 | 1,943 | ||||
| Adjusted working capital (deficiency) (Capital management measure) | (18,637 | ) | 67,589 |
Non-GAAP Financial Ratios
Adjusted Funds Flow (Used) per share
Adjusted funds flow (used) per share is a non-GAAP financial ratio, calculated using adjusted funds flow (used) and the same weighted average basic and diluted shares used in calculating net loss per share.
Net transportation expenses per boe
The Company utilizes net transportation expenses per boe to assess the per unit cost of utilized transportation related to the Company's production. Net transportation expenses per boe is calculated as net transportation expenses divided by total production for the applicable period.
Operating netback per boe
The Company utilizes operating netback per boe to assess the operating performance of its petroleum and natural gas assets on a per unit of production basis. Operating netback per boe is calculated as operating netback divided by total production for the applicable period.
Supplementary Financial Measures
The supplementary financial measures used in this news release (primarily average sales price per product type and certain per boe and per share figures) are either a per unit disclosure of a corresponding GAAP measure, or a component of a corresponding GAAP measure, presented in the financial statements. Supplementary financial measures that are disclosed on a per unit basis are calculated by dividing the aggregate GAAP measure (or component thereof) by the applicable unit for the period. Supplementary financial measures that are disclosed on a component basis of a corresponding GAAP measure are a granular representation of a financial statement line item and are determined in accordance with GAAP.
PRODUCT TYPES
The Company uses the following references to sales volumes in the news release:
Natural gas refers to shale gas.
Oil and condensate refers to condensate and tight oil combined.
Other NGLs refers to butane, propane and ethane combined.
Oil and NGLs refers to tight oil and NGLs combined.
Oil equivalent refers to the total oil equivalent of shale gas, tight oil, and NGLs combined, using the conversion rate of six thousand cubic feet of shale gas to one barrel of oil equivalent as described above.
The following is a complete breakdown of sales volumes for applicable periods by specific product types of shale gas, tight oil, and NGLs:
| Three Months Ended | Year Ended | |||||||||||
| December 31 | December 31 | |||||||||||
| Sales Volumes by Product Type | 2024 | 2023 | 2024 | 2023 | ||||||||
| Condensate (bbls/d) | 22 | 12 | 32 | 7 | ||||||||
| Other NGLs (bbls/d) | 29 | 28 | 35 | 16 | ||||||||
| NGLs (bbls/d) | 51 | 40 | 67 | 23 | ||||||||
| Tight oil (bbls/d) | 451 | 407 | 287 | 132 | ||||||||
| Condensate (bbls/d) | 22 | 12 | 32 | 7 | ||||||||
| Oil and condensate (bbls/d) | 473 | 419 | 319 | 139 | ||||||||
| Other NGLs (bbls/d) | 29 | 28 | 35 | 16 | ||||||||
| Oil and NGLs (bbls/d) | 502 | 447 | 354 | 155 | ||||||||
| Shale gas (mcf/d) | 3,490 | 2,858 | 3,648 | 1,624 | ||||||||
| Natural gas (mcf/d) | 3,490 | 2,858 | 3,648 | 1,624 | ||||||||
| Oil equivalent (boe/d) | 1,084 | 923 | 962 | 426 | ||||||||
TEST RESULTS AND INITIAL PRODUCTION RATES
The 5-19 Lower Montney well was production tested for 9.4 days and produced at an average rate of 377 bbl/d oil and 2,202 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.
The A5-19 Basal Montney well was production tested for 5.9 days and produced at an average rate of 117 bbl/d oil and 630 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.
The B5-19 Upper Montney well was production tested for 6.3 days and produced at an average rate of 92 bbl/d oil and 2,100 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.
The C5-19 Lower Montney well was production tested for 5.8 days and produced at an average rate of 736 bbl/d oil and 2,660 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.
The D5-19 Lower Montney well was production tested for 12.6 days and produced at an average rate of 170 bbl/d oil and 580 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.
The E5-19 Lower Montney well was production tested for 11.4 days and produced at an average rate of 312 bbl/d oil and 890 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure was stable, and production was starting to decline.
The F5-19 Lower Montney well was production tested for 4.9 days and produced at an average rate of 728 bbl/d oil and 1,607 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.
The G5-19 Lower Montney well was production tested for 7.1 days and produced at an average rate of 415 bbl/d oil and 1,489 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.
The H5-19 Lower Montney well was production tested for 8.1 days and produced at an average rate of 411 bbl/d oil and 1,166 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure was stable and production was starting to decline.
A pressure transient analysis or well-test interpretation has not been carried out on these nine wells and thus certain of the test results provided herein should be considered to be preliminary until such analysis or interpretation has been completed. Test results and initial production rates disclosed herein, particularly those short in duration, may not necessarily be indicative of long-term performance or of ultimate recovery.
Any references to peak rates, test rates, IP30, IP90, IP180 or initial production rates or declines are useful for confirming the presence of hydrocarbons, however, such rates and declines are not determinative of the rates at which such wells will continue production and decline thereafter and are not indicative of long-term performance or ultimate recovery. IP30 is defined as an average production rate over 30 consecutive days, IP90 is defined as an average production rate over 90 consecutive days and IP180 is defined as an average production rate over 180 consecutive days. Readers are cautioned not to place reliance on such rates in calculating aggregate production for the Company.
FORWARD-LOOKING INFORMATION
This document contains forward-looking statements and forward-looking information within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", "may", "will", "should", "believe", "intends", "forecast", "plans", "guidance" and similar expressions are intended to identify forward-looking statements or information.
More particularly and without limitation, this news release contains forward-looking statements and information relating to the Company's oil and condensate, other NGLs, and natural gas production, capital programs, and adjusted working capital (deficiency). The forward-looking statements and information are based on certain key expectations and assumptions made by the Company, including expectations and assumptions relating to prevailing commodity prices and exchange rates, applicable royalty rates and tax laws, future well production rates, the performance of existing wells, the success of drilling new wells, the availability of capital to undertake planned activities, and the availability and cost of labour and services.
Although the Company believes that the expectations reflected in such forward-looking statements and information are reasonable, it can give no assurance that such expectations will prove to be correct. Since forward-looking statements and information address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results may differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, the risks associated with the oil and gas industry in general such as operational risks in development, exploration and production, delays or changes in plans with respect to exploration or development projects or capital expenditures, the uncertainty of estimates and projections relating to production rates, costs, and expenses, commodity price and exchange rate fluctuations, marketing and transportation, environmental risks, competition, the ability to access sufficient capital from internal and external sources and changes in tax, royalty, and environmental legislation. The forward-looking statements and information contained in this document are made as of the date hereof for the purpose of providing the readers with the Company's expectations for the coming year. The forward-looking statements and information may not be appropriate for other purposes. The Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.
Coelacanth is an oil and natural gas company, actively engaged in the acquisition, development, exploration, and production of oil and natural gas reserves in northeastern British Columbia, Canada.
Further Information
For additional information, please contact:
Coelacanth Energy Inc.
Suite 2110, 530 - 8th Avenue SW
Calgary, Alberta T2P 3S8
Phone: (403) 705-4525
www.coelacanth.ca
Mr. Robert J. Zakresky
President and Chief Executive Officer
Mr. Nolan Chicoine
Vice President, Finance and Chief Financial Officer
Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.
To view the source version of this press release, please visit https://www.newsfilecorp.com/release/249584
News Provided by Newsfile via QuoteMedia
Coelacanth Energy Inc. (TSXV: CEI) ("Coelacanth" or the "Company") is pleased to announce its 2024 year-end reserves as independently evaluated by GLJ Ltd. ("GLJ") effective December 31, 2024 (the "GLJ Report" or the "Report"), in accordance with National Instrument 51-101 ("NI 51-101") and the Canadian Oil and Gas Evaluation ("COGE") Handbook. All dollar figures are Canadian dollars unless otherwise noted.
Introduction
During 2024, Coelacanth drilled an additional 3 Lower Montney wells on its 5-19 pad and started the construction of pipelines and facilities to allow for the production of all 9 wells on the 5-19 pad to come on production in Q2 2025. The 9 wells consist of 7 Lower Montney wells, 1 Upper Montney well and 1 Basal Montney well that have tested over 11,000 boe/d (flush production) (1). On completion of phase 1 of the facility in May 2025, Coelacanth will have capacity to produce 30.0 mmcf/d of gas plus the concurrent oil production for a combined capacity of approximately 7,500-8,000 boe/d. Phase 2 (adding compression) is scheduled for Q4 2025 and will double capacity.
Coelacanth almost doubled its reserves from 2023 while still only having recognized reserves on less than 10% of its 150 section Montney land block at Two Rivers. A total of 23 combined wells and locations are included in the Report comprised of 13 drilled and completed Montney wells plus 10 Montney undeveloped locations. The 13 existing wells include 8 Lower Montney wells, 4 Upper Montney wells, and 1 Basal Montney well. All 10 undeveloped locations booked were Lower Montney leaving potential to book additional Upper and Basal Montney wells on the same lands. Coelacanth believes it has been conservative in its bookings and, over time, will be able to expand the current reserve base to cover a greater portion of the land base.
The Report includes a total of $148.3 million of future development capital ("FDC") of which $33.5 million is in Jan-May of 2025 for phase 1 of the facility. By the end of May, the capital for phase 1 of the facility will have been spent and all of the proved developed non-producing and probable developed non-producing reserves will change to producing status. These adjustments will have a material effect on the Report given the FDC for phase 1 of the facility will be removed (thereby increasing the overall value) and the producing portion of the Report will increase dramatically with wells coming on production. Coelacanth is planning to engage GLJ to provide a mid-year update of the Report to better illustrate the magnitude of the changes.
Coelacanth's business plan for the Two Rivers Montney Project includes:
Coelacanth is currently:
Coelacanth is excited to initiate its business plan to systematically develop the property, establish the ultimate reserve recoveries and move the established recoverable resource from land to its established producing reserve base.
Reserve Highlights
Coelacanth is pleased to report material increases in both reserves and value:
Notes:
(1) See "Test Results and Initial Production Rates".
Reserves Summary
Coelacanth's December 31, 2024 reserves as prepared by GLJ effective December 31, 2024 and based on the GLJ (2025-01) future price forecast are as follows: (1,4)
| Working Interest Reserves (2) | Tight Oil (Mbbl) | Shale Natural Gas (Mmcf) | NGLs (Mbbl) | Total Oil Equivalent (Mboe) (3) |
| Proved | ||||
| Producing | 344 | 8,097 | 150 | 1,843 |
| Developed non-producing | 1,874 | 38,862 | 720 | 9,071 |
| Undeveloped | 1,137 | 27,324 | 506 | 6,197 |
| Total proved | 3,355 | 74,283 | 1,376 | 17,111 |
| Probable | 2,154 | 44,543 | 825 | 10,403 |
| Total proved & probable | 5,509 | 118,826 | 2,201 | 27,515 |
Notes:
(1) Numbers may not add due to rounding.
(2) "Working Interest" or "Gross" reserves means Coelacanth's working interest (operating and non-operating) share before deduction of royalties and without including any royalty interest of Coelacanth.
(3) Oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil.
(4) Disclosure of Net reserves are included in Company's Annual Information Form ("AIF") dated April 23, 2025 filed on SEDAR+ at www.sedarplus.ca. "Net" reserves means Coelacanth's working interest (operated and non-operated) share after deduction of royalties, plus Coelacanth's royalty interest in reserves.
Reserves Values
The estimated future net revenues before taxes associated with Coelacanth's reserves effective December 31, 2024 and based on the GLJ (2025-01) future price forecast are summarized in the following table: (1,2,3,4)
| Discount factor per year | |||||
| ($000s) | 0% | 5% | 10% | 15% | 20% |
| Proved | |||||
| Producing | 21,615 | 17,655 | 14,827 | 12,765 | 11,220 |
| Developed non-producing | 131,346 | 97,179 | 74,105 | 57,825 | 45,878 |
| Undeveloped | 93,068 | 63,389 | 44,903 | 32,689 | 24,196 |
| Total proved | 246,030 | 178,224 | 133,834 | 103,279 | 81,294 |
| Probable | 221,362 | 147,285 | 105,806 | 80,431 | 63,701 |
| Total proved & probable | 467,391 | 325,509 | 239,640 | 183,710 | 144,995 |
Notes:
(1) Numbers may not add due to rounding.
(2) The estimated future net revenues are stated prior to provision for interest, debt service charges or general administrative expenses and after deduction of royalties, operating costs, estimated well abandonment and reclamation costs and estimated future capital expenditures.
(3) The estimated future net revenue contained in the table does not necessarily represent the fair market value of the reserves. There is no assurance that the forecast price and cost assumptions contained in the GLJ Report will be attained and variations could be material. The recovery and reserve estimates described herein are estimates only. Actual reserves may be greater or less than those calculated.
(4) The after-tax present values of future net revenue attributed to Coelacanth's reserves are included in Company's AIF dated April 23, 2025 filed on SEDAR+ at www.sedarplus.ca.
Price Forecast
The GLJ (2025-01) price forecast is as follows:
| Year | WTI Oil @ Cushing ($US / Bbl) | Edmonton Light Oil ($Cdn / Bbl) | AECO Natural Gas ($Cdn / Mmbtu) | Chicago Natural Gas ($US / Mmbtu) | Foreign Exchange (Cdn$/US$) |
| 2025 | 71.25 | 91.33 | 2.05 | 2.79 | 0.7050 |
| 2026 | 73.50 | 93.32 | 3.00 | 3.70 | 0.7300 |
| 2027 | 76.00 | 96.45 | 3.50 | 4.01 | 0.7500 |
| 2028 | 78.53 | 99.82 | 4.00 | 4.10 | 0.7500 |
| 2029 | 80.10 | 101.80 | 4.08 | 4.18 | 0.7500 |
| 2030 | 81.70 | 103.84 | 4.16 | 4.27 | 0.7500 |
| 2031 | 83.34 | 105.92 | 4.24 | 4.35 | 0.7500 |
| 2032 | 85.00 | 108.04 | 4.33 | 4.45 | 0.7500 |
| 2033 | 86.70 | 110.20 | 4.41 | 4.54 | 0.7500 |
| 2034 | 88.44 | 112.40 | 4.50 | 4.63 | 0.7500 |
| Escalate thereafter (1) | 2.0% per year | 2.0% per year | 2.0% per year | 2.0% per year |
Note:
(1) Escalated at two per cent per year starting in 2034 in the January 1, 2025 GLJ price forecast with the exception of foreign exchange, which remains flat.
Reserve Life Index ("RLI")
Coelacanth's RLI presented below is based on estimated Q4 2024 average production of 1,084 boe per day.
| Reserve Category | RLI |
| Proved plus Probable Reserves | 69.0 |
| Proved Reserves | 42.9 |
Reserves Reconciliation
The following summary reconciliation of Coelacanth's working interest reserves compares changes in the Company's reserves as at December 31, 2024 to the reserves as at December 31, 2023 based on the GLJ (2025-01) future price forecast: (1,2)
| Total Proved | Tight Oil | Shale Natural Gas | NGLs | Total Oil Equivalent |
| (Mbbl) | (Mmcf) | (Mbbl) | (Mboe) (3) | |
| Opening balance | 2,291 | 44,784 | 720 | 10,475 |
| Discoveries | - | - | - | - |
| Extensions and improved recovery | 1,212 | 27,468 | 509 | 6,298 |
| Technical revisions | (28) | 3,663 | 173 | 756 |
| Acquisitions | - | - | - | - |
| Dispositions | - | - | - | - |
| Economic factors | (15) | (297) | (1) | (66) |
| Production | (105) | (1,335) | (24) | (352) |
| Closing balance | 3,355 | 74,283 | 1,376 | 17,111 |
| Proved plus Probable | Tight Oil | Shale Natural Gas | NGLs | Total Oil Equivalent |
| (Mbbl) | (Mmcf) | (Mbbl) | (Mboe) (3) | |
| Opening balance | 3,038 | 60,432 | 970 | 14,080 |
| Discoveries | - | - | - | - |
| Extensions and improved recovery | 2,599 | 56,330 | 1,043 | 13,031 |
| Technical revisions | (9) | 3,734 | 213 | 825 |
| Acquisitions | - | - | - | - |
| Dispositions | - | - | - | - |
| Economic factors | (13) | (334) | - | (69) |
| Production | (105) | (1,335) | (24) | (352) |
| Closing balance | 5,509 | 118,826 | 2,201 | 27,515 |
Notes:
(1) Numbers may not add due to rounding.
(2) "Working Interest" or "Gross" reserves means Coelacanth's working interest (operating and non-operating) share before deduction of royalties and without including any royalty interest of Coelacanth.
(3) Oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil.
Capital Expenditures
Capital allocation by category is as follows:
| ($000s) | 2024 | 2023 | 2022 |
| Undeveloped land | 765 | 1,006 | 1,164 |
| Acquisitions | 765 | 1,006 | 1,164 |
| Drilling and completion | 38,353 | 61,274 | 9,009 |
| Facilities and related infrastructure | 44,935 | 12,094 | 3,689 |
| Geological, geophysical and other | 444 | 239 | 42 |
| Exploration and development expenditures | 83,732 | 73,607 | 12,740 |
| Total capital expenditures | 84,497 | 74,613 | 13,904 |
Finding and Development Costs ("F&D") and Finding, Development and Acquisition Costs ("FD&A")
Coelacanth has presented FD&A and F&D costs below:
| 2024 | 2023 | 2022 | 3 Year Cumulative | |||||
| Proved & | Proved & | Proved & | Proved & | |||||
| ($000's, except where noted) | Proved | Probable | Proved | Probable | Proved | Probable | Proved | Probable |
| Exploration and development expenditures | 83,732 | 83,732 | 73,607 | 73,607 | 12,740 | 12,740 | 170,079 | 170,079 |
| Change in FDC (1) | (1,713) | 30,469 | 90,598 | 77,759 | 11,400 | 33,748 | 100,285 | 141,976 |
| F&D costs | 82,019 | 114,201 | 164,205 | 151,366 | 24,140 | 46,488 | 270,364 | 312,055 |
| Acquisitions | 765 | 765 | 1,006 | 1,006 | 1,164 | 1,164 | 2,935 | 2,935 |
| FD&A costs | 82,784 | 114,966 | 165,211 | 152,372 | 25,304 | 47,652 | 273,299 | 314,990 |
| Reserve Additions (Mboe) (2) | ||||||||
| Exploration and development | 6,989 | 13,789 | 8,637 | 9,784 | 1,169 | 3,400 | 16,795 | 26,973 |
| Acquisitions | - | - | - | - | - | - | - | - |
| 6,989 | 13,789 | 8,637 | 9,784 | 1,169 | 3,400 | 16,795 | 26,973 | |
| F&D costs ($/boe) | 11.74 | 8.28 | 19.01 | 15.47 | 20.65 | 13.67 | 16.10 | 11.57 |
| FD&A costs ($/boe) | 11.84 | 8.34 | 19.13 | 15.57 | 21.65 | 14.02 | 16.27 | 11.68 |
Notes:
(1) Future development capital ("FDC") expenditures required to recover reserves estimated by GLJ. The aggregate of the exploration and development costs incurred in the most recent financial period and the change during that period in estimated future development costs generally may not reflect total finding and development costs related to reserve additions for that period.
(2) Sum of extensions and improved recovery, technical revisions and economic factors in the reserves reconciliation included above.
For Coelacanth's full NI 51-101 disclosure related to its 2024 year-end reserves please refer to the Company's AIF dated April 23, 2025 filed on SEDAR+ at www.sedarplus.ca.
Forward-Looking Information
This news release contains forward-looking statements and forward-looking information within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", "may", "will", "should", "believe", "intends", "forecast", "plans", "guidance" and similar expressions are intended to identify forward-looking statements or information.
More particularly and without limitation, this document contains forward-looking statements and information relating to the Company's oil, NGLs and natural gas production and reserves and reserves values, capital programs, and oil, NGLs, and natural gas commodity prices. The forward-looking statements and information are based on certain key expectations and assumptions made by the Company, including expectations and assumptions relating to prevailing commodity prices and exchange rates, applicable royalty rates and tax laws, future well production rates, the performance of existing wells, the success of drilling new wells, the availability of capital to undertake planned activities and the availability and cost of labor and services.
Although the Company believes that the expectations reflected in such forward-looking statements and information are reasonable, it can give no assurance that such expectations will prove to be correct. Since forward-looking statements and information address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results may differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, the risks associated with the oil and gas industry in general such as operational risks in development, exploration and production, delays or changes in plans with respect to exploration or development projects or capital expenditures, the uncertainty of estimates and projections relating to production rates, costs and expenses, commodity price and exchange rate fluctuations, marketing and transportation, environmental risks, competition, the ability to access sufficient capital from internal and external sources and changes in tax, royalty and environmental legislation. The forward-looking statements and information contained in this document are made as of the date hereof for the purpose of providing the readers with the Company's expectations for the coming year. The forward-looking statements and information may not be appropriate for other purposes. The Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.
Reserves Data
There are numerous uncertainties inherent in estimating quantities of tight oil, shale gas, and NGLs reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth above are estimates only. In general, estimates of economically recoverable tight oil, shale gas, and NGLs reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially.
Individual properties may not reflect the same confidence level as estimates of reserves for all properties due to the effects of aggregation.
This news release contains estimates of the net present value of the Company's future net revenue from its reserves. Such amounts do not represent the fair market value of the Company's reserves.
The reserves data contained in this news release has been prepared in accordance with National Instrument 51-101 ("NI 51-101"). The reserve data provided in this news release presents only a portion of the disclosure required under NI 51-101. All of the required information will be contained in the Company's Annual Information Form for the year ended December 31, 2024, filed on SEDAR+ at www.sedarplus.ca.
Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical and engineering data; the use of established technology, and specified economic conditions, which are generally accepted as being reasonable. Reserves are classified according to the degree of certainty associated with the estimates as follows:
Proved Reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
Probable Reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.
Industry Metrics
This news release contains metrics commonly used in the oil and natural gas industry. Each of these metrics is determined by the Company as set out below or elsewhere in this news release. These metrics are "F&D costs", "FD&A costs", and "reserve-life index". These metrics do not have standardized meanings and may not be comparable to similar measures presented by other companies. As such, they should not be used to make comparisons.
Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare the Company's performance over time, however, such measures are not reliable indicators of the Company's future performance and future performance may not compare to the performance in previous periods.
"F&D costs" are calculated by dividing the sum of the total capital expenditures for the year (in dollars) by the change in reserves within the applicable reserves category (in boe). F&D costs, including FDC, includes all capital expenditures in the year as well as the change in FDC required to bring the reserves within the specified reserves category on production.
"FD&A costs" are calculated by dividing the sum of the total capital expenditures for the year inclusive of the net acquisition costs and disposition proceeds (in dollars) by the change in reserves within the applicable reserves category inclusive of changes due to acquisitions and dispositions (in boe). FD&A costs, including FDC, includes all capital expenditures in the year inclusive of the net acquisition costs and disposition proceeds as well as the change in FDC required to bring the reserves within the specified reserves category on production.
The Company uses F&D and FD&A as a measure of the efficiency of its overall capital program including the effect of acquisitions and dispositions. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.
"Reserve life index" or "RLI" is calculated by dividing the reserves (in boe) in the referenced category by the latest quarter of production (in boe) annualized. The Company uses this measure to determine how long the booked reserves will last at current production rates if no further reserves were added.
BOE Conversions
BOE's may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf: 1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
Abbreviations
| Bbl | barrel |
| Mbbl | thousands of barrels |
| MMbtu | millions of British thermal units |
| Mcf | thousand cubic feet |
| MMcf | million cubic feet |
| NGLs | natural gas liquids |
| BOE | barrel of oil equivalent |
| MBOE | thousands of barrels of oil equivalent |
| WTI | West Texas Intermediate at Cushing, Oklahoma |
Test Results and Initial Production Rates
The 5-19 Lower Montney well was production tested for 9.4 days and produced at an average rate of 377 bbl/d oil and 2,202 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.
The A5-19 Basal Montney well was production tested for 5.9 days and produced at an average rate of 117 bbl/d oil and 630 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.
The B5-19 Upper Montney well was production tested for 6.3 days and produced at an average rate of 92 bbl/d oil and 2,100 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.
The C5-19 Lower Montney well was production tested for 5.8 days and produced at an average rate of 736 bbl/d oil and 2,660 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.
The D5-19 Lower Montney well was production tested for 12.6 days and produced at an average rate of 170 bbl/d oil and 580 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.
The E5-19 Lower Montney well was production tested for 11.4 days and produced at an average rate of 312 bbl/d oil and 890 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure was stable, and production was starting to decline.
The F5-19 Lower Montney well was production tested for 4.9 days and produced at an average rate of 728 bbl/d oil and 1,607 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.
The G5-19 Lower Montney well was production tested for 7.1 days and produced at an average rate of 415 bbl/d oil and 1,489 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.
The H5-19 Lower Montney well was production tested for 8.1 days and produced at an average rate of 411 bbl/d oil and 1,166 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure was stable and production was starting to decline.
A pressure transient analysis or well-test interpretation has not been carried out on these nine wells and thus certain of the test results provided herein should be considered to be preliminary until such analysis or interpretation has been completed. Test results and initial production rates disclosed herein, particularly those short in duration, may not necessarily be indicative of long-term performance or of ultimate recovery.
Any references to peak rates, test rates, IP30, IP90, IP180 or initial production rates or declines are useful for confirming the presence of hydrocarbons, however, such rates and declines are not determinative of the rates at which such wells will continue production and decline thereafter and are not indicative of long-term performance or ultimate recovery. IP30 is defined as an average production rate over 30 consecutive days, IP90 is defined as an average production rate over 90 consecutive days and IP180 is defined as an average production rate over 180 consecutive days. Readers are cautioned not to place reliance on such rates in calculating aggregate production for the Company.
For further information, please contact:
Coelacanth Energy Inc.
2110, 530 - 8th Ave SW
Calgary, Alberta T2P 3S8
Phone: (403) 705-4525
www.coelacanth.ca
Robert Zakresky
President and Chief Executive Officer
Nolan Chicoine
Vice President, Finance and Chief Financial Officer
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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Coelacanth Energy Inc. (TSXV: CEI) ("Coelacanth" or the "Company") announces that its board of directors approved the granting of incentive stock options ("Options") under its stock option plan to acquire up to an aggregate of 3,877,378 common shares ("Common Shares") of the Corporation and the granting of restricted share units ("RSUs") under its restricted share unit plan to obtain up to an aggregate of 2,657,622 Common Shares to certain of its directors and officers. It has also approved the granting of 1,849,001 Options and 906,999 RSUs to certain of its employees and consultants.
All of the Options are exercisable for a period of five years at a price of $0.81 per Common Share and 33⅓% of the Options will vest on the date that is one year after the date of the grant of such Options and the remainder will vest 33⅓% per year thereafter. All of the RSUs are exercisable for a period of three years at no additional cost and 33⅓% of the RSUs will vest on the date that is one year after the date of the grant of such RSUs and the remainder will vest 33⅓% per year thereafter.
Following the grant of Options and RSUs, Coelacanth has an aggregate of 22,697,637 Options and 8,460,065 RSUs outstanding. Coelacanth's share based incentive plans limit the total number of Common Shares underlying the aggregate outstanding Options and RSUs to no more than 10% of the issued and outstanding Common Shares of 531,352,966. As of the date of this press release, the total number of Common Shares underlying the outstanding Options and RSUs on an aggregate basis is 31,157,702 or approximately 5.86% of the issued and outstanding Common Shares.
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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To view the source version of this press release, please visit https://www.newsfilecorp.com/release/237872
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Coelacanth Energy Inc. (TSXV: CEI) ("Coelacanth" or the "Company") announces that it has completed and tested 4 additional wells at its Two Rivers East Project including 3 Lower Montney Wells and 1 Upper Montney well on the 5-19 pad.
LOWER MONTNEY
The 3 new Lower Montney wells (F5-19, G5-19, H5-19) were drilled with an average horizontal length of 3,285 metres and completed with approximately 2.5 tons of sand per horizontal metre. The wells were placed on test for clean-up for an average of 7 days until a stabilized rate was achieved. The test rates noted below are based on the final 24 hours of each test.
The average rate achieved for the 3 new Lower Montney wells was 1,624 boepd per well comprised of 989 bbls per day of 41 API light sweet oil and 3.8 mmcf/d of liquids-rich gas. The rates per well are outlined in the table below:
| Well | Oil - bbls/d | Gas - mmcf/d | Total - boe/d | % Light Oil |
| F5-19 | 1,061 | 3.2 | 1,595 | 67 |
| G5-19 | 900 | 4.0 | 1,573 | 57 |
| H5-19 | 1,007 | 4.2 | 1,703 | 59 |
| Average | 989 | 3.8 | 1,624 | 61 |
The overall rates and more specifically the oil rates were materially higher than the previous 3 wells on the pad (C5-19, D5-19 and E5-19) that achieved an average test rate of 1,338 boepd including 729 bbls/d of light oil and 3.7 mmcf/d of gas (see press release dated January 18, 2024 for more information including per well test results and initial production rates). Although the 3 new Lower Montney wells were drilled with slightly longer lateral lengths and the completion design was slightly modified in an attempt to increase the overall oil production, the tests have exceeded expectations.
UPPER MONTNEY
The Upper Montney well (B5-19) was drilled with a horizontal length of 2,647 metres and completed with approximately 2.5 tons of sand per horizontal metre. The well flowed on cleanup for 6 days and achieved a rate of 1,136 boepd comprised of 271 bbls/d of 40 API light oil and 5.2 mmcf/d of liquids-rich gas. In comparison to the Lower Montney Wells noted above, the B5-19 was 20% shorter in horizontal length and had 42% less frac stages leaving room for future optimization.
Management is very pleased with the B5-19 test result particularly the potential impact on Coelacanth's development inventory over its 150-section contiguous Montney land block. The Upper Montney is extensively mapped over Coelacanth's lands, but the impact of this test is amplified given it is a 10-mile step-out from Coelacanth's Two Rivers West project and 5 miles from the nearest competitor well.
INFRASTRUCTURE & TAKEAWAY
As previously disclosed, Coelacanth has secured long-term takeaway and processing for up to 60 mmcf/d of gas and is in process of constructing the required facilities and pipelines to handle the 5-19 and subsequent pads. Initial testing and start-up of the facility is anticipated for late April 2025.
Overall, Coelacanth believes this was a very significant second step in its development that has materially expanded the development fairway of the Upper Montney as well as increased the productivity of the Lower Montney that was already established as productive.
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
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.
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) |
| Natural Gas | |
| Mcf | Thousands of cubic feet |
| Mcf/d | Thousands of cubic feet per day |
| MMcf/d | Millions of cubic feet 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.
Product Types
The Company uses the following references to sales volumes in the news release:
Natural 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 capital programs. 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.
Test Results and Initial Production Rates
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 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 Basal 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 four 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.
To view the source version of this press release, please visit https://www.newsfilecorp.com/release/232259
News Provided by Newsfile via QuoteMedia
Coelacanth Energy Inc. (TSXV: CEI) ("Coelacanth" or the "Company") is pleased to announce its financial and operating results for the three and nine months ended September 30, 2024. All dollar figures are Canadian dollars unless otherwise noted.
| FINANCIAL RESULTS | Three Months Ended | Nine Months Ended | ||||||||||||||||
| September 30 | September 30 | |||||||||||||||||
| ($000s, except per share amounts) | 2024 | 2023 | % Change | 2024 | 2023 | % Change | ||||||||||||
| Oil and natural gas sales | 2,362 | 679 | 248 | 9,192 | 2,459 | 274 | ||||||||||||
| Cash flow used in operating activities | (3,730 | ) | (2,553 | ) | 46 | (954 | ) | (3,830 | ) | (75 | ) | |||||||
| Per share - basic and diluted (1) | (0.01 | ) | (0.01 | ) | - | (-) | (0.01 | ) | (100 | ) | ||||||||
| Adjusted funds flow (used) (1) | (207 | ) | (773 | ) | (73 | ) | 1,133 | (2,083 | ) | (154 | ) | |||||||
| Per share - basic and diluted | (-) | (-) | - | - | (-) | - | ||||||||||||
| Net loss | (2,464 | ) | (1,869 | ) | 32 | (5,994 | ) | (5,823 | ) | 3 | ||||||||
| Per share - basic and diluted | (-) | (-) | - | (0.01 | ) | (0.01 | ) | - | ||||||||||
| Capital expenditures (1) | 15,760 | 31,176 | (49 | ) | 19,545 | 39,957 | (51 | ) | ||||||||||
| Adjusted working capital (1) | 47,264 | 23,516 | 101 | |||||||||||||||
| Common shares outstanding (000s) | ||||||||||||||||||
| Weighted average - basic and diluted | 530,212 | 426,476 | 24 | 529,605 | 425,685 | 24 | ||||||||||||
| End of period - basic | 530,267 | 426,670 | 24 | |||||||||||||||
| End of period - fully diluted | 617,214 | 469,781 | 31 | |||||||||||||||
| (1) See "Non-GAAP and Other Financial Measures" section. | ||||||||||||||||||
| OPERATING RESULTS (1) | Three Months Ended | Nine Months Ended | ||||||||||||||||
| September 30 | September 30 | |||||||||||||||||
| 2024 | 2023 | % Change | 2024 | 2023 | % Change | |||||||||||||
| Daily production (2) | ||||||||||||||||||
| Oil and condensate (bbls/d) | 221 | 39 | 467 | 268 | 46 | 483 | ||||||||||||
| Other NGLs (bbls/d) | 33 | 7 | 371 | 36 | 12 | 200 | ||||||||||||
| Oil and NGLs (bbls/d) | 254 | 46 | 452 | 304 | 58 | 424 | ||||||||||||
| Natural gas (mcf/d) | 3,450 | 929 | 271 | 3,702 | 1,208 | 206 | ||||||||||||
| Oil equivalent (boe/d) | 829 | 201 | 313 | 921 | 259 | 256 | ||||||||||||
| Oil and natural gas sales | ||||||||||||||||||
| Oil and condensate ($/bbl) | 89.68 | 99.00 | (9 | ) | 90.88 | 93.73 | (3 | ) | ||||||||||
| Other NGLs ($/bbl) | 31.39 | 28.07 | 12 | 33.20 | 33.97 | (2 | ) | |||||||||||
| Oil and NGLs ($/bbl) | 82.10 | 88.43 | (7 | ) | 84.00 | 81.69 | 3 | |||||||||||
| Natural gas ($/mcf) | 1.41 | 3.60 | (61 | ) | 2.16 | 3.58 | (40 | ) | ||||||||||
| Oil equivalent ($/boe) | 30.99 | 36.85 | (16 | ) | 36.41 | 34.83 | 5 | |||||||||||
| Royalties | ||||||||||||||||||
| Oil and NGLs ($/bbl) | 15.52 | 20.08 | (23 | ) | 19.73 | 22.51 | (12 | ) | ||||||||||
| Natural gas ($/mcf) | 0.06 | 0.79 | (92 | ) | 0.23 | 0.82 | (72 | ) | ||||||||||
| Oil equivalent ($/boe) | 5.02 | 8.26 | (39 | ) | 7.44 | 8.82 | (16 | ) | ||||||||||
| Operating expenses | ||||||||||||||||||
| Oil and NGLs ($/bbl) | 10.07 | 18.92 | (47 | ) | 10.10 | 17.68 | (43 | ) | ||||||||||
| Natural gas ($/mcf) | 1.68 | 3.17 | (47 | ) | 1.68 | 2.95 | (43 | ) | ||||||||||
| Oil equivalent ($/boe) | 10.07 | 18.98 | (47 | ) | 10.10 | 17.68 | (43 | ) | ||||||||||
| Net transportation expenses (3) | ||||||||||||||||||
| Oil and NGLs ($/bbl) | 2.36 | 2.40 | (2 | ) | 2.30 | 1.86 | 24 | |||||||||||
| Natural gas ($/mcf) | 0.76 | 1.40 | (46 | ) | 0.72 | 1.36 | (47 | ) | ||||||||||
| Oil equivalent ($/boe) | 3.91 | 7.05 | (45 | ) | 3.65 | 6.76 | (46 | ) | ||||||||||
| Operating netback (loss) (3) | ||||||||||||||||||
| Oil and NGLs ($/bbl) | 54.15 | 47.03 | 15 | 51.87 | 39.64 | 31 | ||||||||||||
| Natural gas ($/mcf) | (1.09 | ) | (1.76 | ) | (38 | ) | (0.47 | ) | (1.55 | ) | (70 | ) | ||||||
| Oil equivalent ($/boe) | 11.99 | 2.56 | 368 | 15.22 | 1.57 | 869 | ||||||||||||
| Depletion and depreciation ($/boe) | (14.89 | ) | (21.33 | ) | (30 | ) | (14.71 | ) | (18.24 | ) | (19 | ) | ||||||
| General and administrative expenses ($/boe) | (12.51 | ) | (47.09 | ) | (73 | ) | (13.90 | ) | (46.70 | ) | (70 | ) | ||||||
| Share based compensation ($/boe) | (13.81 | ) | (34.70 | ) | (60 | ) | (12.72 | ) | (32.12 | ) | (60 | ) | ||||||
| Finance expense ($/boe) | (2.71 | ) | (9.61 | ) | (72 | ) | (1.72 | ) | (5.27 | ) | (67 | ) | ||||||
| Finance income ($/boe) | 9.54 | 37.32 | (74 | ) | 10.03 | 29.26 | (66 | ) | ||||||||||
| Unutilized transportation ($/boe) | (9.94 | ) | (28.44 | ) | (65 | ) | (5.96 | ) | (10.95 | ) | (46 | ) | ||||||
| Net loss ($/boe) | (32.33 | ) | (101.29 | ) | (68 | ) | (23.76 | ) | (82.45 | ) | (71 | ) | ||||||
| (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 nine months ended September 30, 2024, which are available for review under the Company's profile on SEDAR+ at www.sedarplus.com. | ||||||||||||||||||
OPERATIONS UPDATE
In Q3 2024, Coelacanth started the construction of its planned $80.0 million infrastructure project that includes over 35 kilometers of pipelines and a facility to handle current behind pipe volumes and future expansions. Ultimately the facility will be able to handle approximately 16,000 boe/d of which Coelacanth has approximately 4,400 boe/d tested but shut-in at the 5-19 Two Rivers East pad. The infrastructure is expected to be operational by mid-April 2025. Funding for this project is from cash on hand of approximately $64 million at the inception of the project plus up to $27.0 million from a mid-stream company that will fund the pipeline connection to its area gathering lines upon achievement of certain project milestones.
An additional four Montney wells are currently being completed and tested on the 5-19 pad which will add additional capacity to be brought on once the facility is operational. Debt financing of $52.0 million was secured subsequent to the quarter through two revolving bank credit facilities with $35.0 million currently being invested in the four new Montney wells noted plus a water disposal well.
Although the construction and start-up of the Two Rivers East project is a huge step in Coelacanth's development, we believe we are just scratching the surface on what the potential of this large Montney asset base may ultimately be able to perform.
We look forward to reporting updates on the Two Rivers East project in the upcoming quarters.
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 | Nine Months Ended | |||||||||||
| September 30 | September 30 | |||||||||||
| ($000s) | 2024 | 2023 | 2024 | 2023 | ||||||||
| Cash flow used in operating activities | (3,730 | ) | (2,553 | ) | (954 | ) | (3,830 | ) | ||||
| Add (deduct): | ||||||||||||
| Decommissioning expenditures | 790 | 925 | 1,266 | 1,677 | ||||||||
| Change in restricted cash deposits | 2,139 | - | 2,985 | (784 | ) | |||||||
| Change in non-cash working capital | 594 | 855 | (2,164 | ) | 854 | |||||||
| Adjusted funds flow (used) (non-GAAP) | (207 | ) | (773 | ) | 1,133 | (2,083 | ) | |||||
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 | Nine Months Ended | |||||||||||
| September 30 | September 30 | |||||||||||
| ($000s) | 2024 | 2023 | 2024 | 2023 | ||||||||
| Transportation expenses | 1,055 | 654 | 2,426 | 1,250 | ||||||||
| Unutilized transportation | (757 | ) | (525 | ) | (1,504 | ) | (773 | ) | ||||
| Net transportation expenses (non-GAAP) | 298 | 129 | 922 | 477 | ||||||||
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 | Nine Months Ended | |||||||||||
| September 30 | September 30 | |||||||||||
| ($000s) | 2024 | 2023 | 2024 | 2023 | ||||||||
| Oil and natural gas sales | 2,362 | 679 | 9,192 | 2,459 | ||||||||
| Royalties | (383 | ) | (152 | ) | (1,878 | ) | (623 | ) | ||||
| Operating expenses | (767 | ) | (350 | ) | (2,549 | ) | (1,249 | ) | ||||
| Net transportation expenses | (298 | ) | (129 | ) | (922 | ) | (477 | ) | ||||
| Operating netback (non-GAAP) | 914 | 48 | 3,843 | 110 | ||||||||
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 | Nine Months Ended | |||||||||||
| September 30 | September 30 | |||||||||||
| ($000s) | 2024 | 2023 | 2024 | 2023 | ||||||||
| Capital expenditures - property, plant, and equipment | 396 | 15,785 | 973 | 22,344 | ||||||||
| Capital expenditures - exploration and evaluation assets | 15,364 | 15,391 | 18,572 | 17,613 | ||||||||
| Capital expenditures (non-GAAP) | 15,760 | 31,176 | 19,545 | 39,957 | ||||||||
Capital Management Measures
Adjusted working capital
Management uses adjusted working capital 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) | September 30, 2024 | December 31, 2023 | ||||
| Current assets | 49,905 | 87,616 | ||||
| Less: | ||||||
| Current liabilities | (14,235 | ) | (28,754 | ) | ||
| Working capital | 35,670 | 58,862 | ||||
| Add: | ||||||
| Restricted cash deposits | 10,001 | 6,784 | ||||
| Current portion of decommissioning obligations | 1,593 | 1,943 | ||||
| Adjusted working capital (Capital management measure) | 47,264 | 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.
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 | Nine Months Ended | |||||||||||
| September 30 | September 30 | |||||||||||
| Sales Volumes by Product Type | 2024 | 2023 | 2024 | 2023 | ||||||||
| Condensate (bbls/d) | 33 | 4 | 36 | 6 | ||||||||
| Other NGLs (bbls/d) | 33 | 7 | 36 | 12 | ||||||||
| NGLs (bbls/d) | 66 | 11 | 72 | 18 | ||||||||
| Tight oil (bbls/d) | 188 | 35 | 232 | 40 | ||||||||
| Condensate (bbls/d) | 33 | 4 | 36 | 6 | ||||||||
| Oil and condensate (bbls/d) | 221 | 39 | 268 | 46 | ||||||||
| Other NGLs (bbls/d) | 33 | 7 | 36 | 12 | ||||||||
| Oil and NGLs (bbls/d) | 254 | 46 | 304 | 58 | ||||||||
| Shale gas (mcf/d) | 3,450 | 929 | 3,702 | 1,208 | ||||||||
| Natural gas (mcf/d) | 3,450 | 929 | 3,702 | 1,208 | ||||||||
| Oil equivalent (boe/d) | 829 | 201 | 921 | 259 | ||||||||
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/230803
News Provided by Newsfile via QuoteMedia
“The macroeconomic conditions that underpin our oil demand projections deteriorated over the past month as trade tensions escalated between the United States and several other countries,” a March oil market report from the International Energy Agency (IEA) notes, highlighting the downside risks of US tariffs and retaliatory measures.
The instability and weaker-than-expected consumption from advanced and developing economies prompted the IEA to downgrade its growth estimates for Q4 2024 and Q1 2025 to about 1.2 million barrels per day.
Despite the uncertain outlook, an announcement that OPEC+ would extend a 2.2 million barrel per day production cut into Q2 added some support to the market amid global growth concerns and rising output in the US.
Prices spiked at the end of March, pushing both benchmarks to within a dollar of their 2025 start values. However, the rally was short-lived and prices had plummeted by April 9.
WTI price performance, December 31, 2024, to April 23, 2025.
Chart via the Investing News Network.
Sinking to four year lows, Brent and WTI fell below the critical US$60 per barrel threshold, to US$58.62 (Brent) and US$55.38 (WTI), lows not seen since April 2021. The decline saw prices shed more than 21 percent between January and April shaking the market and investor confidence.
“We're into the supply destruction territories for some of the high cost producers,” Ole Hansen, head of commodity strategy at Saxo Bank, told the Investing News Network. “It will not play out today or tomorrow, because a lot of these producers are forward hedging as part of their production.”
Watch Hansen discuss where oil and other commodities are heading.
According to Hansen, if prices remain in the high US$50 range US production will likely decrease, aiding in a broader market realignment. "Eventually we will see production start to slow in the US, probably other places as well, and that will help balance the market,” the expert explained in the interview. “Helping to offset some of the risk related to recession, but also some of the production increases that we're seeing from OPEC.”
In early April, OPEC+ did an about face when it announced plans for a significant increase in oil production, marking its first output hike since 2022. The group plans to add 411,000 barrels per day (bpd) to the market starting in May, effectively accelerating its previously gradual supply increase strategy.
Although the group cited “supporting market stability” as the reasoning behind the increase, some analysts believe the decision is a punitive one targeted at countries like Iraq and Kazakhstan who consistently exceed production quotas.
“(The increase) is basically in order to punish some of the over producers,” said Hansen. He went on to explain that Kazakhstan produced 400,000 barrels beyond its quota.
If these countries return to their agreed limits, it could offset OPEC’s planned production hikes.
At the same time, US sanctions on Iran and Venezuela may tighten global supply further, while a growing military presence in the Middle East also signals rising geopolitical risks, particularly involving Iran.
As such Hansen expects prices to fluctuate between US$60 to US$80 for the rest of the year.
“(I am) struggling to see, prices collapse much further than that, simply because it will have a counterproductive impact on supply and that will eventually help stabilize prices,” said Hansen.
Hansen’s projections also fall inline with data from the US Energy Information Administration (EIA). The organization downgraded the US$74 Brent price forecast it set in March to US$68 in April.
The EIA foresees US and global oil production to continue rising in 2025, as OPEC+ speeds up its planned output increases and US energy remains exempt from new tariffs.
Starting mid-year, global oil inventories are projected to build. However, the EIA warns that economic uncertainty could dampen demand growth for petroleum products, potentially falling short of earlier forecasts.
“The combination of growing supply and lower demand leads EIA to expect the Brent crude oil price to average less than US$70 per barrel in 2025 and fall to an average of just over US$60 per barrel in 2026,” the April report read.
On the natural gas side, Q1 was marked by tight conditions amid rising demand. A colder-than-normal winter led to increased consumption, with US natural gas withdrawals in Q1 exceeding the five-year average.
Starting the year at US$3.59 per metric million British thermal units, prices rose to a year-to-date high of US$4.51 on March 10. Values pulled back by the end of the 90 day period to the US$4.09 level, registering a 13.9 percent increase for Q1.
"Cold weather during January and February led to increased natural gas consumption and large natural gas withdrawals from inventories,” a March report from the EIA explains.
Natural gas price performance, December 31, 2024, to April 23, 2025.
Chart via the Investing News Network.
“(The) EIA now expects natural gas inventories to fall below 1.7 trillion cubic feet at the end of March, which is 10 percent below the previous five-year average and 6 percent less natural gas in storage for that time of year than EIA had expected last month," the document continues.
Following record setting demand growth in 2024 the gas market is expected to remain tight through 2025, amid market expansion from Asian countries.
The IEA also pointed to price volatility brought on geopolitical tensions as a factor that could move markets.
“Though the halt of Russian piped gas transit via Ukraine on 1 January 2025 does not pose an imminent supply security risk for the European Union, it could increase LNG import requirements and tighten market fundamentals in 2025,” the organization notes in a gas market report for Q1.
Although the market is forecasted to remain tight the IEA expects growth in global gas demand to slow to below 2 percent in 2025. Similarly to 2024’s trajectory, growth is set to be largely driven by Asia, which is expected to account for almost 45 percent of incremental gas demand, the report read.
THe US-based EIA has a more optimistic outlook for the domestic gas sector, projecting the annual demand growth rate to be 4 percent for 2025.
“This increase is led by an 18 percent increase in exports and a 9 percent increase in residential and commercial consumption for space heating,” an April EIA market overview states.
The report attributes the expected export growth to increased liquefied natural gas (LNG) shipments out of two new LNG export facilities, Plaquemines Phase 1 and Golden Pass LNG.
Venture Global's (NYSE:VG) Plaquemines LNG facility in Louisiana commenced production in December 2024 and is currently in the commissioning phase.
Once fully operational, it is expected to have a capacity of 20 million metric tons per annum. The facility has entered into binding long-term sales agreements for its full capacity
Golden Pass LNG, a joint venture between ExxonMobil (NYSE:XOM) and state-owned QatarEnergy, is under construction in Sabine Pass, Texas. The project has faced delays due to the bankruptcy of a key contractor, with Train 1 now expected to be operational by late 2025 . Upon completion, Golden Pass LNG will have an export capacity of up to 18.1 million metric tons per annum.
The EIA forecasts natural gas prices to average US$4.30 in 2025, a US$2.10 increase from 2025. Farther ahead the EIA has a more modest forecast of US$4.60 for 2026.
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Securities Disclosure: I, Georgia Williams, hold no direct investment interest in any company mentioned in this article.
Editorial Disclosure: The Investing News Network does not guarantee the accuracy or thoroughness of the information reported in the interviews it conducts. The opinions expressed in these interviews do not reflect the opinions of the Investing News Network and do not constitute investment advice. All readers are encouraged to perform their own due diligence.
Jupiter Energy’s strong cash flow, substantial proven recoverable reserves, and strategic foothold in resource-rich Kazakhstan present a compelling investment opportunity. Its commitment to sustainability—reinforced by a recent strategic investment in 100 percent gas utilization infrastructure—further enhances its long-term investor appeal.
Jupiter Energy Limited (ASX:JPR) is an established oil exploration and production company that operates three oilfields in Kazakhstan. The company is currently producing approximately 600 to 700 barrels of oil per day from its licensed fields, having successfully navigated Kazakhstan’s regulatory and operational landscape since 2008. Its operations are fully compliant, with its three full commercial production licenses secured until 2045/46/46.
Jupiter Energy is recognized as a reliable operator in Kazakhstan, holding 100 percent ownership of its licenses, which span approximately 123 sq km in the oil-rich Mangistau region. Strategically located near the port city of Aktau, its license area benefits from proximity to established oil processing facilities and extensive oil and gas infrastructure, including key pipeline connections to the country’s major refineries (see Figure 1).
The company has successfully navigated regulatory requirements to achieve full commercial production across its three oilfields—Akkar East, Akkar North (East Block), and West Zhetybai—all operating under 25-year commercial licenses. Jupiter’s strong compliance and operational framework reinforce its commitment to long-term, sustainable production in Kazakhstan.
Jupiter Energy’s reserve base has been independently confirmed by a Sproule International competent person’s report (CPR), effective 31 December 2023, detailing significant recoverable reserves.
According to the Sproule International CPR, released in January 2024, Jupiter Energy’s recoverable reserves under the SPE/PRMS classification are as follows:
These figures confirm Jupiter’s substantial reserve base, and correlate with its Kazakh State Approved Reserves which are recorded at approximately 52 mmbbls recoverable (using the GOST C1 + C2 classification methodology) (see Figure 2).
Figure 1: Total reserves for the Mangistau basin are estimated to be in excess of 5 billion barrels including two large oil fields, Uzen and Zhetybai.
On November 15, 2024, Jupiter Energy announced the completion of its gas pipeline integration project, connecting the Akkar East and Akkar North (East Block) oilfields to neighboring gas utilization facilities operated by its larger neighbour, MangistauMunaiGas (MMG). This integration ensures 100 percent utilization of all its associated gas, aligning with Kazakhstan’s environmental goals and enabling the Company to drill further wells whilst continuing to comply with Kazakhstan’s strict 100% gas utilisation policy.
The company plans to connect the West Zhetybai oilfield to this infrastructure as this oilfield is further developed. This project strengthens Jupiter’s relationships with MMG and the Kazakh Ministry of Energy, facilitating long-term production under its commercial licenses and enabling it to sell its oil into both the Kazakh domestic market as well as international oil markets.
Figure 2: Outline of Jupiter Energy’s oilfields located on Block 36
Block 36 is Jupiter Energy’s flagship project located in the Mangistau Basin of West Kazakhstan. Covering an area of approximately 123 sq km, it lies in a highly prospective region with proven oil reserves. The company acquired extensive 3D seismic data over the entire block and surrounding areas, totaling 235 sq km, which then enabled the identification of multiple drilling targets. The current reserve base covers 35 sq km, with further exploration targets available for drilling on the licence area, when funding for further exploration wells is available.
Jupiter has drilled nine wells on Block 36, targeting the Akkar North (East Block), Akkar East, and West Zhetybai oilfields (see Figure 3). The current production from Block 36 is approximately 640 barrels of oil per day, with plans to increase output to around 1,000 barrels per day during 2025, assuming success with the drilling of a new production well in 2H 2025. Further increases in production may also come via the workovers of existing wells and the drilling of further new wells, planned from 2025 to 2030.
Figure 3: Well locations on Block 36
At the helm of Jupiter Energy is a highly experienced corporate and technical leadership team, driving the company towards achieving its goals and increasing shareholder value.
Geoff Gander graduated from the University of Western Australia in 1984, where he completed a Bachelor of Commerce degree. He has been involved in the listing and running of public companies since 1994. He was appointed as a director of Jupiter Energy in January 2005 and he is currently responsible for the overall operational leadership of the company, as well as investor relations and group corporate development.
Baltabek Kuandykov is currently the president of Meridian Petroleum, a privately held Kazakh oil & gas company. He was formerly the president of Nelson Resources, an oil development and production company operating in Kazakhstan which was listed on the Toronto Stock Exchange until its acquisition by Lukoil in 2005. Kuandykov has considerable experience in the oil and gas industry in the region, having served as president of Kazakhoil (predecessor of the Kazakh State oil company KazMunaiGas), and is a well-respected consultant to Chevron Overseas Petroleum on CIS projects. He also worked in a senior capacity for Kazneftegazrazvedka and was president of Kazakhstancaspishelf. Kuandykov has extensive government experience in Kazakhstan, having served as deputy minister of geology, head of the oil and gas directorate at the Ministry of Geology, and was deputy minister of energy and fuel resources.
Alexey Kruzhkov holds an engineering degree and an MBA with over 10 years’ experience working in the investment industry, focusing primarily on the oil & gas, mining and real estate sectors. He has served as a director on the boards of companies listed in Canada and Norway. He is a member of the executive team of Waterford Finance and Investment Limited. He holds British and Russian citizenship.
Alexander Kuzev is an oil industry professional with over 26 years of experience. Most of his career has been spent working in the Former Soviet Union with much of that time responsible for the overall management of field operations with a focus on production sustainability, technology and field maintenance. He brings an important technical advisory skill set to the Jupiter Energy board, as well as in-country experience, having been involved with various Kazakhstan-based oil and gas operations since the late 1990s.
