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.
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
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Coelacanth Energy Inc. (TSXV: CEI) ("Coelacanth" or the "Company") announces that it has secured a $52 million bank credit facility and has commenced a 4-well drilling program at Two Rivers East.
TWO RIVERS EAST PROJECT
Coelacanth has commenced drilling on the 5-19 Pad at Two Rivers East with the first well spud on September 1st. The complete program consists of drilling and completing 3 Lower Montney wells, completing 1 previously drilled Upper Montney well, and drilling a Bluesky disposal well for a total cost of approximately $36 million. The 4 pad wells are scheduled to be completed starting late October 2024.
As previously released, the three 5-19 Lower Montney wells drilled in 2023 had tested at a per well average of 1,338 boe/d for a combined rate of 4,014 boe/d (54% light oil). The program above will be additive to this once the Two Rivers East facility is constructed and on-stream in April 2025. The Upper Montney has not produced in the immediate area but has been very prolific in the greater region. Management is looking forward to proving up the commerciality of this zone in the area as well as establishing expected oil/gas production mix.
Strategic benefits of this program are as follows:
Also as previously released, Coelacanth obtained all regulatory approvals to construct a new battery facility ("Facility") at Two Rivers East designed for gas compression/dehydration, oil treating and water handling, plus gathering and transport lines to connect from the 5-19 Pad through the Facility to a mid-stream gathering line. Construction of the pipelines and the facility site have already commenced and estimated to be operational in April 2025.
BANK CREDIT FACILITY AND FINANCIAL UPDATE
Coelacanth secured 2 revolving bank credit facilities for a total of $52 million from its primary lender. The facilities are backed by reserves at Two Rivers West plus a $45 million Letter of Credit from a third party. The commitment from the third party is for a 2-year term. During the term, Coelacanth expects that the lending value of producing reserves at Two Rivers East will allow for the credit facility to be renegotiated and the Letter of Credit to be returned.
Coelacanth had also previously secured a commitment for approximately $22 million from a Mid-Stream company to finance a pipeline connecting Coelacanth facilities to the Mid-Stream Company's gathering system.
With over $60 million cash and no debt at the end of Q2 2024, Coelacanth estimates it will have approximately $40 million net debt plus the mid-stream commitment once the drilling program is completed and the facility is operational. Once operational and pending drilling success on the above program, Coelacanth's production should stabilize at over 6,000 boe/d until additional wells are drilled in the summer of 2025.
SHARE PURCHASE WARRANTS
As part of the $80 million bought deal financing completed in November 2023, Coelacanth had issued 33.3 million share purchase warrants ("Warrants") with a strike price of $1.05 per share that expire November 15, 2024. Coelacanth's Board of Directors has determined that extending the Warrant expiry date to June 30, 2025 is in the best interest of the Company and management will start the regulatory process to extend such Warrants.
Proceeds of the Warrant exercise, if any, would be used for additional pad drilling at Two Rivers East scheduled for summer of 2025.
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 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.
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.
Production Rates
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.
To view the source version of this press release, please visit https://www.newsfilecorp.com/release/225700
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About BPH Energy Limited:
BPH Energy Limited (ASX:BPH) is an Australian Securities Exchange listed company developing biomedical research and technologies within Australian Universities and Hospital Institutes.
The company provides early stage funding, project management and commercialisation strategies for a direct collaboration, a spin out company or to secure a license.
BPH provides funding for commercial strategies for proof of concept, research and product development, whilst the institutional partner provides infrastructure and the core scientific expertise.
BPH currently partners with several academic institutions including The Harry Perkins Institute for Medical Research and Swinburne University of Technology (SUT).
Source:
BPH Energy Limited
Contact:
David Breeze
admin@bphenergy.com.au
www.bphenergy.com.au
T: +61 8 9328 8366
News Provided by ABN Newswire via QuoteMedia
