Coelacanth Energy Inc. Announces Receipt of All Regulatory Approvals for Two Rivers East and Finalization of Midstream Processing Agreement
Coelacanth Energy has received all necessary regulatory approvals for the construction of infrastructure at its Two Rivers East Project. The company will build a new battery facility for gas compression/dehydration, oil treating, and water handling. Estimated costs for the project are $80 million, with $50 million allocated to the facility. Manufacturing has started, with construction expected to run from fall 2024 to April 2025. The project, anchored by the Lower Montney, has estimated initial production of 4,500 boe/d from five wells.
Additionally, Coelacanth finalized an agreement with NorthRiver Midstream for up to 60 mmcf/d of firm processing service over 10 years at NRM's McMahon gas processing facility. NRM will fund an extension of its gathering system to connect with Coelacanth's new facility. The company has secured long-term takeaway capacity of over 60 mmcf/d of gas into the Westcoast system.
- Received all regulatory approvals for Two Rivers East Project infrastructure.
- Finalized processing agreement with NorthRiver Midstream for 60 mmcf/d of gas processing over 10 years.
- NRM to fund extension of its gathering system, reducing Coelacanth's infrastructure costs.
- Estimated infrastructure costs of $80 million, which could impact cash flow.
- Long construction period from fall 2024 to April 2025, delaying revenue generation.
Calgary, Alberta--(Newsfile Corp. - July 2, 2024) - Coelacanth Energy Inc. (TSXV: CEI) ("Coelacanth" or the "Company") announces that it has received all regulatory approvals to construct infrastructure for its Two Rivers East Project and has finalized its previously announced processing agreement with NorthRiver Midstream Inc. ("NRM").
TWO RIVERS EAST PROJECT
The Company has 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.
The total estimated costs of the infrastructure are estimated at
Estimated initial production from the 5-19 Pad (including the three Lower Montney wells tabled below, one Basal Montney well, and one legacy Lower Montney well) is estimated at 4,500 boe/d.
The Two Rivers East Project is anchored by the Lower Montney but has additional potential upside in both the Upper Montney and Basal Montney. As previous released, the average rate achieved for the 3 Lower Montney wells was 1,338 boe/d per well comprised of 729 bbls/d of 39 API light sweet oil and 3.7 mmcf/d of liquids-rich gas. The rates per well were similar as outlined in the table below:
| Well | Oil - bbls/d | Gas - mmcf/d | Total - boe/d | % Light Oil |
| C5-19 | 818 | 3.2 | 1,345 | 61 |
| D5-19 | 527 | 4.2 | 1,222 | 43 |
| E5-19 | 841 | 3.6 | 1,448 | 58 |
| Average | 729 | 3.7 | 1,338 | 54 |
MIDSTREAM AGREEMENT AND TAKEAWAY CAPACITY
Coelacanth has finalized a previously announced arrangement with NorthRiver Midstream Inc. to secure up to 60 mmcf/d of firm processing service at NRM's McMahon gas processing facility for a period of 10 years. The processing service will commence after the construction of the Two Rivers East Facility. As part of the arrangement, NRM has agreed to fund an extension of its gathering system to interconnect the Two Rivers East Facility to NRM's current gathering system.
As previously disclosed, Coelacanth has secured long-term takeaway of over 60 mmcf/d of gas to be delivered into the Westcoast system.
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 2660 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/214881
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