Coelacanth Announces Q4 2024 Financial and Operating Results
Coelacanth Energy Inc. (TSXV: CEI) (‘Coelacanth’ or the ‘Company’) is pleased to announce its financial and operating results for the three months and year ended December 31, 2024. All dollar figures are Canadian dollars unless otherwise noted.
2024 HIGHLIGHTS
Drilled and completed three Lower Montney wells and completed a previously drilled Upper Montney well on its 5-19 pad at Two Rivers East. Average test production from the three Lower Montney wells was 1,624 boe/d (61% light oil) and test production from the Upper Montney well was 1,338 boe/d (54% light oil). (2)
Secured revolving bank credit facilities for a total of $52.0 million from a Canadian chartered bank.
Substantially completed construction of pipelines to connect the 5-19 pad wells to the Two Rivers East facility.
Initiated construction of its Two Rivers East facility for a Q2 2025 on-stream date.
FINANCIAL RESULTS
Three Months Ended
Year Ended
December 31
December 31
($000s, except per share amounts)
2024
2023
% Change
2024
2023
% Change
Oil and natural gas sales
4,544
4,204
8
13,736
6,663
106
Cash flow from (used in) operating activities
3,157
(404
)
(881
)
2,203
(4,234
)
(152
)
Per share – basic and diluted (1)
0.01
(-)
(100
)
–
(0.01
)
(100
)
Adjusted funds flow (used) (1)
382
1,750
(78
)
1,515
(333
)
(555
)
Per share – basic and diluted
–
–
–
–
(-)
(-)
Net loss
(2,903
)
(750
)
287
(8,897
)
(6,573
)
35
Per share – basic and diluted
(0.01
)
(-)
100
(0.02
)
(0.01
)
100
Capital expenditures (1)
64,952
34,656
87
84,497
74,613
13
Adjusted working capital (deficiency) (1)
(18,637
)
67,589
(128
)
Common shares outstanding (000s)
Weighted average – basic and diluted
530,398
478,731
11
529,804
439,055
21
End of period – basic
530,670
528,650
–
End of period – fully diluted
615,930
609,989
1
(1) See ‘Non-GAAP and Other Financial Measures’ section.
(2) See ‘Test Results and Initial Production Rates’ section.
Three Months Ended
Year Ended
OPERATING RESULTS (1)
December 31
December 31
2024
2023
% Change
2024
2023
% Change
Daily production (2)
Oil and condensate (bbls/d)
473
419
13
320
139
130
Other NGLs (bbls/d)
29
28
4
34
16
113
Oil and NGLs (bbls/d)
502
447
12
354
155
128
Natural gas (mcf/d)
3,490
2,858
22
3,648
1,624
125
Oil equivalent (boe/d)
1,084
923
17
962
426
126
Oil and natural gas sales
Oil and condensate ($/bbl)
87.06
87.38
(-)
89.46
88.94
1
Other NGLs ($/bbl)
33.28
32.32
3
33.22
33.22
–
Oil and NGLs ($/bbl)
83.97
83.88
–
83.99
83.28
1
Natural gas ($/mcf)
2.07
2.86
(28
)
2.14
3.26
(34
)
Oil equivalent ($/boe)
45.57
49.47
(8
)
39.01
42.82
(9
)
Royalties
Oil and NGLs ($/bbl)
16.86
19.38
(13
)
18.70
20.24
(8
)
Natural gas ($/mcf)
0.13
0.26
(50
)
0.21
0.57
(63
)
Oil equivalent ($/boe)
8.22
10.20
(19
)
7.66
9.57
(20
)
Operating expenses
Oil and NGLs ($/bbl)
8.34
11.57
(28
)
9.47
13.25
(29
)
Natural gas ($/mcf)
1.25
1.28
(2
)
1.58
2.21
(29
)
Oil equivalent ($/boe)
7.88
9.57
(18
)
9.47
13.25
(29
)
Net transportation expenses (3)
Oil and NGLs ($/bbl)
5.54
4.95
12
3.46
4.10
(16
)
Natural gas ($/mcf)
0.76
0.81
(6
)
0.73
1.12
(35
)
Oil equivalent ($/boe)
5.01
4.92
2
4.04
5.75
(30
)
Operating netback (loss) (3)
Oil and NGLs ($/bbl)
53.23
47.98
11
52.36
45.69
15
Natural gas ($/mcf)
(0.07
)
0.51
(114
)
(0.38
)
(0.64
)
(41
)
Oil equivalent ($/boe)
24.46
24.78
(1
)
17.84
14.25
25
Depletion and depreciation ($/boe)
(10.76
)
(12.18
)
(12
)
(13.59
)
(14.93
)
(9
)
General and administrative expenses ($/boe)
(15.46
)
(10.77
)
44
(14.34
)
(27.08
)
(47
)
Share based compensation ($/boe)
(7.08
)
(16.31
)
(57
)
(11.12
)
(23.49
)
(53
)
Loss on lease termination ($/boe)
(2.02
)
–
100
(0.57
)
–
100
Finance expense ($/boe)
(18.02
)
(1.28
)
1,308
(6.33
)
(3.09
)
105
Finance income ($/boe)
3.65
10.01
(64
)
8.23
18.75
(56
)
Unutilized transportation ($/boe)
(3.88
)
(3.08
)
26
(5.37
)
(6.65
)
(19
)
Net loss ($/boe)
(29.11
)
(8.83
)
230
(25.25
)
(42.24
)
(40
)
(1) See ‘Oil and Gas Terms’ section.
(2) See ‘Product Types’ section.
(3) See ‘Non-GAAP and Other Financial Measures’ section.
Selected financial and operational information outlined in this news release should be read in conjunction with Coelacanth’s audited financial statements and related Management’s Discussion and Analysis (‘MD&A’) for the year ended December 31, 2024, which are available for review under the Company’s profile on SEDAR+ at www.sedarplus.ca.
OPERATIONS UPDATE
In Q4 2024, Coelacanth achieved two more significant milestones in its vision of moving the Two Rivers Montney Project from a large Montney land block to a proven resource with decades of inventory.
In 2022 and 2023, Coelacanth was able to prove productivity in the Lower Montney over a significant portion of lands at Two Rivers that allowed for the decision to build-out infrastructure and to continue pad drilling at Two Rivers East. During 2024, Coelacanth completed the licensing phase of the infrastructure and started construction while also continuing to develop the Montney resource.
In Q4 2024, Coelacanth was able to substantially complete all pipelines required for its 5-19 pad that connected it from the pad to the future facility and then on to a midstream gathering system. Concurrently, Coelacanth completed a successful Upper Montney well at Two Rivers East and changed the completion design in the Lower Montney on the 5-19 pad. The Upper Montney completion proved significant productivity (previously announced test rate of 1,136 boe/d) (1) in a zone that can be mapped over a significant portion of Coelacanth’s lands and should materially increase drilling inventory. The new Lower Montney completions yielded increased overall test rates as well as increasing the oil percentage (3-well average test rates previously announced at 1,624 boe/d with 61% light oil) (1) pointing to potentially higher per-well recoveries of oil and gas and corresponding per-well values than previously estimated.
Construction of the facility continued throughout Q1 2025 and is now substantially complete. With 9 wells and over 11,000 boe/d (1) of test production waiting on completion of the facility, we anticipate yet another major milestone will be reached imminently. We look forward to reporting updates on the Two Rivers East project as new developments arise.
(1) See ‘Test Results and Initial Production Rates’ section for more details.
OIL AND GAS TERMS
The Company uses the following frequently recurring oil and gas industry terms in the news release:
Liquids
Bbls
Barrels
Bbls/d
Barrels per day
NGLs
Natural gas liquids (includes condensate, pentane, butane, propane, and ethane)
Condensat
Pentane and heavier hydrocarbons
Natural Gas
Mcf
Thousands of cubic feet
Mcf/d
Thousands of cubic feet per day
MMcf/d
Millions of cubic feet per day
MMbtu
Million of British thermal units
MMbtu/d
Million of British thermal units per day
Oil Equivalent
Boe
Barrels of oil equivalent
Boe/d
Barrels of oil equivalent per day
Disclosure provided herein in respect of a boe may be misleading, particularly if used in isolation. A boe conversion rate of six thousand cubic feet of natural gas to one barrel of oil equivalent has been used for the calculation of boe amounts in the news release. This boe conversion rate is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
NON-GAAP AND OTHER FINANCIAL MEASURES
This news release refers to certain measures that are not determined in accordance with IFRS (or ‘GAAP’). These non-GAAP and other financial measures do not have any standardized meaning prescribed under IFRS and therefore may not be comparable to similar measures presented by other entities. The non-GAAP and other financial measures should not be considered alternatives to, or more meaningful than, financial measures that are determined in accordance with IFRS as indicators of the Company’s performance. Management believes that the presentation of these non-GAAP and other financial measures provides useful information to shareholders and investors in understanding and evaluating the Company’s ongoing operating performance, and the measures provide increased transparency to better analyze the Company’s performance against prior periods on a comparable basis.
Non-GAAP Financial Measures
Adjusted funds flow (used)
Management uses adjusted funds flow (used) to analyze performance and considers it a key measure as it demonstrates the Company’s ability to generate the cash necessary to fund future capital investments and abandonment obligations and to repay debt, if any. Adjusted funds flow (used) is a non-GAAP financial measure and has been defined by the Company as cash flow from (used in) operating activities excluding the change in non-cash working capital related to operating activities, movements in restricted cash deposits and expenditures on decommissioning obligations. Management believes the timing of collection, payment or incurrence of these items involves a high degree of discretion and as such may not be useful for evaluating the Company’s cash flows. Adjusted funds flow (used) is reconciled from cash flow from (used) in operating activities as follows:
Three Months Ended
Year Ended
December 31
December 31
($000s)
2024
2023
2024
2023
Cash flow from (used in) operating activities
3,157
(404
)
2,203
(4,234
)
Add (deduct):
Decommissioning expenditures
161
206
1,427
1,883
Change in restricted cash deposits
(5,361
)
–
(2,376
)
(784
)
Change in non-cash working capital
2,425
1,948
261
2,802
Adjusted funds flow (used) (non-GAAP)
382
1,750
1,515
(333
)
Net transportation expenses
Management considers net transportation expenses an important measure as it demonstrates the cost of utilized transportation related to the Company’s production. Net transportation expenses is calculated as transportation expenses less unutilized transportation and is calculated as follows:
Three Months Ended
Year Ended
December 31
December 31
($000s)
2024
2023
2024
2023
Transportation expenses
887
680
3,313
1,930
Unutilized transportation
(387
)
(262
)
(1,891
)
(1,035
)
Net transportation expenses (non-GAAP)
500
418
1,422
895
Operating netback
Management considers operating netback an important measure as it demonstrates its profitability relative to current commodity prices. Operating netback is calculated as oil and natural gas sales less royalties, operating expenses, and net transportation expenses and is calculated as follows:
Three Months Ended
Year Ended
December 31
December 31
($000s)
2024
2023
2024
2023
Oil and natural gas sales
4,544
4,204
13,736
6,663
Royalties
(820
)
(866
)
(2,698
)
(1,489
)
Operating expenses
(786
)
(813
)
(3,335
)
(2,062
)
Net transportation expenses
(500
)
(418
)
(1,422
)
(895
)
Operating netback (non-GAAP)
2,438
2,107
6,281
2,217
Capital expenditures
Coelacanth utilizes capital expenditures as a measure of capital investment on property, plant, and equipment, exploration and evaluation assets and property acquisitions compared to its annual budgeted capital expenditures. Capital expenditures are calculated as follows:
Three Months Ended
Year Ended
December 31
December 31
($000s)
2024
2023
2024
2023
Capital expenditures – property, plant, and equipment
233
4,584
1,206
26,928
Capital expenditures – exploration and evaluation assets
64,719
30,072
83,291
47,685
Capital expenditures (non-GAAP)
64,952
34,656
84,497
74,613
Capital Management Measures
Adjusted working capital (deficiency)
Management uses adjusted working capital (deficiency) as a measure to assess the Company’s financial position. Adjusted working capital is calculated as current assets and restricted cash deposits less current liabilities, excluding the current portion of decommissioning obligations.
($000s)
December 31, 2024
December 31, 2023
Current assets
11,579
87,616
Less:
Current liabilities
(37,234
)
(28,754
)
Working capital (deficiency)
(25,655
)
58,862
Add:
Restricted cash deposits
4,900
6,784
Current portion of decommissioning obligations
2,118
1,943
Adjusted working capital (deficiency) (Capital management measure)
(18,637
)
67,589
Non-GAAP Financial Ratios
Adjusted Funds Flow (Used) per share
Adjusted funds flow (used) per share is a non-GAAP financial ratio, calculated using adjusted funds flow (used) and the same weighted average basic and diluted shares used in calculating net loss per share.
Net transportation expenses per boe
The Company utilizes net transportation expenses per boe to assess the per unit cost of utilized transportation related to the Company’s production. Net transportation expenses per boe is calculated as net transportation expenses divided by total production for the applicable period.
Operating netback per boe
The Company utilizes operating netback per boe to assess the operating performance of its petroleum and natural gas assets on a per unit of production basis. Operating netback per boe is calculated as operating netback divided by total production for the applicable period.
Supplementary Financial Measures
The supplementary financial measures used in this news release (primarily average sales price per product type and certain per boe and per share figures) are either a per unit disclosure of a corresponding GAAP measure, or a component of a corresponding GAAP measure, presented in the financial statements. Supplementary financial measures that are disclosed on a per unit basis are calculated by dividing the aggregate GAAP measure (or component thereof) by the applicable unit for the period. Supplementary financial measures that are disclosed on a component basis of a corresponding GAAP measure are a granular representation of a financial statement line item and are determined in accordance with GAAP.
PRODUCT TYPES
The Company uses the following references to sales volumes in the news release:
Natural gas refers to shale gas.
Oil and condensate refers to condensate and tight oil combined.
Other NGLs refers to butane, propane and ethane combined.
Oil and NGLs refers to tight oil and NGLs combined.
Oil equivalent refers to the total oil equivalent of shale gas, tight oil, and NGLs combined, using the conversion rate of six thousand cubic feet of shale gas to one barrel of oil equivalent as described above.
The following is a complete breakdown of sales volumes for applicable periods by specific product types of shale gas, tight oil, and NGLs:
Three Months Ended
Year Ended
December 31
December 31
Sales Volumes by Product Type
2024
2023
2024
2023
Condensate (bbls/d)
22
12
32
7
Other NGLs (bbls/d)
29
28
35
16
NGLs (bbls/d)
51
40
67
23
Tight oil (bbls/d)
451
407
287
132
Condensate (bbls/d)
22
12
32
7
Oil and condensate (bbls/d)
473
419
319
139
Other NGLs (bbls/d)
29
28
35
16
Oil and NGLs (bbls/d)
502
447
354
155
Shale gas (mcf/d)
3,490
2,858
3,648
1,624
Natural gas (mcf/d)
3,490
2,858
3,648
1,624
Oil equivalent (boe/d)
1,084
923
962
426
TEST RESULTS AND INITIAL PRODUCTION RATES
The 5-19 Lower Montney well was production tested for 9.4 days and produced at an average rate of 377 bbl/d oil and 2,202 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.
The A5-19 Basal Montney well was production tested for 5.9 days and produced at an average rate of 117 bbl/d oil and 630 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.
The B5-19 Upper Montney well was production tested for 6.3 days and produced at an average rate of 92 bbl/d oil and 2,100 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.
The C5-19 Lower Montney well was production tested for 5.8 days and produced at an average rate of 736 bbl/d oil and 2,660 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.
The D5-19 Lower Montney well was production tested for 12.6 days and produced at an average rate of 170 bbl/d oil and 580 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.
The E5-19 Lower Montney well was production tested for 11.4 days and produced at an average rate of 312 bbl/d oil and 890 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure was stable, and production was starting to decline.
The F5-19 Lower Montney well was production tested for 4.9 days and produced at an average rate of 728 bbl/d oil and 1,607 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.
The G5-19 Lower Montney well was production tested for 7.1 days and produced at an average rate of 415 bbl/d oil and 1,489 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.
The H5-19 Lower Montney well was production tested for 8.1 days and produced at an average rate of 411 bbl/d oil and 1,166 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure was stable and production was starting to decline.
A pressure transient analysis or well-test interpretation has not been carried out on these nine wells and thus certain of the test results provided herein should be considered to be preliminary until such analysis or interpretation has been completed. Test results and initial production rates disclosed herein, particularly those short in duration, may not necessarily be indicative of long-term performance or of ultimate recovery.
Any references to peak rates, test rates, IP30, IP90, IP180 or initial production rates or declines are useful for confirming the presence of hydrocarbons, however, such rates and declines are not determinative of the rates at which such wells will continue production and decline thereafter and are not indicative of long-term performance or ultimate recovery. IP30 is defined as an average production rate over 30 consecutive days, IP90 is defined as an average production rate over 90 consecutive days and IP180 is defined as an average production rate over 180 consecutive days. Readers are cautioned not to place reliance on such rates in calculating aggregate production for the Company.
FORWARD-LOOKING INFORMATION
This document contains forward-looking statements and forward-looking information within the meaning of applicable securities laws. The use of any of the words ‘expect’, ‘anticipate’, ‘continue’, ‘estimate’, ‘may’, ‘will’, ‘should’, ‘believe’, ‘intends’, ‘forecast’, ‘plans’, ‘guidance’ and similar expressions are intended to identify forward-looking statements or information.
More particularly and without limitation, this news release contains forward-looking statements and information relating to the Company’s oil and condensate, other NGLs, and natural gas production, capital programs, and adjusted working capital (deficiency). The forward-looking statements and information are based on certain key expectations and assumptions made by the Company, including expectations and assumptions relating to prevailing commodity prices and exchange rates, applicable royalty rates and tax laws, future well production rates, the performance of existing wells, the success of drilling new wells, the availability of capital to undertake planned activities, and the availability and cost of labour and services.
Although the Company believes that the expectations reflected in such forward-looking statements and information are reasonable, it can give no assurance that such expectations will prove to be correct. Since forward-looking statements and information address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results may differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, the risks associated with the oil and gas industry in general such as operational risks in development, exploration and production, delays or changes in plans with respect to exploration or development projects or capital expenditures, the uncertainty of estimates and projections relating to production rates, costs, and expenses, commodity price and exchange rate fluctuations, marketing and transportation, environmental risks, competition, the ability to access sufficient capital from internal and external sources and changes in tax, royalty, and environmental legislation. The forward-looking statements and information contained in this document are made as of the date hereof for the purpose of providing the readers with the Company’s expectations for the coming year. The forward-looking statements and information may not be appropriate for other purposes. The Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.
Coelacanth is an oil and natural gas company, actively engaged in the acquisition, development, exploration, and production of oil and natural gas reserves in northeastern British Columbia, Canada.
Further Information
For additional information, please contact:
Coelacanth Energy Inc.
Suite 2110, 530 – 8th Avenue SW
Calgary, Alberta T2P 3S8
Phone: (403) 705-4525
www.coelacanth.ca
Mr. Robert J. Zakresky
President and Chief Executive Officer
Mr. Nolan Chicoine
Vice President, Finance and Chief Financial Officer
Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.
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