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Brunswick Exploration Inc. (TSX-V: BRW, OTCQB: BRWXF; ‘ BRW ‘ or the ‘ Company ‘) is pleased to report the first results from the 2025 Mirage winter drilling campaign where it drilled an additional twenty-four holes targeting extensions of known mineralized zones. The Mirage Project is located in the Eeyou Istchee-James Bay region of Quebec, approximately 40 kilometers south of the Trans-Taiga Road. This release focuses on the Central Zone including the MR-6, MR-3 dykes and Stacked Dyke area where BRW has continued to intersect wide and well mineralized intervals along strike and at depth.

Highlights include:

  • Significant interval of 36 meters at 1.51% Li2O in hole MR-24-102 within the Stacked Dyke area extending mineralization to the south-east and where an additional 13 dykes measuring between 1.3 and 9.35 meters were intercepted in the same hole.
  • New interval at the MR-6 Dyke with 1.32% Li2O over 28 meters in hole MR-24-101 extending the dyke to the northwest.
  • The MR-3, MR-6 and staked dyke system can now be traced together into a major swarm of spodumene bearing pegmatites covering a surface area of over 1,000 meters by up to 450m.
  • A total of 24 drill holes prioritizing near surfaces mineralization in the extension of the staked dyke area were completed during the winter. Assays are pending for a further 16 holes.

Mr. Killian Charles, President and CEO of BRW, commented: ‘To date, every drill campaign has demonstrated the significant exploration upside at Mirage and these first results from our winter 2025 campaign are no different. We have successfully extended the MR-6 pegmatite and continue to rapidly add considerable intercepts in the neighboring Stacked Dyke area. Interestingly, this high potential target area has continued to return multiple significant mineralized intercepts over the entirety of each drill hole and the Stacked Dyke area remains open in multiple directions.

Brunswick Exploration remains one of the most active lithium exploration companies globally and looks forward to releasing more drill results from Mirage and the restart of prospecting in Greenland. With its unique portfolio, the Company expects to have a milestone rich year.’

Mirage Project Drilling Overview

The Mirage Project comprises 427 claims located roughly 40 kilometers south of the Trans-Taiga Highway in Quebec’s James Bay region and 34 kilometers northeast of Winsome Resources’ Adina Project.

The 2025 winter drilling campaign focused on extending the mineralized Stacked Dyke area to the northeast. Highlights discussed in this release are shown in Table 1 and Figure 1. Collars are shown in Table 2.

Figure 1 : Central Zone of the Mirage Project

Figure 1: Central Zone of the Mirage Project

The holes MR-25-96 and MR-25-98 extended the MR-3 dyke 150m to the South with 0.79% Li2O over 12.2 meters from 55.8 meters to 68 meters and 1.26% Li2O over 7 meters from 176 meters to 183 meters. The hole MR-25-95 also confirmed the present of MR-3 and intersect a new dyke from 123.9 to 132 meters that returned 0.76% Li2O over 8.31 meters. This new shallow dipping mineralized pegmatite is located between MR-3 and MR-6 and is open in all directions. From 290 to 307 meters, the hole MR-25-95 holes also intersected three mineralized dykes that could be extensions to MR-6 at depth, dipping to the east.

The hole MR-25-102 extends the Staked Dyke area to the south with 14 mineralized dykes intercepted with the largest grading 1.51% Li2O over 35.65 meters from 166.6 meters to 202.25 meters. MR-23-32ext was drilled to connect the Stacked Dyke area to MR-6. Multiple dykes were intercepted in this hole and confirmed the presence of three new sub horizontal dykes under MR-6 with the largest returning 1.02% Li2O over 7.75 meters from 158.25 meters to 166 meters.

MR-25-101 confirmed the plunge to the north of MR-6 with an intercept of 28 meters at 1.32% Li2O from 173 meters to 201 meters and extends the MR-6 pegmatite by 100 meters. The hole MR-25-99 and MR-25-100 also intercepted the MR-6 dyke over 14.3 meters and 19.4 meters but showed signs of heavy alteration and no spodumene was identified.

Table 1 : 2025 Drilling Program Mentioned in this Release

Hole ID From (m) To (m) Length (m) Li2O (%)
MR-23-32-ext 143.55 145.55 2.00 2.26
147.55 150.00 2.45 1.41
158.25 166.00 7.75 1.02
MR-25-95 49.50 56.75 7.25 0.55
123.90 132.00 8.10 0.79
225.25 228.25 3.00 1.61
290.00 291.00 1.00 1.44
299.00 300.90 1.90 1.20
303.50 307.20 2.70 1.33
MR-25-96 55.80 68.00 12.20 0.79
147.60 150.90 3.30 0.90
160.55 163.20 2.65 0.27
MR-25-97 18.40 23.20 4.80 1.25
MR-25-98 176.00 183.00 7.00 1.26
MR-25-101 173.00 201.00 28.00 1.32
MR-25-102 17.25 21.00 3.75 1.33
65.70 69.00 3.30 2.66
96.15 105.50 9.35 0.75
117.50 119.50 2.00 1.34
132.75 134.65 1.90 1.81
138.90 140.30 1.40 0.88
157.60 159.85 2.25 1.10
166.60 202.25 35.65 1.51
212.20 214.85 2.65 1.24
239.70 243.60 3.90 1.33
247.95 250.75 2.80 1.74
254.70 256.50 1.80 1.68
292.15 296.10 3.95 1.52
299.00 305.10 6.10 1.19


Table 2
: 2025 Drilling Collars Mentioned in this Release

Hole ID Azimut Dip Length (m) UTM NAD83 z18 East UTM NAD83 z18 North
MR-23-32-ext 320 -73 162 683263 5941204
MR-25-95 30 -60 369 682821 5940489
MR-25-96 30 -90 207 682821 5940989
MR-25-97 320 -65 48 683503 5941233
MR-25-98 315 -60 301.45 682784 5940878
MR-25-99 320 -90 168 682912 5941336
MR-25-100 320 -90 201 682832 5941326
MR-25-101 320 -60 285 682912 5941336


QAQC

All drill core samples were collected under the supervision of BRW employees and contractors. The drill core was transported by helicopter and by truck from the drill platform to the core logging facility in Val-d’Or. Each core was then logged, photographed, tagged, and split by diamond saw before being sampled. All pegmatite intervals were sampled at approximately 1-meter intervals to ensure representativity. Samples were bagged; duplicated on reject, blanks and certified reference materials for lithium were inserted every 20 samples. Samples were bagged and groups of samples were placed in larger bags, sealed with numbered tags, in order to maintain a chain of custody. The sample bags were transported from the BRW contractor facility to the AGAT laboratory in Val-d’Or. All sample preparation and analytical work was performed by AGAT by sodium peroxide fusion with ICP-OES and ICP-MS finish. All results passed the QA/QC screening at the lab and all inserted standard and blanks returned results that were within acceptable limits. All reported drill intersections are calculated based on a lower cutoff grade of 0.3% Li2O, with maximum internal dilution of 5 meters. Host basalts adjacent to the dykes may grade up to 0.3% Li2O but were excluded from the reported intersections.

Qualified Person

The scientific and technical information contained in this press release has been reviewed and approved by Mr. Simon T. Hébert, VP Development. He is a Professional Geologist registered in Quebec and is a Qualified Person as defined by National Instrument 43-101.

About Brunswick Exploration

Brunswick Exploration is a Montreal-based mineral exploration company listed on the TSX-V under symbol BRW. The Company is focused on grassroots exploration for lithium in Canada, a critical metal necessary to global decarbonization and energy transition. The company is rapidly advancing the most extensive grassroots lithium property portfolio in Canada and Greenland.

Investor Relations/information

Mr. Killian Charles, President and CEO ( info@brwexplo.ca )

Cautionary Statement on Forward-Looking Information

This news release contains ‘forward-looking information’ within the meaning of applicable Canadian securities legislation based on expectations, estimates and projections as at the date of this news release. Forward-looking information involves risks, uncertainties and other factors that could cause actual events, results, performance, prospects and opportunities to differ materially from those expressed or implied by such forward-looking information. Factors that could cause actual results to differ materially from such forward-looking information include, but are not limited to, delays in obtaining or failures to obtain required governmental, environmental or other project approvals; uncertainties relating to the availability and costs of financing needed in the future; changes in equity markets; inflation; fluctuations in commodity prices; delays in the development of projects; the other risks involved in the mineral exploration and development industry; and those risks set out in the Corporation’s public documents filed on SEDAR at www.sedar.com. Although the Corporation believes that the assumptions and factors used in preparing the forward-looking information in this news release are reasonable, undue reliance should not be placed on such information, which only applies as of the date of this news release, and no assurance can be given that such events will occur in the disclosed time frames or at all. The Corporation disclaims any intention or obligation to update or revise any forward-looking information, whether as a result of new information, future events or otherwise, other than as required by law. Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this news release.

A photo accompanying this announcement is available at https://www.globenewswire.com/NewsRoom/AttachmentNg/ea65ea8b-aa40-40d8-9be0-f901db569529

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Heliostar Metals Ltd. (TSXV: HSTR) (OTCQX: HSTXF) (FSE: RGG1) (‘Heliostar’ or the ‘Company’) is pleased to announce that it has appointed Mr. Stephen Soock as Vice President of Investor Relations and Development and Ms. Connie Lillico as Corporate Secretary.

Heliostar CEO, Charles Funk, commented, ‘We are delighted to add Stephen and Connie to our team as we continue to build our capacity. Stephen brings his understanding of institutional banking, sales and project knowledge from his role as an analyst at Stifel. He will lead the Company’s investor relationships and contribute to Heliostar’s strategy for production growth and reduction in our cost of capital. Connie brings a wealth of experience, having helped shepherd First Majestic from an ambitious junior to stable producer. She will lead the Company’s regulatory responsibilities in her role as Corporate Secretary. I would also like to thank Ms. Sheryl Dhillon for her diligent, professional long-term service to the Company as our Corporate Secretary.’

Mr. Soock has been in the mining industry for almost 20 years in both technical and capital markets roles. Prior to joining Heliostar, he was a Brendan Wood ranked sell side research analyst at Stifel. He covered growth and development companies in the precious metals space and brings a robust understanding of value creation from junior gold companies to his new role with Heliostar. Mr. Soock has also worked in various engineering roles at mine sites across Canada, including Vale’s Thompson Nickel operation, Mosaic’s Belle Plaine solution potash mine and Rio Tinto’s Diavik Diamond mine complex. He graduated from Queen’s University with a B.Sc. in Mining Engineering and is a CFA Charterholder.

Ms. Lillico brings 20 years of experience working with publicly traded companies in the mining industry. Ms. Lillico has worked with several TSX, TSX-V and NSYE listed companies and prior to joining Heliostar, Ms. Lillico served as the Corporate Secretary at First Majestic Silver Corp. Ms. Lillico has been involved in all aspects of administration of publicly listed companies including regulatory compliance, corporate governance, continuous disclosure requirements, equity financings, mergers and acquisitions, board and committee matters and shareholder communications.

Further, pursuant to the Company’s Omnibus Equity Incentive Compensation Plan, it has granted 700,000 stock options (‘Options’) at an exercise price of $1.05 and 150,000 restricted share units (each, an ‘RSU’) to employees and consultants of the Company. The Options are exercisable for a period of five years and will vest over the next two years. The RSUs will vest in three equal annual instalments commencing on the first anniversary of the grant date.

About Heliostar Metals Ltd.

Heliostar aims to grow to become a mid-tier gold producer. The Company is focused on increasing production and developing new resources at the La Colorada and San Agustin mines in Mexico, and on developing the 100% owned Ana Paula Project in Guerrero, Mexico.

FOR ADDITIONAL INFORMATION PLEASE CONTACT:

Charles Funk
President and Chief Executive Officer
Heliostar Metals Limited
Email: charles.funk@heliostarmetals.com
Phone: +1 844-753-0045
Rob Grey
Investor Relations Manager
Heliostar Metals Limited
Email: rob.grey@heliostarmetals.com
Phone: +1 844-753-0045

 

Neither 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.

Cautionary Statement Regarding Forward-Looking Information

This news release includes certain ‘Forward-Looking Statements’ within the meaning of the United States Private Securities Litigation Reform Act of 1995 and ‘forward-looking information’ under applicable Canadian securities laws. When used in this news release, the words ‘anticipate’, ‘believe’, ‘estimate’, ‘expect’, ‘target’, ‘plan’, ‘forecast’, ‘may’, ‘would’, ‘could’, ‘schedule’ and similar words or expressions, identify forward-looking statements or information. These forward-looking statements or information relate to, among other things: the Company’s goal of becoming a mid-tier producer.

Forward-looking statements and forward-looking information relating to the terms and completion of the Facility, any future mineral production, liquidity, and future exploration plans are based on management’s reasonable assumptions, estimates, expectations, analyses and opinions, which are based on management’s experience and perception of trends, current conditions and expected developments, and other factors that management believes are relevant and reasonable in the circumstances, but which may prove to be incorrect. Assumptions have been made regarding, among other things, the receipt of necessary approvals, price of metals; no escalation in the severity of public health crises or ongoing military conflicts; costs of exploration and development; the estimated costs of development of exploration projects; and the Company’s ability to operate in a safe and effective manner and its ability to obtain financing on reasonable terms.

These statements reflect the Company’s respective current views with respect to future events and are necessarily based upon a number of other assumptions and estimates that, while considered reasonable by management, are inherently subject to significant business, economic, competitive, political, and social uncertainties and contingencies. Many factors, both known and unknown, could cause actual results, performance, or achievements to be materially different from the results, performance or achievements that are or may be expressed or implied by such forward-looking statements or forward-looking information and the Company has made assumptions and estimates based on or related to many of these factors. Such factors include, without limitation: precious metals price volatility; risks associated with the conduct of the Company’s mining activities in foreign jurisdictions; regulatory, consent or permitting delays; risks relating to reliance on the Company’s management team and outside contractors; risks regarding exploration and mining activities; the Company’s inability to obtain insurance to cover all risks, on a commercially reasonable basis or at all; currency fluctuations; risks regarding the failure to generate sufficient cash flow from operations; risks relating to project financing and equity issuances; risks and unknowns inherent in all mining projects, including the inaccuracy of reserves and resources, metallurgical recoveries and capital and operating costs of such projects; contests over title to properties, particularly title to undeveloped properties; laws and regulations governing the environment, health and safety; the ability of the communities in which the Company operates to manage and cope with the implications of public health crises; the economic and financial implications of public health crises, ongoing military conflicts and general economic factors to the Company; operating or technical difficulties in connection with mining or development activities; employee relations, labour unrest or unavailability; the Company’s interactions with surrounding communities; the Company’s ability to successfully integrate acquired assets; the speculative nature of exploration and development, including the risks of diminishing quantities or grades of reserves; stock market volatility; conflicts of interest among certain directors and officers; lack of liquidity for shareholders of the Company; litigation risk; and the factors identified under the caption ‘Risk Factors’ in the Company’s public disclosure documents. Readers are cautioned against attributing undue certainty to forward-looking statements or forward-looking information. Although the Company has attempted to identify important factors that could cause actual results to differ materially, there may be other factors that cause results not to be anticipated, estimated or intended. The Company does not intend, and does not assume any obligation, to update these forward-looking statements or forward-looking information to reflect changes in assumptions or changes in circumstances or any other events affecting such statements or information, other than as required by applicable law.

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To view the source version of this press release, please visit https://www.newsfilecorp.com/release/249614

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An aversion to tax increases has long been one of the Republican Party’s core pillars, but tradition was upended in recent weeks as discussions of a potential new millionaires’ tax hike hit Capitol Hill.

It’s baffled some members of the GOP’s old guard, though Republican operatives who spoke with Fox News Digital were less surprised. They said those conversations were largely ushered in by the party’s growing populist wing.

‘I’m not sure if I’m surprised anymore, because the party has changed so much in just a short period of time. But it is noteworthy,’ longtime GOP strategist Doug Heye told Fox News Digital. 

Heye recalled his time as a senior House leadership aide in 2012, when a Republican proposal for a uniform tax rate for people making under $1 million per year was blown up ‘by a rebellion within our own ranks’ over raising taxes.

‘It all exploded in our faces,’ he said. ‘And now this is what more and more of those Republicans who rejected the idea in 2012 want to do.’

Sources told Fox News Digital this month that the White House was socializing a plan among Republicans to create a new 40% tax bracket for people making more than $1 million.

Various reported plans floated among House Republicans included raising taxes on the ultra-wealthy to rates between 38% and 40%. 

Former House Speaker Newt Gingrich has been seeking to quash that this week, even posting a purported message from President Donald Trump himself on X that said, ‘If you can do without it, you’re probably better off trying to do so.’

Fox News Digital reached out to the White House on Wednesday morning for comment on Gingrich’s note, including the context of the message and why Trump described that he would ‘love’ increasing taxes, but did not receive a reply.

The top income tax rate is currently about 37% on $609,351 in earnings for a single person or $731,201 for married couples. It was lowered from just over 39% by Trump’s 2017 Tax Cuts and Jobs Act.

‘The politics are good for raising taxes on wealthy Americans,’ said John Feehery, a partner at EFB Advocacy and veteran of House GOP leadership staff. ‘The downside is it does have an impact on economic growth. So if you want the cheap political score, that’s the way to go. On the other hand, if you want a solid economy where people are working, you want to be careful on how you do that.’

Asked if the discussions caught him off guard, Feehery said, ‘I’m not surprised by it because Trump is such a populist, and he has a lot of folks who are populist.’

He signaled the appeal of higher taxes for the wealthy was born from that shift.

‘If you look at the constituencies, the biggest constituency, it’s really interesting because the parties have kind of changed,’ he continued. ‘It used to be the country-club Republicans and working-class Democrats; now it’s working-class Republicans and country-club Democrats.’

Heye said when asked about the increase in tax hike talks, ‘I think it’s a mixture of Trump and populism.’

‘Raising taxes used to be an anathema to Republicans, and you know, when George Bush did it after saying ‘Read my lips,’ that was the beginning of the end of his presidency,’ Heye said. ‘That world just doesn’t exist anymore.’

House GOP leaders have publicly made clear that they’re opposed to raising taxes on anyone. But Republicans must find a way to pass Trump’s budget, including new tax policies eliminating duties on tipped and overtime wages, while meeting conservatives’ demand to cut at least $1.5 trillion in government spending to make up for it.

House Freedom Caucus Chair Andy Harris, R-Md., previously signaled that he is open to the idea if spending cuts can’t be reached by other means.

‘What I’d like to do is, I’d actually like to find spending reductions elsewhere in the budget, but if we can’t get enough spending reductions, we’re going to have to pay for our tax cuts,’ Harris told ‘Mornings with Maria’ on FOX Business last week.

‘Before the Tax Cuts and Jobs Act, the highest tax bracket was 39.6%; it was less than $1 million. Ideally, what we could do – again, if we can’t find spending reductions – we say, ‘OK, let’s restore that higher bracket, let’s set it at maybe $2 million income and above’ to help pay for the rest of the president’s agenda.’

Rep. Dan Meuser, R-Pa., similarly floated raising the top tax bracket to 38.6%.

He later told Fox News Digital in a statement, ‘I believe we must help the president deliver on his promise of a tax and regulatory plan that supports pro-American economic and manufacturing growth, and delivers for the vast majority of Americans – while creating savings and promoting fiscal responsibility. Any adjustments in taxes to accomplish these goals should be considered.’

Both Meuser and Harris declined to provide more comment for this story.

Former Vice President Mike Pence, who refers to the 2017 tax cuts as the ‘Trump-Pence tax cuts,’ last week urged House Republicans to stand firm against raising taxes on the country’s top earners and to make the 2017 tax cuts permanent. 

One House GOP lawmaker told Fox News Digital last week that reaction among their colleagues to possible tax hikes was ‘mixed.’

But a former Republican member was skeptical on Wednesday.

‘Raising taxes is a short-term high, which ultimately does more harm than good,’ the former House Republican said. ‘This strategy is contrary to conservative values.’

Meanwhile, Marc Goldwein, senior policy director at the nonpartisan Committee for a Responsible Federal Budget, said it was ‘healthy’ that lawmakers are entertaining fiscal ideas outside their party norms.

He was wary about the push for a tax hike, however.

‘I’m not a fan of doing things that look fiscally good at the same time that you’re doing things that actually are fiscally bad … on top of that, I don’t think raising tax rates is the best way to raise revenue,’ Goldwein said. ‘But with those two things said, I think it is very healthy move that the GOP kind of is talking about that rates actually can go in both directions.’

Fox News Digital reached out to Gingrich for an interview for this story but did not receive a response.

Fox News Digital’s Emma Colton contributed to this report.


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Sen. John Fetterman, D-Pa., is continuing to advocate for the destruction of Iran’s nuclear program.

‘Waste that s—,’ the lawmaker declared to the Washington Free Beacon. ‘You’re never going to be able to negotiate with that kind of regime that has been destabilizing the region for decades already, and now we have an incredible window, I believe, to do that, to strike and destroy Iran’s nuclear facilities.’

‘Years ago, I completely understood why Trump withdrew from the Obama deal. Today, I can’t understand why Trump would negotiate with this diseased regime. The negotiations should be comprised of 30,000-pound bombs and the IDF,’ Fetterman noted, according to the outlet. The IDF is the Israel Defense Forces.

Fox News Digital reached out to Fetterman’s office to request a comment from the senator on Thursday morning but did not receive a response by the time of publication.

The lawmaker, who is a staunch supporter of Israel, had already been calling for the elimination of Iran’s nuclear program.

Fetterman declared last week in a post on X, ‘The only purpose of Iran’s nuclear program is to create weapons. We can’t allow that or negotiate with this regime. Provide our comprehensive military support and whatever else Israel requires to destroy Iran’s capabilities.’

Expert calls out Iran

President Donald Trump noted earlier this week that he had spoken to Israeli Prime Minister Benjamin Netanyahu.

‘I’ve just spoken to Prime Minister of Israel, Bibi Netanyahu, relative to numerous subjects including Trade, Iran, etc. The call went very well – We are on the same side of every issue,’ Trump said in a Tuesday post on Truth Social.

Israel PM Netanyahu gives Sen. John Fetterman (D-Pa.) a silver pager commemorating operation against Hezbollah

Fetterman declared in part of an X post in January, ‘Whatever remains of Iran’s nuclear program needs to be destroyed and I fully support efforts to do so.’


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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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Coelacanth Energy Inc. (TSXV: CEI) (‘Coelacanth’ or the ‘Company’) is pleased to announce its 2024 year-end reserves as independently evaluated by GLJ Ltd. (‘GLJ’) effective December 31, 2024 (the ‘GLJ Report’ or the ‘Report’), in accordance with National Instrument 51-101 (‘NI 51-101’) and the Canadian Oil and Gas Evaluation (‘COGE’) Handbook. All dollar figures are Canadian dollars unless otherwise noted.

Introduction

During 2024, Coelacanth drilled an additional 3 Lower Montney wells on its 5-19 pad and started the construction of pipelines and facilities to allow for the production of all 9 wells on the 5-19 pad to come on production in Q2 2025. The 9 wells consist of 7 Lower Montney wells, 1 Upper Montney well and 1 Basal Montney well that have tested over 11,000 boe/d (flush production) (1). On completion of phase 1 of the facility in May 2025, Coelacanth will have capacity to produce 30.0 mmcf/d of gas plus the concurrent oil production for a combined capacity of approximately 7,500-8,000 boe/d. Phase 2 (adding compression) is scheduled for Q4 2025 and will double capacity.

Coelacanth almost doubled its reserves from 2023 while still only having recognized reserves on less than 10% of its 150 section Montney land block at Two Rivers. A total of 23 combined wells and locations are included in the Report comprised of 13 drilled and completed Montney wells plus 10 Montney undeveloped locations. The 13 existing wells include 8 Lower Montney wells, 4 Upper Montney wells, and 1 Basal Montney well. All 10 undeveloped locations booked were Lower Montney leaving potential to book additional Upper and Basal Montney wells on the same lands. Coelacanth believes it has been conservative in its bookings and, over time, will be able to expand the current reserve base to cover a greater portion of the land base.

The Report includes a total of $148.3 million of future development capital (‘FDC’) of which $33.5 million is in Jan-May of 2025 for phase 1 of the facility. By the end of May, the capital for phase 1 of the facility will have been spent and all of the proved developed non-producing and probable developed non-producing reserves will change to producing status. These adjustments will have a material effect on the Report given the FDC for phase 1 of the facility will be removed (thereby increasing the overall value) and the producing portion of the Report will increase dramatically with wells coming on production. Coelacanth is planning to engage GLJ to provide a mid-year update of the Report to better illustrate the magnitude of the changes.

Coelacanth’s business plan for the Two Rivers Montney Project includes:

  • Delineating and establishing production on multiple Montney zones over its extensive land base.
  • Accelerating production through pad drilling once initial infrastructure is complete.
  • Licensing and constructing additional facilities and pipelines to process future production additions.

Coelacanth is currently:

  • Finalizing the construction of Two Rivers East facility to accommodate the 5-19 pad production.
  • Licensing additional pads for future development.
  • Completing a third-party resource study to aid in well spacing and completion design as well as future delineation.
  • Completing a detailed review of Two Rivers for well development and future infrastructure requirements.

Coelacanth is excited to initiate its business plan to systematically develop the property, establish the ultimate reserve recoveries and move the established recoverable resource from land to its established producing reserve base.

Reserve Highlights

Coelacanth is pleased to report material increases in both reserves and value:

  • Increased Total Proved plus Probable reserves by 95% to 27.5 million boe from 14.1 million boe.
  • Increased Total Proved reserves by 63% to 17.1 million boe from 10.5 million boe.
  • Increased Total Proved plus Probable Reserve value (net present value before taxes, discounted at 10%) by 155% to $239.6 million from $93.9 million.

Notes:
(1) See ‘Test Results and Initial Production Rates’.

Reserves Summary

Coelacanth’s December 31, 2024 reserves as prepared by GLJ effective December 31, 2024 and based on the GLJ (2025-01) future price forecast are as follows: (1,4)

Working Interest Reserves (2) Tight Oil
(Mbbl)
Shale
Natural Gas
(Mmcf)
NGLs
(Mbbl)
Total Oil Equivalent
(Mboe) (3)
Proved
Producing 344 8,097 150 1,843
Developed non-producing 1,874 38,862 720 9,071
Undeveloped 1,137 27,324 506 6,197
Total proved 3,355 74,283 1,376 17,111
Probable 2,154 44,543 825 10,403
Total proved & probable 5,509 118,826 2,201 27,515

 

Notes:
(1) Numbers may not add due to rounding.
(2) ‘Working Interest’ or ‘Gross’ reserves means Coelacanth’s working interest (operating and non-operating) share before deduction of royalties and without including any royalty interest of Coelacanth.
(3) Oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil.
(4) Disclosure of Net reserves are included in Company’s Annual Information Form (‘AIF’) dated April 23, 2025 filed on SEDAR+ at www.sedarplus.ca. ‘Net’ reserves means Coelacanth’s working interest (operated and non-operated) share after deduction of royalties, plus Coelacanth’s royalty interest in reserves.

Reserves Values

The estimated future net revenues before taxes associated with Coelacanth’s reserves effective December 31, 2024 and based on the GLJ (2025-01) future price forecast are summarized in the following table: (1,2,3,4)

Discount factor per year
($000s) 0% 5% 10% 15% 20%
Proved
Producing 21,615 17,655 14,827 12,765 11,220
Developed non-producing 131,346 97,179 74,105 57,825 45,878
Undeveloped 93,068 63,389 44,903 32,689 24,196
Total proved 246,030 178,224 133,834 103,279 81,294
Probable 221,362 147,285 105,806 80,431 63,701
Total proved & probable 467,391 325,509 239,640 183,710 144,995

 

Notes:
(1) Numbers may not add due to rounding.
(2) The estimated future net revenues are stated prior to provision for interest, debt service charges or general administrative expenses and after deduction of royalties, operating costs, estimated well abandonment and reclamation costs and estimated future capital expenditures.
(3) The estimated future net revenue contained in the table does not necessarily represent the fair market value of the reserves. There is no assurance that the forecast price and cost assumptions contained in the GLJ Report will be attained and variations could be material. The recovery and reserve estimates described herein are estimates only. Actual reserves may be greater or less than those calculated.
(4) The after-tax present values of future net revenue attributed to Coelacanth’s reserves are included in Company’s AIF dated April 23, 2025 filed on SEDAR+ at www.sedarplus.ca.

Price Forecast

The GLJ (2025-01) price forecast is as follows:

Year WTI Oil @ Cushing
($US / Bbl)
Edmonton Light Oil
($Cdn / Bbl)
AECO Natural Gas
($Cdn / Mmbtu)
Chicago Natural Gas
($US / Mmbtu)
Foreign Exchange
(Cdn$/US$)
2025 71.25 91.33 2.05 2.79 0.7050
2026 73.50 93.32 3.00 3.70 0.7300
2027 76.00 96.45 3.50 4.01 0.7500
2028 78.53 99.82 4.00 4.10 0.7500
2029 80.10 101.80 4.08 4.18 0.7500
2030 81.70 103.84 4.16 4.27 0.7500
2031 83.34 105.92 4.24 4.35 0.7500
2032 85.00 108.04 4.33 4.45 0.7500
2033 86.70 110.20 4.41 4.54 0.7500
2034 88.44 112.40 4.50 4.63 0.7500
Escalate thereafter (1) 2.0% per year 2.0% per year 2.0% per year 2.0% per year

 

Note:
(1) Escalated at two per cent per year starting in 2034 in the January 1, 2025 GLJ price forecast with the exception of foreign exchange, which remains flat.

Reserve Life Index (‘RLI’)

Coelacanth’s RLI presented below is based on estimated Q4 2024 average production of 1,084 boe per day.

Reserve Category RLI
Proved plus Probable Reserves 69.0
Proved Reserves 42.9

 

Reserves Reconciliation

The following summary reconciliation of Coelacanth’s working interest reserves compares changes in the Company’s reserves as at December 31, 2024 to the reserves as at December 31, 2023 based on the GLJ (2025-01) future price forecast: (1,2)

Total Proved Tight Oil  Shale
Natural Gas 
NGLs  Total Oil
Equivalent
  (Mbbl) (Mmcf)  (Mbbl) (Mboe) (3)
Opening balance          2,291       44,784         720       10,475
Discoveries                       –                    –                          –                  –
Extensions and improved recovery            1,212              27,468                 509          6,298
Technical revisions                 (28)             3,663              173         756
Acquisitions               –                  –                         –                    –
Dispositions                    –                    –                            –                           –
Economic factors              (15)            (297)               (1)              (66)
Production                    (105)            (1,335)                (24)           (352)
Closing balance           3,355               74,283           1,376           17,111
         
         
Proved plus Probable Tight Oil Shale
Natural Gas
NGLs Total Oil
Equivalent
  (Mbbl) (Mmcf) (Mbbl) (Mboe) (3)
Opening balance            3,038      60,432                970            14,080
Discoveries                 –                     –             –                       –
Extensions and improved recovery            2,599               56,330              1,043         13,031
Technical revisions               (9)              3,734                 213                     825
Acquisitions                      –               –                 –                      –
Dispositions                      –                         –         –                   –
Economic factors             (13)              (334)                       –             (69)
Production            (105)         (1,335)                   (24)          (352)
Closing balance       5,509         118,826          2,201         27,515​

 

Notes:
(1) Numbers may not add due to rounding.
(2) ‘Working Interest’ or ‘Gross’ reserves means Coelacanth’s working interest (operating and non-operating) share before deduction of royalties and without including any royalty interest of Coelacanth.
(3) Oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil.

Capital Expenditures

Capital allocation by category is as follows:

       
($000s) 2024 2023 2022
Undeveloped land                   765                  1,006          1,164
Acquisitions             765            1,006              1,164
       
Drilling and completion            38,353           61,274              9,009
Facilities and related infrastructure            44,935          12,094         3,689
Geological, geophysical  and other             444             239              42
Exploration and development expenditures          83,732          73,607              12,740
       
Total capital expenditures    84,497   74,613      13,904

 

Finding and Development Costs (‘F&D’) and Finding, Development and Acquisition Costs (‘FD&A’)

Coelacanth has presented FD&A and F&D costs below:

   2024   2023  2022  3 Year Cumulative 
     Proved &
   Proved &    Proved &    Proved &
($000’s, except where noted)  Proved  Probable  Proved  Probable  Proved  Probable  Proved  Probable
                 
                 
Exploration and development expenditures      83,732      83,732      73,607      73,607      12,740      12,740   170,079   170,079
Change in FDC (1)      (1,713)      30,469      90,598      77,759      11,400      33,748   100,285   141,976
F&D costs       82,019   114,201   164,205   151,366      24,140      46,488   270,364   312,055
Acquisitions           765           765        1,006        1,006        1,164        1,164        2,935        2,935
FD&A costs       82,784   114,966   165,211   152,372      25,304      47,652   273,299   314,990
                 
Reserve Additions (Mboe) (2)                
Exploration and development        6,989      13,789        8,637        9,784        1,169        3,400      16,795      26,973
Acquisitions                 –                 –                 –                 –                 –                 –                 –                 –
         6,989      13,789        8,637        9,784        1,169        3,400      16,795      26,973
                 
F&D costs ($/boe)        11.74          8.28        19.01        15.47        20.65        13.67        16.10        11.57
FD&A costs ($/boe)        11.84          8.34        19.13        15.57        21.65        14.02        16.27        11.68

 

Notes:
(1) Future development capital (‘FDC’) expenditures required to recover reserves estimated by GLJ. The aggregate of the exploration and development costs incurred in the most recent financial period and the change during that period in estimated future development costs generally may not reflect total finding and development costs related to reserve additions for that period.
(2) Sum of extensions and improved recovery, technical revisions and economic factors in the reserves reconciliation included above.

For Coelacanth’s full NI 51-101 disclosure related to its 2024 year-end reserves please refer to the Company’s AIF dated April 23, 2025 filed on SEDAR+ at www.sedarplus.ca.

Forward-Looking Information

This news release contains forward-looking statements and forward-looking information within the meaning of applicable securities laws. The use of any of the words ‘expect’, ‘anticipate’, ‘continue’, ‘estimate’, ‘may’, ‘will’, ‘should’, ‘believe’, ‘intends’, ‘forecast’, ‘plans’, ‘guidance’ and similar expressions are intended to identify forward-looking statements or information.

More particularly and without limitation, this document contains forward-looking statements and information relating to the Company’s oil, NGLs and natural gas production and reserves and reserves values, capital programs, and oil, NGLs, and natural gas commodity prices. The forward-looking statements and information are based on certain key expectations and assumptions made by the Company, including expectations and assumptions relating to prevailing commodity prices and exchange rates, applicable royalty rates and tax laws, future well production rates, the performance of existing wells, the success of drilling new wells, the availability of capital to undertake planned activities and the availability and cost of labor and services.

Although the Company believes that the expectations reflected in such forward-looking statements and information are reasonable, it can give no assurance that such expectations will prove to be correct. Since forward-looking statements and information address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results may differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, the risks associated with the oil and gas industry in general such as operational risks in development, exploration and production, delays or changes in plans with respect to exploration or development projects or capital expenditures, the uncertainty of estimates and projections relating to production rates, costs and expenses, commodity price and exchange rate fluctuations, marketing and transportation, environmental risks, competition, the ability to access sufficient capital from internal and external sources and changes in tax, royalty and environmental legislation. The forward-looking statements and information contained in this document are made as of the date hereof for the purpose of providing the readers with the Company’s expectations for the coming year. The forward-looking statements and information may not be appropriate for other purposes. The Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.

Reserves Data

There are numerous uncertainties inherent in estimating quantities of tight oil, shale gas, and NGLs reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth above are estimates only. In general, estimates of economically recoverable tight oil, shale gas, and NGLs reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially.

Individual properties may not reflect the same confidence level as estimates of reserves for all properties due to the effects of aggregation.

This news release contains estimates of the net present value of the Company’s future net revenue from its reserves. Such amounts do not represent the fair market value of the Company’s reserves.

The reserves data contained in this news release has been prepared in accordance with National Instrument 51-101 (‘NI 51-101’). The reserve data provided in this news release presents only a portion of the disclosure required under NI 51-101. All of the required information will be contained in the Company’s Annual Information Form for the year ended December 31, 2024, filed on SEDAR+ at www.sedarplus.ca.

Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical and engineering data; the use of established technology, and specified economic conditions, which are generally accepted as being reasonable. Reserves are classified according to the degree of certainty associated with the estimates as follows:

  • Proved Reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

  • Probable Reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

Industry Metrics

This news release contains metrics commonly used in the oil and natural gas industry. Each of these metrics is determined by the Company as set out below or elsewhere in this news release. These metrics are ‘F&D costs’, ‘FD&A costs’, and ‘reserve-life index’. These metrics do not have standardized meanings and may not be comparable to similar measures presented by other companies. As such, they should not be used to make comparisons.

Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare the Company’s performance over time, however, such measures are not reliable indicators of the Company’s future performance and future performance may not compare to the performance in previous periods.

‘F&D costs’ are calculated by dividing the sum of the total capital expenditures for the year (in dollars) by the change in reserves within the applicable reserves category (in boe). F&D costs, including FDC, includes all capital expenditures in the year as well as the change in FDC required to bring the reserves within the specified reserves category on production.

‘FD&A costs’ are calculated by dividing the sum of the total capital expenditures for the year inclusive of the net acquisition costs and disposition proceeds (in dollars) by the change in reserves within the applicable reserves category inclusive of changes due to acquisitions and dispositions (in boe). FD&A costs, including FDC, includes all capital expenditures in the year inclusive of the net acquisition costs and disposition proceeds as well as the change in FDC required to bring the reserves within the specified reserves category on production.

The Company uses F&D and FD&A as a measure of the efficiency of its overall capital program including the effect of acquisitions and dispositions. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.

‘Reserve life index’ or ‘RLI’ is calculated by dividing the reserves (in boe) in the referenced category by the latest quarter of production (in boe) annualized. The Company uses this measure to determine how long the booked reserves will last at current production rates if no further reserves were added.

BOE Conversions

BOE’s may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf: 1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Abbreviations

Bbl barrel
Mbbl thousands of barrels
MMbtu millions of British thermal units
Mcf thousand cubic feet
MMcf million cubic feet
NGLs natural gas liquids
BOE barrel of oil equivalent
MBOE thousands of barrels of oil equivalent
WTI West Texas Intermediate at Cushing, Oklahoma

 

Test Results and Initial Production Rates

The 5-19 Lower Montney well was production tested for 9.4 days and produced at an average rate of 377 bbl/d oil and 2,202 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.

The A5-19 Basal Montney well was production tested for 5.9 days and produced at an average rate of 117 bbl/d oil and 630 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.

The B5-19 Upper Montney well was production tested for 6.3 days and produced at an average rate of 92 bbl/d oil and 2,100 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.

The C5-19 Lower Montney well was production tested for 5.8 days and produced at an average rate of 736 bbl/d oil and 2,660 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.

The D5-19 Lower Montney well was production tested for 12.6 days and produced at an average rate of 170 bbl/d oil and 580 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.

The E5-19 Lower Montney well was production tested for 11.4 days and produced at an average rate of 312 bbl/d oil and 890 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure was stable, and production was starting to decline.

The F5-19 Lower Montney well was production tested for 4.9 days and produced at an average rate of 728 bbl/d oil and 1,607 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.

The G5-19 Lower Montney well was production tested for 7.1 days and produced at an average rate of 415 bbl/d oil and 1,489 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure and production rates were stable.

The H5-19 Lower Montney well was production tested for 8.1 days and produced at an average rate of 411 bbl/d oil and 1,166 mcf/d gas (net of load fluid and energizing fluid) over that period which includes the initial cleanup where only load water was being recovered. At the end of the test, flowing wellhead pressure was stable and production was starting to decline.

A pressure transient analysis or well-test interpretation has not been carried out on these nine wells and thus certain of the test results provided herein should be considered to be preliminary until such analysis or interpretation has been completed. Test results and initial production rates disclosed herein, particularly those short in duration, may not necessarily be indicative of long-term performance or of ultimate recovery.

Any references to peak rates, test rates, IP30, IP90, IP180 or initial production rates or declines are useful for confirming the presence of hydrocarbons, however, such rates and declines are not determinative of the rates at which such wells will continue production and decline thereafter and are not indicative of long-term performance or ultimate recovery. IP30 is defined as an average production rate over 30 consecutive days, IP90 is defined as an average production rate over 90 consecutive days and IP180 is defined as an average production rate over 180 consecutive days. Readers are cautioned not to place reliance on such rates in calculating aggregate production for the Company.

For further information, please contact:

Coelacanth Energy Inc.
2110, 530 – 8th Ave SW
Calgary, Alberta T2P 3S8
Phone: (403) 705-4525
www.coelacanth.ca

Robert Zakresky
President and Chief Executive Officer

Nolan Chicoine
Vice President, Finance and Chief Financial Officer

Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.

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To view the source version of this press release, please visit https://www.newsfilecorp.com/release/249585

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The Trump administration is warning of ‘serious consequences’ over Russia’s plans to open a naval base in war-torn Sudan. News of the development of the base has triggered an unusual warning from the State Department, Fox News Digital was told.

A State Department spokesperson told Fox News Digital, ‘We encourage all countries, including Sudan, to avoid any transactions with Russia’s defense sector.’

The Kremlin appears to be desperate to join the Horn of Africa global powers ‘naval club,’ with its approved plans for a base for warships and nuclear-powered submarines at Port Sudan. This is not far down the Indian Ocean coast from Djibouti, where there are U.S. and Chinese bases. With the new Syrian government likely to kick the Russians out of their base in Tartus, Port Sudan would be Russia’s only foreign naval base.

‘Moscow views Sudan, because of its strategic location, as a logical place to expand Russia’s footprint into Africa, which Putin views as a key place of geopolitical confrontation with the United States and China,’ Rebekah Koffler, a strategic military intelligence analyst, told Fox News Digital. 

‘Russia views the U.S. and China as its top adversaries, with whom Moscow may in the long-term have a kinetic conflict. Hence, Putin wants intelligence and military capabilities stationed close to the U.S. Djibouti base and Chinese facilities,’ she said.

‘Given that the U.S. and China already have [a] naval presence off of the Horn of Africa,’ Koffler added, ‘Russia is looking at Port Sudan as a logistics hub for weapons transfers, storage of military hardware ammunition, all sorts of war-fighting capabilities.’

‘The potential Russian naval logistics facility in Sudan would support Russian power projection in the Red Sea and Indian Ocean,’ John Hardie, deputy director of the Russia Program at the Foundation for Defense of Democracies (FDD), told Fox News Digital. He added that ‘this issue has gained greater importance for Moscow, given the uncertainty over the future of its Tartus naval logistics facility.’

A Russian naval base in the Indian Ocean has strategic military implications — it’s a relatively short sailing distance to the Red Sea and the Suez Canal, a choke point through which an estimated 12% of the world’s shipping passes, while 61% of global oil tanker traffic is also said to use the canal. Koffler said this poses a significant security threat. 

‘If Russia perceives an impending escalation against Russia, let’s say in Ukraine — such as an impending deployment of NATO forces or draconian economic measures designed to tank [the] Russian economy — I would not rule out the possibility that Putin could authorize something disruptive to exploit the choke point and destabilize or disrupt global shipping, as a way of deterring Western actions threatening Russia.’

The deal permitting Moscow to build a military base has been given the green light, although there are serious logistical challenges involved. ‘The agreement between Sudan and Russia was finalized in February, following a meeting between Sudan’s Foreign Minister Ali Yusef Sharif and Russia’s Foreign Minister Sergei Lavrov in Moscow,’ Koffler explained. 

Hence the strongly worded comments to Fox News Digital from the State Department that ‘the United States is aware of the reported deal between Russia and the SAF [Sudanese Armed Forces] on establishing a Russian naval facility on Sudan’s coast. We encourage all countries, including Sudan, to avoid any transactions with Russia’s defense sector, which could trigger serious consequences, potentially including sanctions on entities or individuals associated with those transactions.

‘Moving forward with such a facility or any other form of security cooperation with Russia would further isolate Sudan, deepen the current conflict, and risk further regional destabilization. ‘

On the (very) dry land that is Sudan, the situation Monday around the city of Al Fasher and the neighboring massive Zamzam refugee camp in the Darfur region is ‘horrifying,’ U.N. Assistant Secretary-General Tom Fletcher posted.

The civil war in Sudan, between the government’s SAF and the rebel Rapid Support Forces (RSF), has just passed its grisly second anniversary. Tens of thousands have been killed, and an estimated 13 million people have been uprooted from their homes. The U.N. describes it as the world’s worst humanitarian crisis, and UNICEF calls it ‘hell on earth.’

‘There can be no overstating the brutality and destructiveness of the RSF assault on Zamzam (refugee camp),’ Sudan researcher Eric Reeves told Fox News Digital this week. ‘The camp that has existed since 2004 is no longer, even as it had grown to more than 500,000 people.’

Ominously, Reeves added that ‘the real dying has only just begun. Nearly the entire population of Zamzam has fled, and in all directions the threat of RSF violence remains. This creates insecurity of a sort that prevents humanitarians from reaching these scattered people. Tremendous numbers will die either from RSF violence or the lack of food, water and shelter.’

Another 30 were reported killed on Tuesday in a fresh RSF attack on Al Fasher. And just this past week, the RSF rebels announced they are setting up their own government. The State Department told Fox News Digital, ‘The United States is deeply concerned about the Rapid Support Forces (RSF) and aligned actors’ declaration of a parallel government in Sudan. This attempt to establish a parallel government is unhelpful for the cause of peace and security and risks a de facto partition of the country.’

‘It will only further destabilize the country, threaten Sudan’s territorial integrity, and spread wider instability throughout the region. The United States has made clear that our interest is in the restoration of peace and an end to the threats the conflict in Sudan pose to regional stability. The best path to peace and stability is an immediate and durable cessation of hostilities so that the processes of establishing a civilian government and rebuilding the country can begin,’ the spokesperson said.

Caleb Weiss, editor of the FDD’s Long War Journal and also a Defections Program Manager at the Bridgeway Foundation, put some of the blame for not ending the Sudanese war on the Biden administration. He told Fox News Digital that it ‘stopped short of seriously facilitating any sort of meaningful peace talks/mediation/or being tough on outside backers of various groups to really get them to be serious in previous negotiation attempts. This is where the Biden administration failed.’ 


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President Donald J. Trump recently signed an Executive Order directing the Secretary of Energy to rescind certain restrictions on water pressure established by his predecessors. 

As the White House put it, the president was ending the “Obama-Biden war on water pressure and [making] America’s showers great again.”

This isn’t the final salvo in the decades-long Appliance Wars — nor did the order accomplish what many on social media claim.

I first encountered the Appliance Wars in the 1990s, courtesy of my favorite TV show, Seinfeld. In a memorable episode, Kramer, Jerry, and Newman are all visibly irked (and unkempt) as they wrestle with the newly mandated “low-flow” showers.

“There’s no pressure; I can’t get the shampoo out of my hair!” Kramer laments. “If I don’t have a good shower, I am not myself. I feel weak and ineffectual; I’m not Kramer.”

The scene comes from “The Shower Head,” Season 7, Episode 15, which aired in 1996. I didn’t catch it until a few years later while in college, but even then the episode felt fresh, edgy, and smart. 

What I didn’t know was that the Appliance Wars had already been raging for decades.

The Appliance Wars

On December 22, 1975, President Gerald Ford signed into law the Energy Policy and Conservation Act, which granted the president powers over energy exports. The law included regulatory power over household appliances to increase energy efficiency.

The legislation was a response to the 1970s oil crisis, an event that was exacerbated by price controls imposed by President Richard Nixon. The first energy efficiency regulations under the EPCA focused primarily on items like refrigerators, air conditioners, and water heaters, but over time, the scope of these regulations expanded and became more stringent.

In 1992, the Energy Policy Act amended the EPCA to require stricter efficiency standards for appliances and water efficiency standards, including a rule that mandated lower-flow showerheads that limited outflows to 2.5 gallons of water per minute. 

The federal government’s attempt to save the planet by regulating showerheads seemed common sense to some and absurd to others. For writers at Seinfeld, it was clearly the latter. 

Yet the low-flow showers that Seinfeld mocked were not stringent enough for some. 

In 2010, the Obama Administration reduced the maximum flow of showerheads to 2.0 gallons per minute. Some states have gone further. California, for example, has regulations that limit the maximum flow rate for showerheads to 1.8 gallons (and 1.2 GPM for bath faucets).

Twitter and media were abuzz last week that Trump had “made showers great again,” but his executive order didn’t scrap the federal rule, something the White House’s own statement confirms.

“President Trump is restoring sanity to at least one small part of the federal regulations, returning to the straightforward meaning of ‘showerhead’ from the 1992 energy law, which sets a simple 2.5-gallons-per-minute standard for showers,” the press release stated.

The executive order reversed a complicated Biden rule — it was 13,000 words, according to the White House — on the definition of the word “showerhead.” What it did not do was repeal the 1992 regulation.

‘If Washington Can Regulate Showerheads’

The Trump administration is taking a victory lap for “Making Showers Great Again,” but the federal regulation that inspired “The Shower Head” is still in place — it’s just slightly less stringent than the 2-gallon per minute rule initiated during the Obama presidency. (To be fair, the 2.5 limit is written into the US Code, which cannot be changed with the stroke of a pen.) 

That episode ended with Kramer buying “hot” showerheads off the black market. The episode captured the absurdity of attempting to conserve resources in a top-down fashion. As Kramer pointed out, he couldn’t get clean with the new showerheads, which resulted in him taking longer showers. 

Longer showers are indeed a consequence of lower-flow showerheads, but these are the kind of practical consequences that rule-making bureaucrats rarely consider. We’re supposed to take it on faith that federal regulators know the optimal amount of water each individual requires to live, wash, and flush. They don’t, of course.

The Showerhead Wars are funny because they are a Kafkaesque absurdity. The wars lay bare the stupidity of a soulless bureaucracy that can spend 13,000 words defining the term “showerhead” to make our lives less enjoyable and efficient. 

The joke is ultimately on us. Because if Washington can regulate your showerhead, it can regulate anything — and that’s the problem.

We just made it through another tax season. Congress has begun debating whether and how to extend the Trump tax cuts from the 2018 Tax Cuts and Jobs Act. While many elements of that tax debate are worth commenting on, I want to highlight the standard deduction because it sheds light on an underappreciated part of American philanthropy.

Prior to the introduction of the federal income tax in 1913, charitable donations did not have meaningful tax deduction benefits. Yet Americans gave generously. In fact, if anything, American philanthropy has declined due to the Scrooge effect of the welfare state. “Are there no [state-funded] prisons [or work-houses]?” Ebenezer Scrooge asks in Charles Dickens’ A Christmas Carol.

The questions reveal that Scrooge (and others) feel that their higher taxes to fund a variety of social and “poverty-reduction” programs take the place of direct philanthropic giving. Americans also keep a lot less of what they earn today than they did a hundred or a hundred and fifty years ago—as most of us know from recent personal experience.

The case of welfare programs crowding out charity has been made eloquently by Marvin Olasky in The Tragedy of American Compassion. Various religious and fraternal orders provided health insurance, old-age insurance, and other social services to their members throughout the nineteenth and into the twentieth century. These services were later replaced by state unemployment benefit schemes, Social Security, Medicare, and Medicaid.

These government programs “crowded out” charitable, philanthropic, civil society—contributing to problems of declining social capital elaborated by Robert Nisbet (Quest for Community) and Robert Putnam (Bowling Alone). Government agencies and government checks replaced civic networks and systems of support. Yet American philanthropy is still alive and kicking in the U.S.

The Lilly Family School of Philanthropy at Indiana University estimates that Americans gave $557.16 billion to charity in 2023. That’s about $1,600 per capita. By comparison, Canadians gave about $400 per capita to charity and Brits gave about $250 per capita. Even as a percentage of GDP, the U. S. ranks well above European countries. According to one source, the U. S. is one of the most charitable countries in the world.

What’s remarkable is that the vast majority of Americans who give to charity receive no federal tax benefit from doing so. Returning to the individual exemption, when you file your taxes, you can either claim the standard deduction ($14,600 for an individual, or $29,200 for a couple) or you can itemize your deductions. A few expenses can count towards the itemized deductions, but these expenses are highly qualified and don’t add up to much for the average person.

From a benefit standpoint, your qualified expenses, including your charitable giving, must add up to more than the standard deduction before you receive any tax advantage. Suppose someone takes the entire $10,000 state and local tax deduction (SALT) and comes up with $5,000 more in other qualified expenses. They would still be $14,200 short of the $29,200 standard deduction for a couple. This means that any of their charitable giving, up to $14,200, does not render them any benefits on their federal taxes. 

Seventy percent of American households earn less than $127,000 before taxes. So $14,200 would mean donating more than ten percent of their pre-tax earnings before they saw any advantage from the giving being “tax-deductible.” For most Americans, the “tax-deductible” element of charitable giving is practically irrelevant. Yet they give anyway.

Most Americans donate money even though they receive no federal tax benefit. Americans gave generously long before the income tax and the charitable tax deduction existed. A large industry of lawyers and accountants has cropped up to help wealthy people lower their tax liabilities through various forms of charitable giving. Sometimes these methods lead to creative accounting and legal gymnastics that can distort or divert people’s choices of how to use their wealth.

These observations provide a few reasons to want an alternative to our federal tax code 501(c)(3) structure. We should ask whether society would be freer in a world without tax exemptions for charitable giving—a world without the stark for-profit/nonprofit legal divide with all its attendant reporting and hoops. Tax code rules that put their thumb on the scale represent social engineering of the kind free people should reject.

Most Americans give generously without thought of return—even with a large welfare state and high taxes. There is something deeply admirable about this kind of generosity that gives without expecting any material benefit in return. Imagine how they would give if the welfare state were trimmed down and their taxes were lower. That’s what George W. Bush’s “compassionate conservatism” should have meant.

The oil sector faced volatility throughout the first quarter of 2025.

Concerns around weak demand, increasing supply and trade tensions came to head in early April, pushing oil prices to four year lows and eroding the support Brent and West Texas Intermediate (WTI) had above the US$65 per barrel level.

Starting the year at US$75 (Brent) and US$72 (WTI), the oil benchmarks rallied in mid-January, reaching five month highs of US$81.86 and US$78.90, respectively. Tariff threats and trade tensions between the US and China, along with soft demand in Asia and Europe, dampened the global economic outlook for 2025 and added headwinds for oil prices.

This pressure caused oil prices to slip to Q1 lows of US$69.12 (Brent) and US$66.06 (WTI) in early March.

“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.

Oil prices fall as OPEC hikes output and supply risks mount

WTI price performance, December 31, 2024, to April 23, 2025.

WTI price performance, December 31, 2024, to April 23, 2025.

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.

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.

Oil price forecast for 2025

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.

Supply concerns add tailwinds for natural gas

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.

Natural gas price performance, December 31, 2024, to April 23, 2025.

“(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.

Natural gas price forecast for 2025

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.

Securities Disclosure: I, Georgia Williams, hold no direct investment interest in any company mentioned in this article.

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