In short: The CEO pitching his own company. "About 90% of our production is in Netherlands, all gas there, and 10% is in Canada, mainly oil… we're the largest gas producer in Netherlands among the producing community there. By equity interest." Two 2025 acquisitions (NAM Offshore from the Shell/Exxon JV; a ~one-third non-op interest in GEMS) took the company from ~$65M market cap and ~$2/share at the May-2023 recap to ~$2B and ~$54 with "no equity out the door" on the first deal and a ~3% equity kicker on the second. Q2 production ~17,000 boe/d, July accounting estimate ~23,000; ~$300M 2026 budget; below one turn of leverage; buyback, no dividend. His own caveat on the commodity: at ~€55/MWh TTF "it's actually likely that they would be lower than that over any appreciable forward period rather than higher."
Whose view this is: Tony Marino is the CEO of Tenaz. Everything positive here is the company's own account of itself on a friendly podcast. It is a very good source of operating detail and a poor source of impartiality.
What the company does: Tenaz produces natural gas from platforms in shallow Dutch waters — about 90% of the business — plus a small Canadian oil operation in Alberta that supplies the other 10%. It is now the largest gas producer in the Netherlands measured by the share of production it owns. The Dutch fields sit in 30-35 metres of water, close to shore, in calm weather, and the rock is ordinary conventional sandstone rather than shale, so wells decline slowly and behave predictably.
Why the gas is worth so much more than Canadian gas: European gas trades on a Dutch benchmark called TTF — the price for a unit of gas delivered into the Netherlands. Canadian gas trades on AECO, an Alberta benchmark. Because Europe has to import most of its gas by ship while Alberta is landlocked with limited export routes, the two prices are wildly different: at the time of this interview European spot was around $25 for the same quantity of gas that fetched under $2 in Alberta — roughly ten times the price for the identical molecule. The whole business case is producing into the expensive market instead of the cheap one.
How it got 30 times bigger without diluting anyone: two acquisitions in 2025. The big one bought the offshore Dutch business that Shell and Exxon jointly owned and had stopped investing in for roughly fifteen years — old platforms, spare pipeline and gas-plant capacity, and a long list of wells nobody had drilled. The second bought about a third of GEMS, a brand-new field on the German border where two wells each flow ~75 million cubic feet a day — the two highest-rate wells in the country. Between the recapitalisation in 2023 and this interview the share price went from about $2 to about $54 and the market value from $65 million to roughly $2 billion. Critically, almost none of that was paid for with new shares (the first deal used none, the second about 3% of the price), so existing holders kept their slice.
The deal structure, explained: the price agreed with Shell and Exxon was €165 million — but priced as of 1 January 2024, while the deal did not actually close until May 2025. In that sixteen-month gap the fields kept producing and the cash they generated counted against the purchase price, so by closing most of it was already paid; Tenaz even collected money back at the closing table. On top of the price sit three contingent payments — extra money the seller only gets if things go well, instead of a higher price up front. First, a share of free cash flow (cash from operations minus capital spending) for 2025-2027: half in 2025, half in 2026, a quarter in 2027. Because capital spending is subtracted before the split, every euro Tenaz reinvests in new wells both grows the company and shrinks the cheque to the seller — the two goals point the same way. Second, a royalty that only starts if exploration finds a genuinely large new field (about 17.5 billion cubic feet, with a bigger royalty above 35). Third, a price kicker that only bites in 2028-2031 and only if gas averages above €50 per megawatt-hour for a full year — today's price is about €55, but the market's 2028 price is nearer €30, so it is currently far out of the money.
The "alligator jaw": running an offshore platform costs roughly the same whether it produces a lot or a little — the crew, the helicopter, the maintenance are all fixed. So each extra unit of gas arrives with almost no extra cost attached, and profit per unit widens as production grows even if the gas price stands still. Draw revenue per unit rising and cost per unit falling on the same chart and you get two diverging lines that look like an open alligator's jaw. Fatter margins also make the company safer: a given drop in the gas price hurts a high-margin producer far less than a thin-margin one.
What he concedes: the gas price is the one thing management cannot control, and he thinks it is more likely to fall than rise — "it's actually likely that they would be lower than that over any appreciable forward period." Roughly 55% of 2026 and 45% of 2027 European output is already sold forward in the low €30s, well under today's price, which cushions a fall but also caps the upside and produces alarming-looking accounting losses each quarter when prices rise. There is also $300-400 million of eventual well-plugging liability, no published long-range plan (the old 100,000 boe/d ambition is neither confirmed nor withdrawn), and the buyback-not-dividend policy means the return of capital depends on management continuing to judge the shares cheap.
0:19We are a TSX listed company, really an international producer. About 90% of our production is in Netherlands, all gas there, and 10% is in Canada, mainly oil. So the critical thing about the company today is that we're the largest gas producer in Netherlands among the producing community there. By equity interest.
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