$65 Million to $2 Billion: The Netherlands' #1 Gas Producer

0:19 What Tenaz is today — a Dutch offshore gas producer with a Canadian tail

• "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."
• All Netherlands production is offshore, in ~30-35 m of water and typically within ~30 km of shore.

1:07 Why the Netherlands — the jurisdiction case

• "The fiscal regime is consistent and it's very very good… the political environment there is quite stable… there is strong rule of law."
• Physical advantages he lists: benign southern-North-Sea weather ("not kind of this really rough weather area like you think of in the North Sea"), good service infrastructure, and a workforce inherited from Shell/Exxon.
• And the price: "it's European gas and very high priced in comparison to North America and particularly in comparison to Canada."

2:39 Conventional rock, and plumbing built for a bigger business

• "It's good geology, reliable geology, conventional geology… it doesn't have super high decline rates, actually quite low because of the conventional nature." Every well drilled to date has come in.
• The under-appreciated asset is the existing infrastructure: "it's built for an industry that used to produce at much much higher rates… Everything we drill is from an existing platform." No pipelines or platforms to recapitalise — capital goes into wells and workovers only.

5:02 GEMS in one paragraph — Gateway to the Ems

• New development on the Netherlands/German maritime border, "100% success rate on the drilling activity," non-operated with Tenaz at roughly one-third (27-45% across licences).
• "Two of those wells produce about 75 million cubic feet a day and this is into a market where gas in Canadian dollar terms on an energy basis sells for 25 or so Canadian per MMBTU."

8:06 The model, stated plainly — low entry multiples abroad, then organic growth

• The host's summary — "acquiring undervalued overseas assets where entry multiples are lower and operating upside is higher" — draws "It's exactly the way to put it and this is kind of the mantra that we had when we came out with the recap."
• "Multiples lower at entry, more opportunity to drive up production, drive down unit costs, improve profitability in the overseas assets. And you put those two together, you have this great chance for a high return on capital."
• Where they are now: "really now the primary activity of the company is to just execute on this organic growth" — acquisitions are "the icing on the cake."

11:24 The part that makes the chart work — almost no equity issued

• "The first deal had no equity out the door. The second one for gems, we had a very small equity kicker… only something like 3% of the total consideration."
• "So we don't have very many more shares out than we had at the time we did the recap. But the company is now… 30 times bigger already."
• And it was not levered up either: "we end up doing it at pretty low debt multiples… We're kind of underlevered even today."

12:38 The scoreboard, in his host's numbers

• "Today is August 6th. The market cap is approximately $2 billion. Q2 average production was about 17,000 BOE a day. Your latest July estimates getting towards 23,000 BOE a day."
• Against May 2023: "the share price has gone from approximately $2 to today it's about 54. There was a time it was about 70… Market cap at the time 2023 was $65 million."
• He explicitly does not welcome the war-driven spike to ~$70: "I don't think that runup in price in the stock that the war induced has particularly been a positive because we feel like we can execute the growth plan at very strong prices and super strong margins without it."

18:28 Deal 1 — NAM Offshore, bought from the Shell/Exxon JV

• Roughly 11,000 boe/d and ~55 MMboe of reserves, sold by the 50/50 Shell-Exxon joint venture that had not drilled the offshore in ~15 years.
• Why it was for sale: NAM's onshore business was dominated by Groningen — "biggest field in Europe onshore, that was ultimately shut in due to seismicity" — which made the offshore "a logical sale."
• How Tenaz got in the room: contacts made early, and "we were part of really a very limited process."

25:53 The trick in the timing — 16 months of interim free cash paid the price

• Effective date Jan 1 2024, closing May 12 2025 — "that's a 16-month period, so the free cash generated during that period went against the consideration, the base consideration as of Jan 1 24, paid it down a lot. We had pretty good pricing. We were able to lock in some of that with hedging during that period."
• Base consideration was €165M with a ~€23M deposit; at closing Tenaz actually received ~€15M back.
• He frames the long close as a known feature of European deals, not a bug: "we expected them to go off at pretty low multiples… and also they take typically a long time to close."

31:40 Contingency 1 — the free-cash earnout, and why reinvesting shrinks it

• "A sharing of free cash flow for three of the years of the deal, 25, 26, and 27. Half of free cash, FFO minus capex, going to the sellers in 25, half, and 26, one quarter in 27." A payment has already been made for 25; a 27 estimate sits on the balance sheet and is remeasured quarterly.
• The elegant part: capex is deducted before the split, so "the fact that we invest significantly in nom drilling workovers means that the contingent payment under the earnout is lower than it would otherwise be" — the incentive to reinvest and the payment obligation point the same way.
• He rejects the "seller financing" label: "they are really pure contingencies."

33:24 Contingencies 2 and 3 — an exploration royalty and a 2028-31 price kicker

• Exploration: nothing until a single new-field discovery reaches ~17.5 BCF, then a royalty; a higher rate above 35 BCF — "I think it's five and 10 after you hit each of these thresholds." No such discovery yet.
• Price: applies only 2028-2031, after-tax and inclusive of hedging, above €50/MWh — the seller takes about a quarter of the increment to €60/MWh, more above. Calculated annually, deliberately: "that means you don't just clip the tops monthly or quarterly."
• The live gap: spot is ~€55/MWh, but "the forward strip for 28 is… about 30 euros a meg… so it's around half of the threshold level."

36:16 Deal philosophy — structure for both sides, and the limits of contracts

• "The objective in the entire deal and the way to get them done is to meet the objectives not only for our company in this case as the buyer but also for the counterparty." The contingencies exist to give the seller retained upside without cash today.
• On trust: "there's no way in any contract you can provide for every contingency… good contracts make good friends" — but "if you truly trust no one, you would never make a deal."

38:26 The alligator jaw — fixed offshore opex as an engine of margin

• "So much of the opex offshore, vast vast majority of it, is fixed. You bring in an additional molecule or MCFD, it does not really change the opex very much. So it's huge contribution margin."
• Transportation — the genuinely variable piece — is "less than 10% of the total," so unit costs fall as volumes grow.
• Combined with a rising European-gas share of the mix, the corporate chart is "kind of an alligator jaw": revenue per unit up, cost per unit down. And higher margins de-risk the business — "a change in commodity price has less of an impact when you start with high margins rather than low margins."

40:24 Deal 2 — GEMS, closed October 2025

• ~$230M US cash plus a $60M contingent piece and ~$12M US of equity, for ~4,000 boe/d and 19.3 MMboe 2P at the time.
• Contrast with NAM: non-operated instead of ~85% operated, very early stage instead of mid-life, three discovered pools to develop plus a book of contingent and prospective resource — "a few other blobs as we call them, seismic leads that are not yet characterized as prospects."

43:02 GEMS wells — the two highest-rate wells in the Netherlands

• Two wells drilled by the operator since closing: "the first one originally tested 40 million a day. The last one just came on 75 million a day… Now the two highest rate wells in the Netherlands are on this asset."
• Next: an extension well drilling now, an exploration well to the east, then the N4 A and C pools (tested 20 and 50 MMcf/d) on a new satellite platform "couple years from now."
• Production is already "on the order of two and a half times where we bought it at."

46:36 Why give up operatorship — and the wind-powered platform

• Stated preference is control: "we feel like via engineering and geoscience capability… as operator you can optimally match it to your company's objectives." GEMS was the exception, taken for the returns.
• The N5A platform is powered by an offshore wind farm on the German side of the border and drills with an electric rig, so "that drilling going on right now doesn't really generate any emissions."

48:25 The edge he claims — forecast the "controllable inputs" well

• Engineering and geoscience are "the foundation actually of what we do in the acquisitions": a per-well, per-project forecast of rates, capex and opex — "all of these kind of technical inputs I call them really the controllable inputs."
• He concedes the honest limit: "in acquisitions the biggest driver of whether it's high rate of return or not is how does a commodity unfold versus where you buy it at." The technical work is what stops a technical disaster; the commodity is not controllable.
• Even the finance team is technical: "some of them seem like great engineers in their own right even though they're in finance, like our CFO."

51:56 Fish where there are few bidders — avoiding winner's curse

• "We also prefer the international market. It does have fewer participants, particularly qualified participants… The fewer potential buyers you have, competitors you have buying, the better returns you get."
• "This kind of gets into acquisition theory but this has been demonstrated both theoretically and empirically… when there are five or six bidders it's hard to make a good deal… You can avoid winner's curse."
• He notes the other side plays the same game: "the sellers know this and the dealers who are the intermediaries in these deals, they know this as well. They want to get more bidders in."
• What limits the bidder count is capability, not appetite: "there aren't as many qualified bidders that have that technical capability to run the assets, to get to closing… meet all the regulatory requirements."

55:39 The geology — Rotliegend traps, and the "bald structure" insight at GEMS

• Main producing sand is the Rotliegend, with deeper Carboniferous and shallower horizons; structurally trapped, conventional, and "possible to evaluate on all the elements of risk that exist" with classical reservoir engineering.
• The GEMS unlock: drillers 20-25 years ago targeted the crests and found "bald structures, no sand." The modern model puts the good sand in the topographic lows — "now that that model's understood… I guess we were able to clue into that model."
• Data advantage on the TEN licences: full 3D and in one key area an ocean-bottom-node survey ("the geophones are on the seabed… you get a very very high quality picture"), only now being evaluated and not yet in the portfolio.

1:00:40 The 2026 program — one operated rig, a workover barge, a walk-to-work vessel

• ~$300M budget. One operated rig (the Shelf Winner) drilling about four wells a year, roughly three months a well, plus non-op wells on Eni-operated assets and a gross four-well GEMS program.
• New in Q3: a heavy-duty barge for well intervention that "hasn't been done for a long time in the NOM assets." Workovers do not give "eye popping rates," but at a fifth to a tenth of a new well's cost, "usually it's higher rate of return even than drilling."
• A third vessel does light intervention and platform integrity work — a deliberately diversified activity set, "which I think makes it a lower risk program."

1:03:54 What a well costs — and the learning curve he is betting on

• Stimulated wells ~€60M gross; the first unstimulated well (the intended mode) came in on budget at ~€43M gross. "I bet we can make a 20% if not more reduction in those costs… 30 to 35 million I'm hoping."
• GEMS wells are programmed at similar cost but unstimulated and very high rate — "this is where you can get a couple month payout." Operated wells "quite readily get one-year payouts or lower depending on the price environment."
• He is explicit these are today's-price payouts: "We're not always going to have probably today's prices, but I think the program is going to be very resilient."

1:07:04 Midstream — three layers of infrastructure they did not have to build

• Existing platforms with reusable slots ("we can reclaim a slot from an older well"), pipelines to shore in excellent condition and built for higher rates, and two onshore gas plants.
• NGT at Uithuizen (Tenaz holds 21% equity) and the operated Den Helder plant, "the largest actually name plate plant in Europe"; combined nameplate ~5¼ Bcf/d, far above current throughput even with mothballed trains.

1:09:08 Decommissioning — the liability the host pushes on

• ~$300-400M of wellbore liability on the balance sheet. His answer: "It's actually to us a pretty low level of liability in comparison to the value of the offshore assets."
• Two levers: extend field life (which pushes out the abandonment and cuts its present value while generating more cash), and drive decom cost down through scale, shared equipment utilisation with other North Sea operators, and better technical practice.

1:12:45 Canada — the unsung 10%

• From ~900 boe/d at the 2021 recap to roughly 2.5x, funded from its own free cash. Core is a Mannville Rex pool with ~400 MMbbl oil in place, converted from low-rate verticals to optimised long horizontals with better frac staging.
• Running room added by stacking zones — Ellerslie and Glauconite by multilateral without fracs, Sparky (and possibly Lloyd) by single-lateral horizontals with multi-stage fracs.
• Later, the capital math: Canada is "less than 5%" of the capital budget for 10% of production, so "you could think of it as efficient in terms of the ratio of share of company production compared to share of company capital."

1:15:45 Balance sheet and return of capital — buyback, not dividend

• "We want to be underlevered… we're below one turn now, we would be headed for way way lower debt levels than that." A C$305M note is callable May 2027 and he expects a lower refinancing rate, though the RBL already gives "quite strong liquidity."
• No dividend, by choice — this team ran heavy dividend models in previous incarnations and found them hard to defend through commodity volatility ("you run into the super extreme case of COVID"). "Today our return of capital really occurs through the buyback… We think the stock is good value."
• If a dividend ever comes, "it would start small so we could have steady increments of growth in it."

1:19:41 Listener questions — no "windfall," and a polite no-comment on BP's UK sale

• Asked how a higher-for-longer TTF windfall would be spent, he rejects the premise: "I don't think it's a windfall in any case. Prices may well not stay at the current level. That is very possible. Probably likely." Debt comes down "at almost any price," with the buyback running alongside.
• On BP's UK North Sea process (1:20:27): would evaluate, but the UK's fiscal regime and incumbents' tax pools are structural disadvantages — "you can make your own judgments about the relative probability."

1:22:03 Is 100,000 boe/d still the ambition?

• No number reaffirmed and no long-range plan published — "At some point in the future, I'd like to do that, but we'd like to have some degree of confidence in it while properly characterizing the uncertainties."
• Scale is still the goal for two reasons: operating economies (offshore services must be contracted long-term, unlike picking up a Canadian rig on a window) and capital-market acceptance — "you get better acceptance in the midcap realm than you do at the nano or micro cap realm."
• Split of future growth: "part of the growth that we have in the future I would say probably will come from acquisitions. There's no guarantee on that part of it. There's much greater certainty around the organic growth."

1:27:20 TTF versus AECO — and his own price view

• The host's framing: European spot ~"$25 an MCF" against AECO "sub $2" — "at least 10 times as high in Europe."
• Marino will not extrapolate it. The forward curve "has validity for the initial part of the period… you go two or three years out, it's probably not a good predictor at all," partly because of low liquidity and an imbalance between consumer and producer hedgers.
• His actual lean is down: "To me it's actually likely that they would be lower than that over any appreciable forward period rather than higher than that."

1:29:25 The hedge book — what is locked and at what price

• Roughly 55% hedged on TTF for 2026, ~45% for 2027, below 10% for 2028, nothing in 2029 and beyond because "the way the futures market is constructed doesn't really offer you very good opportunities out there."
• Struck "in the low 30s per euros per megawatt hour" — put on at the time of the NAM and GEMS acquisitions to underwrite the first couple of years' returns, and in GEMS' case because "that one was done with debt."
• The cost is visible and he does not hide it: realised losses on the book and "huge swings in net income under IFRS accounting, this kind of mark to market change every quarter."

1:32:44 How they hedge — collars, three-ways, and trading the skew

• House philosophy: "about half hedged for the first year looking forward and in the 30% to 50% range for the second year."
• Not just swaps: typically costless collars, sometimes three-ways, and timed to skew — "you can get a much better ceiling sold call than you can get floor bought put even in a costless situation."
• He flags the trade-off of a three-way honestly: great downside coverage, "but then you have a sold put as well at some lower level below which you would not have any protection."

1:34:51 Closing — alignment, and the partners

• "Our employees are actually all shareholders in the company… If I was an investor that's the first thing I'd want to know. How much do the people in the company own? And is everybody an owner?"
• Thanks the industry partners by name — ONE-Dyas, Eni, and EBN, "the state gas producer that has typically 40% heads up interest in all these licenses."