Tenaz Energy Corp. (TNZ) Earnings Call Transcript & Summary

Hello. I'm Tony Marino, President and CEO of Tenaz Energy. Thanks for joining our Q1 2026 update. I'd first ask you to note our investment advisories on Slide 2. I'm going to begin with a discussion of our operating and financial results using the first Slide 4. So in Q1 '26, our production was up 4%, reaching a level of approximately 16,200 BOE/D with the vast majority of that production coming out of Netherlands. FFO for Q1 '26 was approximately CAD 65 million. That was a 4% increase from the fourth quarter of '25. We certainly had our most active capital program we've ever had in the company's history, 3 offshore jack-ups running on licenses in which we have an interest. I'll cover it more later, but one of these operated in 2 non-operated drilling rigs in the Dutch North Sea. An offshore workover campaign going in Q1 as well. And we also drilled 3 gross wells in Canada that we operated. Our CapEx for the first quarter was CAD 92 million. That's about 1/3 of our 2026 plan. We'll talk about an increase to our capital program. It will probably end up being about 30% of the capital for the year as a whole with that increase. And certainly, I would say, probably our most capital-intensive quarter that we expect. Our operating netback in Q1 '26 was very, very strong, over $57 per boe. Reasons for the higher netback, we had higher pricing in this quarter, in part driven by the outbreak of war in the Middle East at the end of February and driven by really an improving product mix in the company with higher levels of Netherlands production in the mix because of the acquisitions and continuing organic growth. Our net debt as of the end of Q1 was $389 million. That was an increase over our year-end debt level because our capital program exceeded FFO. It's very front-loaded on capital, as I talked about earlier. And of course, we see the production results, and resulting revenue and cash flow coming in mostly after Q1. We do expect to have substantial free cash flow at the commodity strip that we have currently during the year, even with the capital increase that we're announcing Q1 results. And it's quite a reasonable debt level. While we do expect deleveraging further during this year, if you just take that debt level and compare it to our expected FFO for the year, it would be about a 1x multiple. We did record a net loss of CAD 111 million in the first quarter of '26. This loss that we recorded is really just due to the requirements of marking to market our entire hedge book for '26, '27 and '28 and recording that entire change in the mark-to-market value in the first quarter. As at the end of 2025, as at Q4 '25, we had a small gain -- unrealized gain recorded on the hedge book that shifted to a negative position, unrealized loss position is recorded in Q1, and it's the reason for the loss that we recorded here. This hedge accounting of IFRS is sometimes a little bit counterintuitive in that when you have higher prices in a quarter and certainly, it's been very dramatic with what has happened with the Middle Eastern war, it actually can lead you to report quite a substantial loss. If prices decline, that hedge book position reverses and you may well report high net income when you have a lower price period. Counterintuitive, a little bit confusing, not very reflective of our increasing cash flow and what we expect to be substantial free cash flow. But nonetheless, this is how the mark-to-market accounting under IFRS works, and it was the entire reason for recording this loss. Slide 5. Let's review our operating activity during the quarter. On our Tenaz Energy Netherlands or TEN operated assets, first of all, we finished drilling our first well with the Shelf Drilling Winner jackup that we are operating. This well called the K07-FB-103 well, which is the K7 also often referred to as the K7 Papa South pool. So we finished drilling this well, and we have now completed it. We brought it on production during Q2 at a rate of 7.8 million cubic feet a day, that's 3.6 million cubic feet a day net to Tenaz. This is very close, almost exactly our expected production rate actually flowing into the system that we expected during the first month of production. So as expected, tested at a higher rate, and this is the rate at which we put it on production. The Shelf Drilling Winner rig then moved to the K17 platform, began drilling the K17-103 well. This, we have a 60% working interest in. This well is still drilling. We do intend to complete it with a multistage stimulation in the horizontal lateral. And that activity, we're still scheduling with a stimulation vessel that will occur a little bit later this year. We also conducted an initial barge workover campaign on the K15A platform with a barge that we have since released and we have no barge running at the moment. We'll explain later, we're going to pick up a new more versatile barge later in the year. That K15A program added about 7 million cubic feet a day of productive capacity. That would be 3.2 million a day net to our interest, quite a successful program. These workovers tend to pay out pretty fast, don't require as much capital, of course, as drilling a new well, and they can give you some quite good production results. Talk about the forward activity a little bit later on. At GEMS, operated by ONE-Dyas on wells that we have a 33.3% working interest. First of all, production continues on the first N05A pool, well #1 at a rate of about 74 million cubic feet a day or around 24 million to 25 million net to our interest. With respect to the drilling, they finished the first development well in this program. It would be the second well in the N05A pool. This well is called the N05-A-03. It was drilled and completed and brought on production gross rate of 40 million cubic feet a day, quite strong productivity and 13.3 million cubic feet a day net to Tenaz. Again, that's in addition to the N05-A-1 well that is still on production at 74 million cubic feet a day gross. That one is the highest producing rig well in the Netherlands. After the N05-A-03 well, the ONE-Dyas operated drilling rig began drilling the second development well and this year program would be the third well in the N05A pool. This well designated as the A02 well, and this drilling is continuing. Third rig is operated by ENI at the pool in the -- on the L10 license. So here, we have a 21.4% working interest. ENI finished drilling that L10 Malachite well and has tested at -- did a step rate test, stabilized rate of 14.5 million cubic feet a day, and they are in process of tying that well in. Again, that one is 21.4% working interest. Canada, we drilled 3 gross wells. 2 were in the Ellerslie member of the Mannville formation. These are multilateral wells with no stimulation, and they are currently on production at a rate of 450 BOE/D, which is nearly 400 BOE/D net to our interest, 85% oil, the rest AECO gas. The third well was drilled and completed in the member of the Mannville formation, again, 7/8 working interest. It is a single lateral with multistage Fracs, and it is currently producing at 245 BOE/D, around 215 BOE/D net to our interest, its oil percentage of that oil equivalent rate is 72%. That well continues to [indiscernible] water cuts. So successful activity, I would say, throughout this very active Q1 program. On Slide 6, I'll talk a little bit about our capital program for the rest of the year and the expansion of the budget. So the first thing, we are announcing a $25 million increase to our targeted capital program. Previously, we've guided to CAD 250 million to CAD 275 million. We're now targeting CAD 300 million investment for the year. We do expect to be generating at this level meaningful free cash. And as we look at our alternatives for using that cash, we do have an ongoing NCIB program. We will be reducing debt levels. But we do think that the very highest use that we could have of free cash flow, given our high rate of return on the development program is to have more organic development and more organic production growth. The incremental capital goes toward an expanded workover program, bringing in a new barge. I'll cover that in just a second, an additional non-operated well that we expect to occur late in the year. And also, it allows for stimulation of the third well in our operated program, which is a little bit more expensive than an unstimulated well as we had planned previously. So more workovers, the additional nonoperated well and kind of an expanded better completion scope for the third well in our operated drilling program. The barge is shown in the picture on the right side of the slide, Triton-10 barge, we think quite a versatile vessel. We intend to have it in place during the second half of the year. We've already identified 50 workover opportunities. In aggregate, these are going to have, we believe, a risk IRR in excess of 100% under the current commodity strip and even under much lower pricing, if it occurs, we have very strong returns. Again, we get rates of -- rates out of these workovers, and they don't take that much capital because the vast majority of the capital investment occurred at the time of drilling. So it's quite an efficient way to employ capital. We have actually a very long-term set of workover opportunities. The scheduling we have now takes this barge already out into 2029. The barge is quite versatile. It can also help our completion program when it's more efficient. We can have the barge complete wells rather than using the drilling rig, which could then be employed to do further drilling activity on the very large opportunity set that we have for new grassroots wells as well. All of this, of course, occurring from existing platforms. And again, all this activity kicks in later in the year. We don't expect very much of a production impact from it during 2026, but we should have improvements in our already further growth in our rates than we previously expected in '27 and the years beyond as a result of this modest expansion. I'd like to briefly discuss European gas fundamentals. We've talked about this in previous quarters. We show on Slide 8, an update of our storage curves for the European Union, actually 9 years of data here, including the current year '26 shown in the dark red curve. We already knew that we came into the heating season for '25, '26 at relatively low storage levels. We then had a pretty cold winter overall in Europe. And as a result, we're running with pretty low storage compared to the previous 9 years as we have now moved into -- we're in the shoulder season moving into the injection season. As I think everybody knows, I covered the next couple of bullets, Europe has begun really relying more on just-in-time deliveries via LNG vessels for supply, not as much as on storage in the past and pipeline deliveries into Europe are pretty maxed out already. So it's really become a storage of LNG delivery. It's kind of a difficult position for Europe to be in, given the problems that have emerged in the Middle East with LNG supply. It's going to be a bit harder to refill the storage to typical levels. We don't know when the problems in the Middle East are going to be resolved. Everybody knows, I think that biggest LNG facility in the world in Qatar has had substantial damage. Of course, there's no delivery of LNG happening out of it along with no oil flows out of the past Strait of Hormuz. So Europe has quite a challenge in front of it to rebuild storage to an adequate level as we go into winter. The EU had, had mandates to reach 90% levels previously. I think those have already been relaxed to some degree. And again, Europe is going to be in a position of having to compete for LNG supplies with Asia. In a sense, the TTF change in gas price that occurred as a result of the war has been attenuated as a result of it occurring during the shoulder season, but we think that this competition for deliveries between Asia and Europe is going to increase as we move into the summer power season in Asia. So kind of a hard situation for European storage at this point. We show the pricing curves historically and in the dash lines and the forwards on Slide 9 for TTF in red and then for Henry Hub in the lighter green color and AECO in the dark green color. I'll point out that these prices were as of May 1, it's volatile every day. For example, as we are recording this on May 6, there's been a substantial drop in prices today, really depends on the news flow out of these negotiations and the military activity in the Persian Gulf. You haven't really seen much of a reaction out of the NYMEX or out of AECO, but there, of course, has been this big move up in TTF for the reasons we just talked about. It's still a very backwardated curve, doesn't show much incentive for seasonal storage as well, but it does vividly illustrate the impact of the war and the higher prices that we have in our TTF gas. Our product mix for this year will be close to 90% TTF for Tenaz. Moving to Slide 10, I'll just review again our commodity hedging. We talked a little bit about this earlier and the impact on the net income. So in our typical hedging program, in the next 12 months, we'd intend to have -- or for the current year, let's say, we'd intend to have about 50% hedged and around 30% for the 12 months after that. In our current condition, our overall corporate price exposure for the next 24 months is about 1/3 hedged. Breaking it down into the individual products for TTF, our most important exposure, this is going to ultimately be 90% plus of our product mix, we are 55% hedged for '26. The average price on that just under EUR 32 per megawatt hour. That's just about CAD 15 per Mcf for methane, CAD 15 per MMBtu. For '27, it's a little bit over 1/3 hedged. Average price there slightly higher, EUR 33.60 per megawatt hour, corresponding to a price just a little bit under CAD 16 per MMBtu. And then a small position for 2028, about 2% hedged at an average price of EUR 34/meg corresponding to about CAD 16 per MMBtu. WTI isn't nearly as significant product for us. We're about just over 1 quarter hedged for '26. Average price there, USD 67.50 per barrel, small position for '27, 6% of estimated production at an average price of USD 65 per barrel. And AECO, even less important volumetric product in our product mix and a very small part of our revenue. We were hedged for '26 and '27 at an average price of CAD 3.14 per MMBtu. That's well in excess of the market price representing around 63% of our '26 production and probably just under half of our '27 production. So again, a meaningful hedge book at what are really historically quite strong prices and the remainder exposed to the currently higher market prices for European gas and WTI. And finally, with respect to '26 guidance, kind of a reiteration of what we already talked about on Slide 12, projecting 21,000 BOE/D midpoint for '26 and a capital program targeting CAD 300 million of organic investment, which is up $25 million driven by the things I talked about earlier, the barge addition of an nonoperated well and stimulated well -- a third well in our program, our operated program. On the right side, we just outlined the individual wells that we expect to drill in our current plan, the working interest and a rough time line for when those activities are going to happen. So in closing, I'd first ask you to again note our investment advisory on Slide 13. And let me thank you for your interest in Tenaz. The next opportunity we'll have to talk is at our AGM scheduled for May 27. So again, thanks for your interest, and we look forward to our next opportunity.