Tourmaline Oil Corp. ($TOU)

Good morning, ladies and gentlemen, and welcome to the Tourmaline Q1 2026 Results Conference Call. [Operator Instructions] This call is being recorded on Thursday, May 7, 2026. I would now like to turn the conference over to Scott Kirker, Chief Legal Officer. Please go ahead.

Thank you, operator, and welcome, everyone, to our discussion of Tourmaline's financial and operating results as at March 31, 2026, and for the 3 months ended March 31, '26 and '25. My name is Scott Kirker, and I'm the Chief Legal Officer here at Tourmaline Oil Corp. Before we get started, I refer you to the advisories on forward-looking statements contained in the news release as well as the advisories contained in the Tourmaline annual information form and our MD&A available on SEDAR and on our website. I also draw your attention to the material factors and assumptions in those advisories. I'm here with Mike Rose, Tourmaline's President and Chief Executive Officer; Brian Robinson, our Chief Financial Officer; and Jamie Heard, Tourmaline's Vice President of Capital Markets. We will start with Mike speaking to some of the highlights of the last quarter and the full 2025 year. After his remarks, we'll be open for questions. Mike, go ahead.

Thanks, Scott. Thanks, everybody, for dialing in, and we're pleased to review our Q1 '26 results and provide an update on our broad range of activities. The company achieved record production in the first quarter, generated very strong earnings and our cash flow and free cash flow forecast for '26 and '27 are steadily moving up. Some select highlights. Continued new well outperformance in both gas complexes, leading to production at the midpoint of guidance despite significant Q1 capital deferrals. The first 2 major facility projects in the Northeast BC infrastructure build-out, those being Aitken and Groundbirch, remain on schedule. Due to strong global liquids prices and our access to Pacific propane exports, our '26 NGL realizations are anticipated to increase by approximately 30% over 2025. Q1 '26 cash flow was $862 million, and that generated $202 million of free cash flow for the quarter. Our Q1 '26 net earnings were very strong $658 million. We have steadily improving '26 and '27 full year free cash flow outlooks. And net debt at March 31, '26 was $1.5 billion, which is below the long-term debt target of $1.75 billion and is approximately 0.4x net debt to cash flow. Looking briefly at production. First quarter '26 average production was 666,089 BOEs per day within the original guidance range. Unchanged '26 average production of 620,000 to 640,000 BOEs per day is anticipated. We intend to maximize the use of our new Dimsdale, Alberta storage capacity as well as existing long-term Dawn and California storage facility positions, along with potential in-basin production curtailment during periods of low prices, this spring and summer. We've also scheduled the vast majority of our '26 facility maintenance into Q2 during low gas prices, which keeps gas volumes offline. Today, that equates to around 70 million per day. And some of that is higher cost third-party gas. And that's all largely factored into '26 guidance and Q2 guidance. Briefly on financial results. As mentioned, we generated $202 million of free cash flow in the quarter, really despite extremely weak Western North American gas prices this winter. First quarter OpEx was $4.75 per BOE. That's down 8% from Q1 2025 and our full year '26 OpEx of $4.50 per BOE continues to be expected, and that's down 9% from full year 2025 as we continue to make the business better, primarily through our BC build-out. Full year '26 EP capital budget remains at $2.55 billion. That's following the $350 million reduction that we announced on March 4 of this year. We have identified an additional $200 million of what is primarily D&C capital that could be deferred from the '26 EP program should Western North American nat gas prices remain weak through the whole year. Tourmaline's exposure to international LNG prices and the increasing liquids pricing has improved current '26 free cash flow estimates to a little over $0.9 billion, and the free cash flow benefit from our exposure to JKM and TTF pricing via our LNG export-related contracts will not be realized until Q2, and that's due to the timing of LNG cargoes. So that actually -- that benefit was not in our Q1 cash numbers. Some marketing highlights. Our average realized net gas price in Q1 '26 was CAD 3.59 per Mcf, significantly above the AECO 5A benchmark price of CAD 2.05 per Mcf for that period, as we continue to reap the benefits of our diversified marketing portfolio and strategic hedging program. We have an average of 930 million cubic feet per day of natural gas hedged for the remainder of '26 at a weighted average fixed price of CAD 5.13 an Mcf. We have an average of 220 million a day exposed to international pricing, TTF and JKM in '26, and that systematically grows over the next 2 years. The company is also amongst Canada's largest propane producers. And similar to the natural gas business, that we have, we have a long-standing propane marketing diversification strategy in place. Currently, approximately 45% of our propane production receives the Argus Far East Index propane price. And with the benefits of this improved NGL pricing and reduced ethane production, we do expect '26 NGL realizations to average close to 30% higher than they did the prior year. Looking at the EP program. As mentioned, well outperformance compared to prior 5-year averages has continued in both gas complexes. In the B.C. Montney complex, '25 well performance was up 22% over the previous 5-year period, that means 2020 to 2024. In Q4 '25 and Q1 '26, this has continued. BC Montney well performance gas side is up 13% over the 2020 to now 2025 time frame and the Alberta Deep Basin is up 6% over the same time period. That's based on IP 30 rates because we haven't had the wells on for as long. Just some specific well highlights. We've done extremely well as we generally do. During Q1 of '26 in what we call the North Montney, we've delivered strong pad and well performance in all 3 sub complexes in the north. So at Aitken, the 5-well Birch pad averaged IP 90 rates of 3.4 million cubic feet per day and 419 barrels per day of C5+. At Gundy, the 11-well d-4-G pad tested at average peak rates of 25 million cubic feet per day and 130 barrels per day of C5+. So that's across 11 wells. That's the average. It is important for investors to know that we're choking almost all of our high-deliverability gas wells in this current low local gas price environment. Further north in Conroy, the 8-well La Presse pad averaged IP 90 rates of 4.8 million a day, and 283 barrels of C5+. Deep Basin also continued to deliver strong well results throughout the complex, not as robust as the BC Montney, but very strong for the Deep Basin, particularly on the liquid side. So the Resthaven 3-well Wilrich A pad came on production in March, has an average IP 30 of a little under 15 million cubic feet per day and 112 barrels per day of condensate along with that. The Ansell 08-11 3-well Wilrich pad, came on in February, average IP 30 of 11.7 million cubic feet per day and 217 barrels per day of C5+, which is well above normal. In the South Deep Basin, the Ferrier 02-20 2-well block pad started up in March, and it produced at average well rates of 724 barrels per day of C5+ and 2.7 million cubic feet per day of gas. And safe to say on a broader note, our year-end '25 2P natural gas reserves of 27.7 Tcf achieved with only booking 15% of current drilling inventories position the company very well as recent international developments render sizable economic reserves in stable jurisdictions increasingly attractive. On the EPI front, Tourmaline is the first Canadian company to be certified under the MiQ and the first company in MiQ's history to have certified integrated gas production and processing facilities. It applies to our full Northeast BC gas production base of 1.6 Bcf a day. And it positions Tourmaline to access differentiated markets where verified methane intensity influences procurement decisions in landed jurisdictions. We continue to progress the multiyear diesel displacement strategy. That's a cost savings and an emissions reduction exercise. We've displaced over 250 million liters of diesel now since we started this and saved over $245 million to date, and that includes the cost of the nat gas fuel replacement. Our new 10-year target is savings of $565 million. So these are material cost savings. And then finally, our Board of Directors intends to declare a quarterly base dividend of $0.50 per share in early June, which will be payable on June 30, 2026, to shareholders of record at the close of business on June 15, 2026. So I think that's it for any kind of formal remarks, and we're all here to answer questions. Thanks.

[Operator Instructions] First question comes from Sam Burwell out of Jefferies LLC.

I guess first off on gas dynamic like the West Coast, which has been a little bit of a headwind, looks open for the summer. So curious if you think that exports can pick up meaningfully over the next few months? And then have we seen any reaction in the Malin and PG&E strips from hydro generation tied to the Grand Coulee and that stuff? Or is that all still really yet to materialize?

It's starting to materialize as we look at BC, Pac Northwest and Northern California hydro, it's all moved down significantly from where it was. Jamie can talk to the strips. Really, all we need in California now is some heat. We still have over 1 Bcf a day of gas on GTN that should be going west that is backed up into Alberta. So we need to see PG&E improve first, and we think we will when they get some heat because hydro has moved off. The Grand Coulee Dam maintenance is underway, and we think that ultimately lifts AECO and Station 2. We think this happens during Q2, and there's a number of other green shoots that we've seen that we're excited about, but let's make sure it's not another false start. All 3 markets have moved up over the past week, but let's see that happen on a sustained basis. And Jamie, I think you probably paid more attention to the strip, so.

Yes, we do see ARBs coming into a place where we could expect exports to come back in July, August. And even just in the last couple of weeks, as Mike was saying, we've seen firmness in PG&E, Malin directly translate into better AECO strip. So these markets are clearly connecting right now. Some other additional points, Costa Azul started taking gas a little earlier than we expected. So that's the LNG plant in Mexico. And long has been our thesis that, that plant actually impacts the California corridor more than a Delaware egress point, and that's exactly how the strips reacted on feed gas, SoCal was the market that seemed to react the strongest. And -- that will further tighten the California corridor. As Mike was saying, it's about 1 Bcf of export loss out of the WCSB today. And to put that in perspective, LNG Canada has recently been getting to nameplate to running at 2 Bcf a day, averaged about 1.5 Bcf per day in the first quarter. Production in basin is up modestly. It averaged roughly 0.7 Bcf a day in the first quarter, but at many times, has been closer to flat. We're closer to flat entering into Q2, and we are flat on exit. We would normally with the LNG plant on at 1.5 going to 2 and production up less than one be in a pretty tight market. What has masked that tightness completely is this lack of exports into that West Coast market. Now this LNG plant is going to be on for 40 to 60 years ahead of us, while this West Coast export outage or a lack of economic pull is going to last until July if we get heat, in August, September, if we don't. And so we think this temporary disruption in how AECO is trying to balance is indeed going to be measured in months, and then we turn into a much tighter basin in the 2 years ahead of us. And when we look at a little further, we see the WCSB averaging over 1 Bcf of demand over the next 5 years.

Okay. Understood. And then just longer term, I'm curious what you think of Canada's entree into sovereign wealth? And could the Canada Strong Fund be a tailwind for a project like Ksi Lisims getting financed and getting to FID? And do you think that sovereign wealth or any other fiscal support can realistically drive additional LNG infrastructure on the West Coast beyond LNG Canada Phase 2 and beyond Ksi Lisims.

I'd say yes would be the short answer to that question. There's $25 billion of additional capital available. It certainly can't hurt.

Next question comes from Patrick O'Rourke from ATB Cormark.

I guess just thinking about the potential of the incremental $200 million capital reduction that you've pointed to, I think that probably most reasonable people could assume that you want to see how sort of the summer plays out from a storage dynamics probably overall, but also regionally. What's sort of the gating parameters around that decision point? And then to the extent that you're choking volumes and building DUCs here, does that act as a tailwind as well for the capital program in 2027?

Yes, it does and really as soon as second half 2026 because really, we went through the same exercise to some extent in 2025 and match the production growth curve to the improving price curve and ended up achieving our production targets for 2025. So in -- like by deferring production in Q2 and deferring capital expenditures in Q2, you make that cash all back up in the second half. And actually exceed it because you're going to sell into what we think is going to be a higher price environment. So yes, I think largely, you're correct on that assumption.

Okay. Great. And then with the update here, you realized some of the improved waterborne gas prices as well as some liquid pricing incremental free cash flow. Net debt is still below sort of the target level and alluded to distribution of that. Can you walk through sort of how you see the mechanics of incremental free cash flow distribution going forward?

I think it's a very dynamic time. Prices are moving dollars, sometimes almost $10 a day. And so our strategy right now is to receive this free cash flow. And we have some observations. One of our observation is, especially in NGLs, the backwardation is incredibly steep. It's a less liquid market. There's less visibility and liquidity. And so it backwardates steeply. And so it could very well outperform what strips say today. Our go-forward plan is to receive these higher cash flows definitely in Q2. Cash flows will benefit from the tension the war has created in all of our markets. And then once that cash is received, then we'll proceed with the decision on how it's going to be distributed. But you're right, we're below our net debt target, and we definitely have a practice of continuing to deliver excess free cash flow back to shareholders. At this time, we just want to make sure we have it in our pockets first just because the day-to-day changes and outlooks are more dramatic in this current environment.

Next question comes from Greta Drefke from Goldman Sachs.

I was just wondering if you could speak a bit about your latest views on the outlook for in-basin power demand growth driven by data centers up in Canada. What are you seeing in terms of terming specific conversations? And are you seeing any new regulatory tailwinds, too?

I'll start at the end of that. On the regulatory side, the federal government deferred or eliminated the clean electricity regulations, which promotes gas-fired power in Alberta. The Alberta government with Bill 8 stacked the regulatory process rather than run it in sequence. So logically, that should make it go a little faster. We've been exploring the possibility of co-locating with a hyperscaler at one of our sites and are really a year into that evaluation process, and we offer a lot if it's all competitive on a North American basis. We could do that or we could just simply be a provider of gas to another project. We don't have anything to announce at this point on our own initiative, but are well into it, and we'll certainly advise the market if something material transpires. Alberta is a great place to do this. I think our current government recognizes it. It's something that has to get done relatively soon because there's not an infinite number of data centers that are going to get built. And we think the whole industry in Alberta on the data center behind fence power gen looks a lot more legitimate as soon as a major announcement is made.

Great. And then just for my second question, I appreciate the color you provided on your outlook for local pricing over the next several months or so. But I was wondering if you could speak a bit more about your latest views on if you're looking to hedge out incremental local exposure in the near or medium term if you're able to.

Yes. If we're able to, I mean, the reality is the strips over the past few months really haven't offered anything that looks attractive, but we certainly intend to run with a larger hedge book than, say, we did 2 and 3 years ago. Brian, anything?

And we have picked up a bit more LNG hedging as well as taking advantage of the run-up in oil and liquids a little bit.

Thinking about storage as a mechanism in your effective hedge book. It's like a physical hedge. You're moving volume from one quarter to the next. And so the contango in AECO is steep. I think it's going to be an incredible year to store gas for Tourmaline. And we now have 2 Bcf in storage with 8 to go. So we have lots of options and lots of times in the months ahead of us to inject at when prices are low. And we expect to have many opportunities in the third and fourth quarter and the first quarter next year to withdraw that gas at a much higher price.

Next question comes from Josef Schachter from Schachter Energy Research.

Every time you turn on the TV, on the business channels, you hear about Open AI, Anthropic and all kinds of AI stuff. What's going on in terms of business side, like for Tourmaline? Are you finding benefits in the field or head office? Can you give us some examples of things that you're integrating into your system? And does that impact materially in terms of productivity? Does it impact your labor force? Just to get an idea of how a real company is using all of this new technology.

We're using it and evolving it in many aspects of our business currently from learning software in the field to optimize production for wells that are on plunger lift to drilling technology just behind the bit to learn and drill faster and faster wells. And then there's a whole myriad of opportunities within head office itself. AI bots kind of going through 3D seismic volumes, looking at the horizons that are outside what we're landing our horizontals in the Deep Basin and the BC Montney and can really complement an exploration program that we have going on already and are the only company in Canada at scale that is doing that. So yes, the opportunities are endless. It's not going to distract us from what our main business is right now. And as tools, I think you just look at it as a series of tools and use them effectively.

Can you quantify yet productivity improvements? Or is that -- is it too early?

Yes, I'd say too early.

Well, we have one tech that we're quite pleased with, and they're a private business called Ambyint. We partnered with them and they're steadily working across our fleet, and it's on the artificial lift side, so rod lift going to gas lift. And the quick math is with optimized well calls, it could be a 10,000 BOE day uplift for our business. And so that's one example of lower base decline. There's a slew of emission benefits and cost benefits on top of that. But we have found some real diamonds in our pursuit of looking at all the different applications that this can come into our business. And that's one we're really excited about and pleased with.

Next question comes from Jamie Kubik from CIBC.

We saw a major announcement last week with respect to M&A in the Shell and ARC transaction. Tourmaline historically been an active acquirer, particularly when gas pricing is weak. Would you be able to just discuss how the team is thinking about M&A in the current environment?

Yes. I don't think we've changed our mantra from what we've been saying over the past year, Jamie, that post mid-2025, we're looking at small complementary tuck-in asset deals in and around existing assets and infrastructure or infrastructure that we're going to construct over the next 4 to 5 years in BC. So we're not pursuing large M&A at this point in time.

Okay. And then we did see a disposal of an asset in this past quarter. Are further dispositions on the table? Or how are you thinking about that, Mike?

Well, that -- I mean that was really a long planned disposition. We sold our most mature production complex, a small component of the overall company and essentially are going to replace it with brand-new lower-cost production much earlier in life. And really, as we went through our M&A cycles, over the almost 20 years of the company, we've been pretty good at disposing of assets that we didn't really felt fit in the long term. And so there's no big dispositions being planned by the company right now.

Next question comes from Chris Grand, a Private Investor.

Thank you for thinking long term for investors. But in the short term, kind of tying into that last question, the ARC Shell deal. We can all see all the metrics in the PV-10, the production and the price they paid. And we know you used to do business with them or work there. Do you have any other comments about that deal, like how comparing and contrasting to what your assets are? And are there going to be any economies of scale that they're going to get that's going to impact do you? Any questions, any ideas along that?

I don't think there's economies of scale for us. From a macro standpoint, we hope this is the catalyst that get Shell to FID LNG Canada Phase 2. We know the metrics that, that deal happened as well, and they're at a much higher per share valuation for Tourmaline than where we're currently trading at based on existing 2P reserves. And I'm kind of sad that ARC is gone. This is a multi-decade company that's had a long storied history in the basin, and it's kind of too bad that they're disappearing, but that's the business transaction that was arranged.

Next question comes from Fai Lee out of Odlum Brown.

Mike, I just want to quickly just already a couple of questions about the Shell acquisition, ARC. But I'm just wondering, have you been seeing any increased interest from like given what's happened geopolitically, increased interest in the space from foreign buyers, like we saw Shell, obviously, but they had some unique need there. But what about other players that possibly could be looking to invest in Canada? What's your thoughts around that?

Yes. I think there definitely is enhanced interest by. We're seeing a whole lot of interest on the LNG side. And so we have a lot more approaches on doing supply deals for various liquefaction facilities across North America, and we're seeing more potential projects emerge that could add additional egress for the Western Canadian sedimentary Basin. So yes, it's exciting times. I mean natural gas, it's really evolved into the central core of the world's energy stack, and it's going to be like that for decades to come, and it's for all kinds of good pragmatic reasons. So we're excited. And just bear in mind that what's really exciting for us right now is that we're rapidly making a really good business that much better from well productivity to improving cost to a fortress balance sheet to decades of booked reserves to an unmatched high-quality drilling inventory. Every aspect of our business is getting better and lower Western North American gas prices are masking that in the short term, but it's going to be a double win for shareholders when this all turns around, and we think it can happen within a quarter on the local pricing front.

Okay. Yes. On that note, I know Jamie talked about the temporary reasons why AECO gas might be depressed right now. And I understand, it makes sense to take the actions you're doing in terms of more gas storage and increasing your DUC levels. But I'm just kind of wondering like given it's temporary, like what sort of AECO price we have to see before -- in the future to keep -- to avoid this kind of increased storage and DUCs, like what kind of AECO price, will be $3? What price would you be looking at?

Yes. When we're -- I mean, we don't plan to increase our capital budget from what we've laid out in that 5-year plan or the cadence of it. We'll make sure the first 2 major facility projects in the North Montney Phase 1 build-out are accomplished on time. When prices are getting weaker, what do we look at? It's on that inventory slide in our COD, our breakeven half-cycle economic price for the Deep Basin in the $1.90 to $2 range. So that's why most of the capital deferrals or cuts have been on that side of the ledger. Our BC Montney gas condensate complex, the breakeven is $1.40, which is partly why the whole build-out is happening in the first place. And so those are the numbers that caused us to cut capital, and we've got a very well thought out, very detailed capital program over the next 5 years in the BC build-out. As I mentioned, we'll continue to improve our margins and drop our costs.

Okay. That's great. And just a last quick question. I was just assuming when I read your press release that you're going to get some excess cash flow in the second quarter due to the Iran war and a little bit of a windfall. And I was just assuming it's going to be paid on special dividends, but it sounds like it may not necessarily be that case, and you might consider other options and which brings the question like under what -- what would cause you to think about share buyback perhaps?

Yes. Well, let's see how much free cash flow we have. And that's what Jamie was basically saying is that because things are so volatile and short term, let's realize the free cash flow win above the base dividend obligation and then make decisions on where it's going to be allocated.

Okay. But would you be necessarily looking at your share price or would be some other factors involved?

We'll look at all the various options.

There appears to be no further questions at this time. I would now like to turn the call over to Scott for closing remarks. Go ahead, Scott.

Thanks, Josh. Thanks, everyone, for attending, and we'll talk to you at the end of next quarter.

Ladies and gentlemen, this concludes -- sorry about that guys. Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.