Tourmaline Oil Aktie

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.

Good morning, ladies and gentlemen, and welcome to the Tourmaline Q4 2025 Results Conference Call. [Operator Instructions] This call is being recorded on March 5, 2026. I would now like to turn the conference over to Scott Kirker. Please go ahead.

Thank you, operator, and welcome, everyone, to our discussion of Tourmaline's financial and operating results for the quarters and years ended December 31, 2025, and December 31, 2024. My name is Scott Kirker, and I'm the Chief Legal Officer here at Tourmaline. 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. Go ahead, Mike.

Thanks, Scott, and thanks, everybody, who dialed in. So we're pleased to announce our Q4 2025 disclosed year-end reporting and update on '26 activities so far. So a few highlights. We had record production in Q4 of '25, and that carried on and set a new record in January of this year. We added 829 million BOEs of 2P reserves in '25, including a corporate record single year organic 2P addition of 457 million BOEs. We realized continued corporate operating cost reductions in Q4 of '25, down over 9% from the first half of '25 to current $4.66 per BOE. Peace River High asset sale was completed in February 2026 for proceeds of $765 million. And net debt at year-end '25 of $1.5 billion, inclusive of the impact of the Peace River High asset sale was down from Q3 '25 net debt of $2.3 billion and represents 0.5x forecasted '26 cash flow. On production, in addition to record Q4 production, our Q4 '25 average liquids production was a record 152,673 barrels per day. January '26 production averaged over 685,000 BOEs per day.

That's prior to the sale of the Peace River High asset. We've elected to terminate our discretionary deep cut gas plant deliveries in the Alberta Deep Basin those contracts expire. This will reduce corporate average ethane production volumes by approximately 20,000 barrels per day on a full year basis, but is expected to increase '26 operating netback by approximately $65 million and forecasted '27 operating netback by approximately $110 million, and that's through the elimination of deep cut processing fees as well as C2+ transportation and fractionation fees. And really, this is all part of the overall cost reduction and margin improvement initiative that's ongoing. Looking a little deeper at financial results. Q4 '25 cash flow was $890 million or $2.29 per fully diluted share, and full year '25 cash flow was $3.4 billion. As mentioned, we've sold the Peace River High complex to a Canadian senior producer for cash proceeds of $765 million. the company has sold its most mature highest cost production and we'll replace that with new low-cost production streams flowing through newly constructed Tourmaline facilities.

And although we pioneered the Charlie Lake horizontal play in the first place in '09 and 2010, this disposition allows us to enhance the focus on our 2 massive natural gas complexes. We intend to utilize the proceeds in the following way: $500 million for permanent long-term debt reduction and the remaining $265 million to fund in part the BC infrastructure build-out split between the next 2 years, and that's the Phase 1 build-out.

As mentioned, net debt year-end '25 was $1.5 billion, and that's down from $2.3 billion in Q3 '25. We've set a long-term net debt target of $1.75 billion. A few comments on the capital budget. We have updated the multiyear EP plan in the COV, and it's been updated for results in '25, asset sales, very strong well performance, new commodity hedges and the new cost reduction initiatives that we've realized to date. We believe that during these unusually volatile times, the best business approach is to just steadily reduce debt and continually improve the overall cost structure, and that's exactly what we're doing. Q4 '25 EP CapEx was $813 million, and that was within the original guidance range.

The combination of the Peace River High asset sale and the redirection of discretionary Deep Basin deep cut volumes will reduce total corporate production by a total of approximately 50,000 BOEs per day on a full year basis.

Importantly, the '26 full year EP CapEx program will be reduced by $350 million to $2.55 billion, along with a $50 million cut in our non-EP capital for a total CapEx reduction of $400 million. This reduction includes the $175 million of originally planned CapEx on the Peace River High complex and a further $175 million of expenditures in the gas complexes. We believe it's prudent to defer certain gas-focused expenditures until we see a sustained stronger local price as both AECO and Station 2 prices in the Western Canadian Sedimentary Basin and the prices in the Pacific Northwest and California are unusually low. The gas complex expenditure reductions will have a negligible impact on our '26 production guidance given much stronger-than-anticipated '26 well performance to date.

We have identified an additional $200 million of D&C capital that could be deferred from the '26 EP capital program if commodity prices remain weak. At strip pricing, Tourmaline's revised EP plan anticipates '26 cash flow of $3.4 billion and free cash flow of a little over $0.7 billion.

All else equal, for every USD 0.10 per Mcf that AECO pricing improves, our '26 cash flow and free cash flow increased by approximately $45 million. Similarly, because we are exposed to these markets for every dollar per Mcf that both JKM and TTF improved, '26 cash flow improves by $50 million and '27 cash flow by $70 million. Some comments on reserves. Year-end '25 PDP reserves were 1.47 billion BOEs, and that's up 20% -- 27%, sorry. Total proved reserves of 3.26 billion BOEs were up 20% over 2024, and our 2P reserves eclipsed the 6 billion BOE mark, and they were up 15% year-over-year. So after 17 years of full operations, the company has 27.7 Tcf of economic 2P natural gas reserves and just under 1.5 billion barrels of 2P oil condensate and NGL reserves. These are all pipeline connected to markets across North America.

And at year-end '25, we'd only booked a little over 15% of our current internally estimated drilling inventory of 26,500 gross locations. And that's kind of been our historical booking average of the total inventory for the last few years. It's always around 15%.

Reserve replacement was 356%, which is big for a large company of 25 annual production of 233 million BOEs with the 2P additions of 829 million BOEs. The company has elected to increase D&C costs across our entire booked inventory, including the previously booked inventory, and that's to reflect our steady migration to longer horizontals. They're 75% longer wells since 2018 and an increasing percentage of plug-in per style completions, mostly in the Northeast BC Montney. We also increased future facility capital in the year-end '25 report. So these onetime increases actually bumped up the 2P F&D for '25 alone by $3.21 per BOE. Looking at some marketing highlights. The company has an average of about 880 million cubic feet per day of nat gas hedged in '26, and that's at a weighted average fixed price of CAD 4.54 per Mcf.

In the first quarter, we had over 370 million cubic feet per day of our physical gas exposed to the premium price Eastern markets, which was good when they ran. So that's Dawn, Ventura, Chicago, Iroquois, Emerson and ANR Southeast. And that provided a strong uplift to our Q1 cash flow.

We have entered into a long-term natural gas storage agreement with AltaGas at their Dimsdale storage facility in Alberta. We did that in the second half of 2025. Subsequently, AltaGas has announced a positive final investment decision for the Phase 2 expansion of that facility. So in '26, we'll have access to 6 Bcf of storage capacity, and that starts in April of this year. And then next year in mid-'27, it increases to 10 Bcf and that's for a 10-year term. And we view the acquisition of an additional large storage position as a strategic opportunity to improve financial performance and enhance our operational flexibility in periods of natural gas volatility. And it's really just another aspect of our ongoing efforts to fully integrate our natural gas business.

Updating the cost reduction and margin improvement activities. We did embark upon that initiative in mid-'25, and the focus is on reducing all aspects of the cost equation. And we're excited by the rapid progress that we've made already. So Q4 OpEx was $4.66 a BOE. That was down 3% from the third quarter in 2025. and 9% from the first half of 2025 when costs were $5.14 a BOE.

The Peace River High complex sale will reduce go-forward corporate OpEx by a further 7%. So our '26 OpEx guidance is $4.50 per BOE. With the success of the cost reduction initiatives to date, we are revising our aggregating aggregate operating and transport cost reduction target that was $1 per BOE by 2031 to $1.50 per BOE and approximately $0.70 per BOE have already been achieved since the first half of '25. We've also entered into agreements to control our frac sand capacity in BC via a transload facility.

It's expected to commence operations in Q2 of '26. in this vertical integration of our sand business, it's estimated to save a minimum of $40 million per year in capital costs. The ongoing Northeast BC infrastructure build-out will systematically reduce costs as well as various components are completed.

First major component completed is the liquids hub and associated pipelines with it, that's located in proximity to the Aitken gas processing complex. By 2031, Tourmaline expects up to $500 million per year of aggregate commodity price independent structural cost reductions, and that's compared to the first half '25 cost structure.

And that will flow through to lower corporate breakevens and our free cash flow margin improvement. On the EP front, in 2025, we drilled 320 gross wells, and we led the Canadian industry with a total of 1.7 million meters drilled during the year. In '25, we delivered our best overall well performance in the past 6 years in the BC Montney gas condensate complex. We're 22% higher in '25 than the previous 5-year average, and that's based on the IP90 of 102 wells. And this outperformance has been across the full suite of the BC Montney assets from Aitken, Birch, Gundy in the north, to Groundbirch, Doe, Montney in the south., and it speaks to the size and scale of this fully derisked asset base.

We continue to increase lateral length, 25 Deep Basin and Northeast BC program, averaging 8,400 completed lateral feet, and that's up 1,100 feet over 2024. D&C cost per foot in the Deep Basin and BC are actually now in decline and the stats are quoted there.

The 26 EP capital budget reduction that we've announced, the $175 million will not impact the original startup of timing of the Aitken and the Groundbirch Manias gas plant projects in BC. Aitken is on schedule for a Q4 '26 completion and Manias completion is expected in Q4 of '27. Our ongoing new zone new pool exploration program has now resulted after approximately 5 years in 2.55 Tcf equivalent of 2P reserve additions and approximately 1,350 Tier 1 and Tier 2 drilling locations. And we've got several high-impact exploration and delineation wells planned in the '26 program. We figure this is by far the largest and most consistent exploration program in the basin.

On EPI, our environmental performance improvement, importantly, Tourmaline has achieved Grade A certification for methane performance across our entire Northeast BC asset base. That's under MIQ's global methane certification standard. We are the first Canadian company to be certified under MIQ and the first company in MIQ's history to have certified integrated gas production and processing facilities.

And the timing of this is significant given the ongoing negotiations on methane between the province of Alberta and the federal government. There are several other EP highlights as there always are detailed in the release, and you can read those at your leisure. On the dividend, our Board of Directors has declared a quarterly base dividend of $0.50 per share payable on March 31, 26 to shareholders of record at the close of business on March 16, '26. And the weak Western Canadian Sedimentary Basin local gas pricing and unusually low pricing at the PG&E and Malin sales hubs this winter will limit free cash flow and constrain our ability to fund a special dividend in Q1.

Sustained stronger pricing and our ongoing margin improvement activities are expected to lead to further base dividend increases and special dividends are anticipated to be used in those periods of particularly strong pricing to return the majority of incremental free cash flow to shareholders. So that's it for the formal remarks, and we're here to answer questions.

[Operator Instructions] Your first question comes from Kalei Akamine from Bank of America.

My first question is on the capital flexibility. You called out potentially taking $200 million of additional capital out of the '26 budget. With the breakup season kind of around the corner, I imagine that decision would be imminent. What factors would influence your decision? How do you allocate the reduction across the asset base? And in the case where there's additional flexibility needed in coming years, should we think about what you've done here as the template for future actions?

Yes. Well, cutting the capital budget in '26, sorry, is exactly what we did in '25 and '24, but particularly weak local pricing and PG&E pricing, they're both below $2 was the reason for that. Yes, we do have flexibility to cut an additional $200 million.

Again, it would be focused on D&C because we want to keep the 2 plant projects in BC on schedule and total facility spending in BC is sort of between $250 million and $300 million for those particular projects. So we do have quite a bit of flexibility. You mentioned breakup. It gives us a bit of time, so probably 2 to 3 months to watch where prices go. And we are starting to see AECO move upwards from its sort of $1.60 level. And PG&E was constrained. That was -- usually, that's a huge premium market for us, usually trades USD 2 above Henry Hub. Now it's $1 below Henry Hub, which we haven't seen in the 9 years we've been selling there. It's actually always a big winner in our portfolio.

They had no winter. They had an enormous amount of rain. So lots of excess hydro. And then there's a particular maintenance project at the Grand Cooli dam where they have to do dry dam maintenance that starts on March 15. So they've been emptying that reservoir all winter, and that's been hammering 6 gigawatts a day into that local market, which is a bit oversupplied anyway.

6 gigs is about equivalent of a Bcf a day of gas. So it certainly hasn't helped gas. Now we expect that price to start improving when the maintenance starts. And then that 6 gigs has gone for an extended period of time. First of all, they do the maintenance and then they have to refill. So we're positive on our outlook for where PG&E prices are going to go. And AECO and PG&E are directly connected, and you can watch them. They've been tracking each other really for the past month. And they're both going to head up. I didn't mention that it's $45 million for each dime on AECO.

So if we got to the marvelous price of $2.25, all of a sudden, our free cash flow is over $1 billion. So it kind of puts it in context. So we have some time. We certainly have some flexibility. The first EP capital cut because of well outperformance doesn't affect the production. If we cut more capital out of the budget, it would affect production.

I also think Costa Azul LNG is starting up sometime in the second half, so that should be supportive to that macro that you're talking about in California. The next question is just on plug and perf. We've seen more of the Montney program shifting from Ball drop to plug and perf because of the results, I would assume. If that is more capital efficient, more resource for less dollars, could we see you fully shift your program to plug and perf? I know it's really hard to fix something that isn't broken, but wondering if there are any incremental benefits that could be realized.

Yes. I mean we're up to 75% of the wells in BC on plug and perf. And we continue to evaluate. It's particularly advantageous when you're in the more liquid-rich tighter Montney horizons. And so we're certainly using it there. And we did take the entire booked inventory well cost up primarily because of this evolution to plug and perf style completions.

So our 2P F&D because we're carrying the booked inventory would have been $588 a BOE rather than the 908 because we basically recalibrated the entire inventory and the capital all in year 1. So it sets us up nicely for even lower F&D in future years. So we're always working on it and figuring out the best recovery, the best deliverability and the best economic return on the wells.

Your next question comes from Sam Burwell of Jefferies.

I wanted to piggyback on Kale's question on the CapEx deferrals. I mean, first, were these in the Deep Basin primarily or in Northeast BC or spread all over the place? And then how does this impact 2027 and beyond? I mean, is there CapEx that could be incremental to the numbers in the EP plan? And if so, is there upside to production? Or is this sort of timing deferral already baked into those numbers that we're looking at in the EP plan?

The deferrals and cuts were more in the Deep Basin than anywhere else. And one flexibility option we have, of course, is to continue to drill the pads and not frac them because the stimulation piece is 60% of the cost. And so that's essentially what we did in the second half of 2025. We shaped the production growth curve to the improving price curve. And December prices actually were good in '25, and we're able to do that very quickly. Deep Basin breakeven is about $2 an Mcf. And so that's why the majority of the capital deferrals have been there. The BC Montney is $1.40 for reference. We can add production into 2027 if we have a much more favorable pricing environment. I mean, right now, we're weak locally at AECO and Station 2 and on the West Coast in the U.S. We're strong in the East and obviously, a recent tailwind with our exposure to JKM and TTF. So we remain very flexible. I think we can pivot faster than anybody with our EP program, and we will.

Okay. Great. And then next one, just on the ethane rejection decision. Is that idiosyncratic to just those particular contracts at certain plants, coupled with the desire to cut costs? Or is this any wider indication of ethane recovery economics across the basin?

Yes. The only place we recover ethane is in Alberta. So none of the BC build-out is impacted by that because there isn't an ethane business out there. But yes, it's a tough business, and it's hard to make money. We've been in those deep cuts in the Deep Basin outside operated for an extended period of time. And generally, we make very, very little to nothing of ethane. And even though it's such an important feedstock in the petrochemical business, the gas in Alberta has so much ethane in it that as soon as the price starts to improve, someone downstream goes and recovers that ethane and kind of keeps the market very, very weak.

And so those contracts were coming due, and it was an opportunity for us to save costs. And it fits perfectly with this broad initiative we have across the company, which is really working.

So you're going to get a double win when our local prices finally improve because we're doing a whole bunch of things to make this business a whole lot better, and it's all masked by our very low sub-$2 AECO prices in the connected basin. So when those improve and they will, you'll get kind of a double win. You'll get the top line improvement off the improving gas prices and then all the underlying improvements to the business will just add to that.

Your next question comes from Greta Drefke of Goldman Sachs.

My first one is just on the return of capital outlook. Beyond the base dividend, can you speak to the AECO pricing environment that would position Tourmaline to return to paying out a special dividend? Do you see a path towards returning to special dividend payouts by the end of this year? Or would you expect it to return in 2027 or so?

So we are always available and willing to sweep additional free cash flow to shareholders and our preferred method has been a special dividend. Prices are changing quickly and our cash flows can change quickly, too. Just with the TTF and JKM move that we've seen over the last couple of days alone, that's added several hundred million dollars to our forward outlook of free cash flow. And we see that as not yet settled. It's still transpiring. And if LNG out of that region, the Middle East is constrained for more than a month, we see a pretty dramatic change in global S&D that would could propel JKM and TTF prices to a point where free cash flow is well over $1 billion for Tourmaline. So we're monitoring that. It's also affecting our FEI pricing at propane.

That's up quite a bit relative to where it was last week for our forward outlook. This is also adding to our free cash flow outlook. And as we march through the year, we'll continue to monitor our forward free cash flow profile. And if there's ample free cash flow over and above the base dividend, we will return it.

Great. That's very helpful. And then for my second question, I just wanted to ask a little bit more on the power demand outlook for the basin. Can you speak a little bit about your latest conversations with regulatory entities, hyperscalers or other parties on the potential for power demand build-out relating to data center demand in Western Canada? Have you seen time lines or just broader conversations progressing as expected? And have these discussions been of the scale or magnitude that would encourage you to participate in a potential project?

We've been -- we're a year into a process exploring the possibility of Cold Lake locating near one of our natural gas plants. We think Alberta has all kinds of advantages. We have advantages because we've got land and water and power redundancy and fiber connection and CCUS capability of a hyperscaler wanted a full green solution, if you like. We will know what we're going to do specifically this year in 2026.

But we're excited about what's happening in Alberta altogether. There's a couple of on-grid projects. We expect to see an announcement on one of those, and we think that will be very good for the basin and the market's understanding that this can be a big growth opportunity for Alberta. By 2030, just adding up some of the behind the fence opportunities and the 2 on-grid projects we kind of see it as a minimum 1.5 a day of gas consumption inside the basin. And that would be ahead of LNG Canada Phase 2. So that would be very good timing for the S&D dynamics in our basin. Anything you want to add, Jamie?

I would think that these dynamics extend just beyond the Alberta border as well into areas Tourmaline can easily reach with gas. As we've seen data centers be built out, we would kind of characterize the first phase as on-grid power consumption where it was available. Alberta is still in that phase. The second phase was reigniting brownfield assets or mothballed assets.

And the third phase has been brand-new greenfield development with behind the fence power generation matched with the data center. And those assets have moved north and west. We've seen far more announcements of behind-the-meter data centers, west of the Great Lakes into the Dakotas and the Montana. And those are assets that Tourmaline can access with gas, and it will also tighten the markets that Tourmaline already accesses, whether it be on Northern Border or into the Great Lakes region or even into the Malin market. And so as we see these build-outs, we're excited for the opportunity to participate in the province of Alberta, whether it be our colocation project that we're directly involved in or a firm supply agreement with a project that is near one of our asset bases.

But we also think that Tourmaline's gas in the western part of the Northwest of the United States is going to have preferential access to the vast build-out that's already occurring into basins that frankly have a declining local supply environment. So it's both a local and a broad strategy at Tourmaline, and we see probably the next year being a pretty critical year to see all these things frame up FID and put real dollars to work in consumption that we're going to enjoy '27, '28 and beyond.

Your next question comes from Aaron Bilkoski of TD Cowen.

You've been pretty nimble with the shorter cycle E&P capital cuts. But I'd be curious to know if there's a scenario where you would lower the longer-term growth trajectory through 2031.

Well, I think we want to keep the first 2 plants in the Montney build-out on schedule. So as I mentioned, so that would be Aitken and Groundbirch Manias. If gas prices don't recover and they're lower than what any of us are actually expecting getting towards the end of the decade, we have flexibility around the timing of the Phase 2 of the BC Montney build-out. I mean we can take a year off if we need to and build significant free cash flow in that particular annum. So we're just going to see how it plays out. But as you mentioned, we are nimble and can pivot quickly.

The next question comes from Josh Silverstein of UBS.

I wanted to touch on the LNG exposure that you have given the capacity and contracts signed and to understand some potential upside exposure. It looks like you're assuming kind of $12 to $13 JKM versus $3.75, $4 Henry Hub. I'm guessing there's probably kind of an all-in cost of maybe $5 to $6 to get that JKM price. So can you just talk around some of the sensitivity around that if we remain at kind of this $10, $12 spread, just maybe how much upside there is?

Josh, it's Jamie speaking. So your numbers are roughly correct. We ran the strip that you're seeing for '26 and '27 in the 5-year plan on March 2. So that would have just the first day of this international price move incorporated within it. We have today over 200 million cubic feet a day of LNG capacity. That extends towards 330 million cubic feet a day over the next several years. The details are in the deck. We've only hedged roughly 1/4 of that. That's also in the hedge disclosure available in our financials website. We have taken steps to lock in some of the spike that we've seen, but we're totally aware that a long-term outage, specifically out of the Qatar LNG plant would rapidly reshape the S&D dynamics on the water, and we are available for that upside, especially in the months ahead and into '27 as our portfolio also expands into these markets.

So the sensitivity is a $1 change in JKM or TTF together is roughly $50 million of free cash flow this year and $70 million next year. And we've seen these. Obviously, these markets go into the 20s, 30s, 40s on supply disruptions before. So we're aware that it's a very high convex market, and it could end up being a windfall, and we're widely open to it.

And just to understand, that's a dollar move higher relative to what it was trading at or that's a spread change?

It's just a sensitivity. So I'm talking about, yes, holding Hub flat. If JKM and TTF move $1, that's your sensitivity. So it's a sensitive of just the floating market. We're not going to get into the swaps and the deductions, et cetera. Those are all confidential contracts, but your characterization of roughly $4 to sometimes $5 less is a fair estimate, inclusive of our transport cost to the Gulf.

Got it. That's helpful. And then just on cash allocation, you're $1.5 billion at the end of the year. You're taking $500 million down from that. You're at $1 billion. You're well below the $1.7 billion target.

Is the idea that sometime this year, maybe use that some way if it's not going to special dividends, could you use it for acquisitions, some additional storage opportunities? Or do you actually want to stay around kind of the $1 billion number, maybe kind of use the balance sheet if natural gas prices move lower?

Josh, I just want to add a quick clarification. In our financials, because the Arch is available for sale, our net debt includes the proceeds. So the $1.5 billion is after receiving the effective consideration of the Arch. And then maybe I'll let Mike talk about our M&A outlook.

Yes. I mean, right now, the M&A is focused on small asset tuck-ins in and around existing infrastructure or infrastructure to be built. So we're not looking at anything large at the current time. And persistence and patience are the key to pre assets out of large companies. And so we'll continue with that approach. But M&A is not a big piece of the equation right now.

Your next call comes from Jamie Kubik of CIBC.

Just with respect to Ford pricing, AECO and Station 2 aren't really sustainably above $3 a DJ until 2028. Should we think about potential for shut-ins through the summer from Tourmaline? And I guess, when do you expect that forward pricing turns for the better here?

Yes. If the price gets low enough, and we've shut in before, we're actually -- of course, we're always thinking the price is going to go up, but we are quite constructive, and Jamie and I can talk to that. Our storage position starts to factor into that summer equation. We can inject, I think, 67 million a day this summer, but that number in 2027 summer triples, and that becomes a meaningful volume.

And we can be very nimble about when we inject and when we withdraw. It's a very high deliverability reservoir. And again, we know quite a bit about it from previous employment. It's actually something I worked on at Shell many decades ago when it actually had producible gas in it. So it's kind of fine that way. Just some comments on LNG Canada and it's on and gosh, the price is $2 or less, what's going on. Part of it is that California equation that we talked about already, and it is putting a cap on AECO because it is so weak.

And we need to get that 3 Bs a day out of the West Gate and the other B that comes down through the West Coast system into the Pacific Northwest to clear. And we see the PG&E prices will start to help with that. And there's an order of fill with the LNG Canada facility. So the first train, most of the fill came from the direct connects that a couple of the large operators have.

And then it was -- as you brought Train 2 on, the first volumes for that were off the Enbridge system. So that meter station is Sunset West. And so the last station to get gas, which is the one that affects AECO and the NGTL system is Willow, and it's had really strong volumes over the last 3 or 4 weeks. And so AECO, NGTL get the positive impact last. And storage, if you look at it, will -- in about 7 days based on the weather, will eclipse the storage withdrawal that we had in all of last year's winter. So we're going to end up well into the 200s of withdrawal. That's positive. And when we think you'll start seeing it set up is when there'll be really tepid injections in April and May when you actually have reasonably warm weather. And we think that's what starts to move the AECO and Station 2 prices up. Anything else you guys want to add or...

I would say the other thing is we closely study the supply side of the equation locally, and we are not seeing meaningful supply growth in the basin. The numbers we see would be well shy of 1 billion cubic feet a day.

Exit or exit was actually down. February was much milder, so we didn't have freeze-offs this year, but we still average, call it, 0.6, 0.7, and then that's spinning to, call it, 0.4, 0.5 today as we see supply. So the local FD is good. It's -- you can't have AECO too strong because you need to be able to clear transport economics into our main export hub of Pac Northwest and PG&E. And so as that market strengthens, AECO can strengthen. There's no long-term glut issue locally. It is this idiosyncratic demand issue we've had with just a very bizarre winter, which was very East focused and not very West focused.

Okay. Could you maybe talk a little bit about the potential for turnarounds in Q2 or Q3 with respect to terminaling or even perhaps more broadly and how that could possibly help the situation?

Well, we kind of schedule our turnarounds or try to, when the scheduled TC and Enbridge turnarounds are happening. So it's about the same as last year. I think the scheduled pipeline turnarounds from the big midstreamers is a little bit less for '26 versus 2025, particularly on the GTN system, which impacts us.

Your next question comes from Fai Lee of Odlum Brown.

I'm just trying to get my head wrapped around your 5-year plan and the AECO pricing assumptions. Given the future strip for AECO seems to be closer to $2.50, which is what we're seeing in 2027. Just trying to understand how I can reconcile that with the $4 that you have for 2028. And is that something related to the PG&E like demand, if that improves that you see moving up closer to that? Or what's your confidence interval around the $4 outlook for 2028 and beyond?

Fai, this is Jamie speaking. So the first 2 years, as you mentioned, are on strip, and we just honor the strip that's offered on the date. We are totally aware that markets will disconnect to the upside and the downside in any given year. And so the flat price deck is what we think would be a balanced outlook at a fixed price. So in our perspective, $65 WTI feels mid-cycle.

$4 Henry Hub, given the dynamics we see at play in the United States where basins are starting to have performance degradation feels like a new normal for a mid-cycle price. We are aware there will be volatility on either side of that. And then in a $4 hub environment, we believe AECO should price at transport economics and transport economics would imply a basis of roughly USD 1.

In the current foreign exchange environment, USD 1 basis is effectively offset by the FX. So CAD 4 would be your implied AECO price. So this is, from our perspective, a mid-cycle look at Tourmaline's cash flows. The reason why we felt flat deck was a good illustration here is the margin improvement of the business is better borne out. You can see the margin improve on an annum to anum basis as we grow this business in BC, which is our most profitable rock. If you were to run strip every day, the contango turning to backwardation was always masking that, which was hiding this margin improvement that's inherent in the asset base, even though year-to-year, you'll definitely see it come through in the financials. So we thought the flat deck was a better way to illustrate how the profitability of the business was getting better in the out years.

Yes. I understand the rationale, and I don't have an issue with what you've just said. I'm just trying to understand if the reality turns out to be closer to the future strip, which is closer to, call it, $250, $255, does that change your marketing strategy or your -- a lot of been talked about capital plans, I guess, as well. But how does -- how are you set up your 5-year plan if the outlook isn't really $4? And I guess, would you consider like in 2027 and beyond, you're increasing your AECO exposure. Would that change if it's closer to the $2.50 in reality?

Yes, everything would change. So I did reference that when Aaron asked his question, I mean, we can slow down on the North Montney Phase 2 build-out in BC. So that's addressing the capital side of the equation. We are the most diversified producer in North America. So right now, it's about 1.3 Bs a day of our 3 Bcf a day is exported.

And usually, we win on those markets. So this winter, we did not win on California. So we'll continue to look for diversification opportunities, which help the overall financial picture of the company. But we are very flexible and nimble as has been referenced on the call, and we know the price breakpoints and when we should slow down and when we should speed up. And so we are paying attention to that every single week.

Okay. And just really quick, is that -- I know you've given the sensitivity for 2026 for AECO, but you haven't for 2027. Is that just because of that nimbleness and things can change? Is that why?

It would be slightly larger, call it, 25% larger in '27, and that's mostly a flexibility of hedge book.

There are no further questions at this time. I will now turn the call back over to Scott Kirker. Please continue.

Thank you, operator. Thanks, everyone, for participating. We look forward to our discussion next quarter. See you then.

Ladies and gentlemen, that concludes today's conference call. Thank you for your participation. You may now disconnect.

Good morning, ladies and gentlemen, and welcome to the Tourmaline Q3 2025 Results Conference Call. [Operator Instructions] This call is being recorded on Thursday, November 6, 2025.

I would now like to turn the conference over to Scott Kirker. Please go ahead.

Thank you, operator, and welcome, everyone, to our discussion of Tourmaline's financial and operating results as at September 30, 2025, and for the 3 and 9 months ended September 30, 2025 and 2024. My name is Scott Kirker, and I'm the Chief Legal Officer here at Tourmaline.

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 our year so far. After his remarks, we'll be open for questions.

Go ahead, Mike.

Thanks, Scott, and thanks, everybody, for dialing in. We're pleased to go through Q3 and then answer questions that you may have. A few highlights. Q3 '25 average production of 634,750 BOEs per day was at the high end of our anticipated guidance range of 625,000 to 635,000 BOEs per day despite storage injections and shut-ins during the quarter. We're pleased to announce that we have entered into a long-term natural gas storage agreement with AltaGas at their Dimsdale storage facility, and we view the addition of another large storage position as a strategic opportunity to enhance financial performance and strengthen operational flexibility in volatile natural gas price environments like we just went through this past summer.

We've also entered into 2 short-term and long-term LNG gas supply contracts which complement our existing extensive portfolio. Looking specifically at production, fourth quarter production is expected to average between 655,000 and 665,000 BOEs per day with a '25 exit volume of 680,000 to 700,000 BOEs per day. Our third quarter liquids production of a little over 147,000 barrels per day was up 4% quarter-over-quarter. And our '26 average production guidance of 690,000 to 710,000 BOEs per day remains unchanged as does the current multiyear EP plan, which is forecast to yield 30% high-margin production growth to 850,000 BOEs per day by 2031.

Third quarter 2025 cash flow was $720 million and third quarter '25 earnings were $190 million. Our third quarter realizations were impacted by unusually large natural gas export maintenance outages, both the East Gate and the West Gate. As a result of these outages, AECO and Station 2 pricing averaged $0.64 and $0.48 per Mcf, respectively, during the quarter. And while we curtailed gas supply during the weakest local price days, the sustained low local prices were the primary reason for lower than our expected third quarter cash flow.

The curtailments on export pipelines reduced our volumes accessing downstream markets as well, and that includes our premium markets, such as the Gulf Coast and the Western U.S. by approximately 155 million cubic feet per day. So instead, these volumes were sold into AECO and Station 2 spot prices, and that meaningfully impacted our September natural gas revenue. On a positive note, the force majeure on the Great Lakes pipeline ended in early October and East Gate exports are at normal levels and the West Gate maintenance ends during this month of November. Looking ahead, with the benefit of LNG Canada demand creating additional capacity on local egress pipelines, second and third quarter 2026 AECO pricing is currently averaging $3 an Mcf compared to $1.18 for the same period in 2025. And we think additional upside should be created if AECO basis tightens further, and that is what we anticipate happening.

Third quarter 2025 EP expenditures were $825 million. The full year EP capital budget remains unchanged at $2.6 billion to $2.85 billion. We closed a $71.7 million transaction with Topaz Energy Corp., whereby Topaz purchased a GOR on the recently acquired Saguaro and Strathcona Groundbirch Northeast BC Montney development lands. And in addition, on October 28, we completed a secondary offering of Topaz common shares for gross proceeds of approximately $230 million.

Moving to marketing. Lots of activity as we continue to vertically integrate our gas business and maximize future realized prices. We have an average of 1.2 Bcf per day of nat gas hedged for the remainder of 2025 at a weighted average fixed price of CAD 4.33 per Mcf. This includes 57 million cubic feet per day hedged at a weighted average price of CAD 20.13 per Mcf in international markets and 109 million cubic feet per day at a weighted average price of $6.86 per Mcf in the Western U.S. markets. Q3 '25 AECO and Station 2 nat gas prices were the weakest in over 30 years. And as mentioned, that negatively impacted cash flow. However, prices are improving thus far in the fourth quarter and the 2026 strip price outlook continues to migrate upwards.

We are pleased to enter into that Dimsdale storage deal. We'll have access to 6 Bcf of storage capacity starting in April for a 10-year term with the ability to increase to 10 Bcf in the event that AltaGas takes FID on Phase 2. And we view the addition of another large storage position as a really strategic opportunity to enhance financial performance and provide operational flexibility with these very volatile prices.

On the LNG front, we've entered into several new supply contracts as detailed in the release, and I won't go through them, but they're there for you to read. In aggregate, we'll have an average of 213,000 MMBtus exposed to international pricing in '26. That will grow to 250,000 by exit '27 and 330,000 by exit '28. So a very attractive progression.

Turning to the capital budget and the EP plan. As mentioned, spending in the quarter was $825.5 million as we executed capital projects deferred from Q2, along with the original Q3 budgeted items really to prepare for incremental production volumes in advance of higher anticipated winter gas prices, which are materializing. Our full year EP spending remains unchanged for 2025 and 2026. The '26 EP capital program is $2.9 billion, and that is unchanged from the release on July 29, 2025. Utilizing current strip pricing, our EP plan anticipates '26 cash flow of approximately $4 billion and free cash flow of approximately $0.9 billion. The strip pricing includes a '26 AECO basis of $1.66 per Mcf, and we anticipate that basis tightening towards USD 1 as the basin dynamics adjust for LNG Canada's demand.

And for every USD 0.10 per Mcf that AECO basis tightens, our '26 cash flow and free cash flow would increase by approximately $50 million. And should natural gas prices weaken in 2026, we certainly have the option to reduce capital spending as appropriate to optimize free cash flow and our planned shareholder returns. Approximately $200 million to $250 million of currently planned capital spending could be deferred in such a low price scenario, and that would really have only a minor impact on '26 production guidance.

On our cost reduction focus and margin improvement initiatives, the ongoing Northeast BC development project and infrastructure build-out will provide both significant growth and margin expansion by improving all of our operating metrics. Q3 2025 corporate OpEx of $4.80 per BOE was down $0.34 a BOE from the first half of this year, so approximately a 7% improvement. And early components of the Northeast BC build-out have been completed, and that has initiated the cost reduction progression and is contributing to the reduction in OpEx in the third quarter, and this process will really accelerate going forward.

The Northeast BC development project is anticipated to systematically reduce combined corporate OpEx and transportation costs by at least $1 per BOE as it is put in place over the next 6 years. And we see the opportunity for meaningful progress on this target in 2026 and all subsequent years. And there is potential to increase the overall total long-term target moving forward. We have a comprehensive corporate focus on reducing all aspects of the cost equation as well as our per well EP capital costs in 2026. So we're targeting a 5% OpEx reduction in the Deep Basin next year and targeting a further 5% reduction in D&C costs over currently budgeted levels. And these reductions are not captured in the multiyear EP plan yet because we'll make sure we realize them first.

And we've always had a very strong cost structure, and we plan to make it even stronger going forward. We have elected to pursue the potential sale of our Peace River High light oil and gas complex, so the Charlie Lake Play, which we actually pioneered back in Duvernay Oil Corp days. If completed, this sale would further lower corporate OpEx and provide proceeds that could be reinvested into our higher-margin BC growth assets or emerging EP opportunities that we've assembled in the Deep Basin. So this initiative is just a subset of the significant internal value creation opportunities that exist within the company's overall portfolio.

Specifically on E&P in the quarter, we drilled 68 wells, completed 88 wells and entered the fourth quarter with 38 DUCs, the majority of which are expected to be completed in the near term should gas prices continue to improve. We were very pleased our 25 Northeast BC Montney IP90 well performance to date is up 26% over the 5-year average performance as we drill steadily longer horizontal wells in that complex and the percentage of plug and perf style stimulations has been increased. And despite these more expensive completions, our 2025 Montney D&C costs are trending down on a per lateral foot basis. Our new pool new zone exploration success continues across all complexes, and we have 12 to 15 new pool or follow-up delineation wells currently in the Q4 '25 and 2026 drilling program. So lots of exciting opportunities on that front.

On the dividend, our Board has declared a special dividend of $0.25 per share. That will be payable on November 25 to shareholders of record on November 14, 2025. And the company intends to declare the quarterly base dividend of $0.50 per share in December. We commenced paying special dividends in September of 2021, and that special dividend has varied between $0.35 per share and $2.25 per share until this quarter where it's $0.25. And while the '26 free cash flow outlook continues to improve, we will continue to find the balance between the planned EP growth program and the size and cadence of the special dividend.

And I think that's enough for formal remarks, and there's 4 of us here ready to answer questions you may have.

[Operator Instructions] Your first question is from Kale Akamine from Bank of America.

I want to start by asking on the Peace River sale. I'm wondering if you can give us any clues as to how you're thinking about the value of that asset. And I guess, fundamentally, if you don't see the price that you want, would you consider retaining the asset? And the part B of the question is, this is essentially a fully developed position that comes with midstream, gas processing, et cetera. Is there any chance that you would hold on to certain assets?

I'll kind of -- thanks, Kale. Not going to give you what our price expectations are at this point because the process is going on. I think you would appreciate that. If it doesn't hit a certain value, we're not going to sell it. You're right, it is a fully developed asset, and I think it's very attractive to people that are looking for new opportunities like that. It would be a great way to start a company. And I think we'd sell it all together rather than break it up. And I did mention in the formal remarks, I mean, it's -- this is a play that we actually invented, started it vertically in Duvernay Oil Corp. days, created a company called X Shaw, ended up buying it back when Tourmaline was in existence. And then the play at a reverse where we had a different application of horizontal multiphase fracking drilling for the Charlie Lake, and it's worked extremely well.

So why are we selling it? Well, the reality is that the returns from investing in our 2 very large gas complexes kind of always outstrip the returns from growing the Peace River High asset in a material way. And so it's been essentially on maintenance capital for 4 to 5 years. And we think we have a whole gamut of opportunities in both gas complexes, and we can use the proceeds to kind of more profitably grow with lower OpEx in those 2 gas complexes. So that's kind of the rationale behind it.

That's great, Mike. I appreciate that. And for the second question, in the release, you called out a handful of what I'll call cash management items. And given the recent price environment for AECO Gas, I think that's prudent, although things seem to be on the mend today if we're looking at AECO prices. We just talked about the Peace River sale, but there's also Topaz equity and there's CapEx deferrals that you have in your back pocket. I'll leave the Topaz question for someone else, but I'm wondering how you would characterize the CapEx deferral of $200 million to $250 million. Is that drilling related? Or is that infrastructure related?

It would be primarily drilling related if we exercise on that in a weaker price environment than we're in today, we would carry on with the BC infra buildout. And I think you can see the rationale for that, that if prices are significantly weaker, we hold the volumes back. And so that would mean the D&C budget would be reduced.

Your next question is from Patrick O'Rourke from ATB Capital Management -- sorry, ATB Capital Markets.

Maybe just a follow-on with respect to the $200 million to $250 million in potential reductions here. Just wondering what's sort of the time frame for those decision points rolling out into 2026? And then is there any sort of quantification on '27, '28, et cetera, from a volume perspective? Or would this -- my thought is being a company with such a large defined inventory, really well-defined growth on the back of that inventory, would at any point, you consider sort of gearing back on exploration in the near term to preserve capital?

We could do that, although the exploration program has generated opportunities that should we proceed with the sale of the Peace River High complex that over 2 or 3 years, we think would fully replace the volumes from that complex. And as far as timing on when we make those decisions, I think we see if the Peace River High sells first because obviously, there's a maintenance capital budget item associated with that complex in the current '26 budget. So we'd be adjusting the '26 budget at that point. And by year-end, I think we'll have a pretty good look at where the '26 strip is going to be, where basis gets to. And I think it was referenced already that AECO is starting to repair itself. The West Gate is back open today, but there is another restriction in a week or so, and then it's free and clear.

So we should be switching to or flipping to withdrawals from storage now. And then that will drive price and receipts were a little higher in the basin over the past week and a good portion of that was due to gas backed up because of storms on the West Coast and LNG Canada was not picking the same volumes west that they have been, which I think has gotten up as high as [ 800,000 ]...

And then just thinking about sort of the interplay between the balance sheet and potential for special dividends. I know -- I don't want to call it caution, but obviously, it's been a sweep of free cash flow. Debt was a little higher. You've got the proceeds coming in from the Topaz share sale. So that will help. But how do you think about above and beyond the base dividend free cash flow allocation between that special dividend and maybe a little bit more debt reduction in the current environment?

Yes. I mean we're thinking about all those things. And I think we said it reasonably clearly in the press release, we do not intend to use the balance sheet to fund special dividends. I think having 2 quarters of the lowest AECO prices in 30 years is a rare circumstance. And for Q3, paying the special using the balance sheet was one of those rare circumstances. But we will continue to look at the growth capital and the special dividend potential and find that balance.

Your next question is from Sam Burwell from Jefferies.

Just another question on the CapEx flexibility. Just curious like what drives that decision? What's -- how do you frame it? Is it based on not wanting to outspend after paying the base dividend? And then like what sort of time frame in terms of like viewing the strip or your view on gas prices are we looking at? Is this like months, some sort of medium-term time horizon? Just curious about how you're thinking about potentially flexing down the CapEx?

Yes. I mean the main control, of course, is the gas price and then everything flows from that. This winter, we're already seeing cash gas prices recover. We're seeing very strong November, December, January, we think there's potential for that to get stronger still. I think all operators are reacting to that. We wouldn't expect any curtailed volume today. So you're kind of seeing fully loaded receipts, and it's not scary. Year-over-year growth is very modest, and we think that will allow this winter strip to improve. Tourmaline has a natural recalibration every spring and breakup.

So as we come out of this winter and look ahead to what summer and winter following strip looks like in the months of March, April, May, that's a very natural time to calibrate the intensity of drilling for the back half of the year. And I think that would be a good time for us to also calibrate on free cash and make sure we're still delivering what we've always planned, which is that 5% growth and in excess of $1 billion a year of free cash flow.

Understood. And then sort of tying into that a little bit on the Canadian gas macro, like supply has come up a bit, granted that shut-ins coming back and it's sort of typical seasonality and the prices come up. But do you think that there's more room for supply to come on? And just asking this because we are going to get more demand from Train 1 pulling more consistently and then Train 2 pulling another Bcf a day next year. So just curious about your view on supply-demand balance and how much supply can realistically come on to fill the incremental demand from LNG Canada Train 2?

Yes. We regularly refresh this work. And as I was saying, November looks relatively flat to last year, and we don't believe we're curtailed much at all as a basin today. Our expectation is next year grows well shy of 1 billion cubic feet a day on an annual per annum basis. Our number would be around 0.6, 0.7 exit over exit growth. We think actually might even be shy of that, around 0.5 Bcf a day.

And to your point, LNG Canada will go from not doing anything in the first half of this year to doing close to and up to 2 billion cubic feet a day, we think as early as the first quarter of 2026. So that's a very meaningful demand change. And the basin will need to react to that with less exports to the United States, and the mechanism to achieve those less exports will be a tighter basis. And we think that will transpire over the next several months. We think there's other tailwinds at play. We believe the Biden expansion on the Northern border is a benefit to the Canadian export picture. It tightens up our basin Erestill.

And we also think there's going to likely be power consumption and power announcements over the next 12 months that helps spur long-term demand thinking and tighten up '27, '28, '29 basis picture as well. So from our perspective, everything we are looking to see for this winter and the year ahead is transpiring. We are not seeing a wall of gas answer stronger cash prices. We are seeing LNG Canada ramp very well, and we continue to see lots of green shoots in local demand, whether it be power or [indiscernible].

And I think it will take Canada and Alberta specifically getting a little cooler here in the next 3 weeks to see what the draws ultimately look like on a year-over-year basis. And I think when we look at draws per week in December and compare them to what we were drawing last year, it could be almost a double. And I think that starts to wake the market up. Yes. And the last time the basin had a demand increment like LNG Canada adds to 2 Bs a day was start-up of Alliance. And I think that's flipped the differential for 3 years.

Your next question is from Aaron Bilkoski from TD Cowen.

I have another question on the Peace River High. If you do ultimately sell it, should we expect you to use the proceeds to add capital to the multiyear plan? Or is the plan to simply redirect some of that maintenance capital that was being spent on the Charlie Lake into the Montney and the Deep Basin?

Yes. More of the latter, Aaron, at this point. I think in order for us to add capital in the EP plan, we want to see strong commodity prices provide that signal. So at this point, it's going to delever the balance sheet. And it's another source of funding for this infrastructure growth that's going to start to add that incremental cash flow and free cash flow that, frankly, we're going to see -- we saw some of it this quarter. We're going to see more of it in '26. And then as Aken comes on and Groundbirch comes on over the years ahead, you're going to see that structural cash flow and free cash flow start. So it's funding that build.

Your next question is from Jamie Kubik from CIBC.

Aaron sort of asked the question I was going to ask her, but I'll ask a little bit of a different one. Can you just talk about how you're thinking about debt levels in the business? Is there a target in mind that you're driving to? Is it a function of forward cash flow? Just a bit more color on your thought process around this would be great.

Well, I think we hit our kind of peak debt metric right now at 0.5x to 0.6x at the bottom of the cycle. So that will drive down to 0.2 to 0.3 as we move towards, we think, a more sustainable long-term price cycle. So we're going to keep that pristine balance sheet focus that we've always had, Jamie.

Okay. And can I ask maybe is the peak debt level where you're at sort of right now, is that a bit of a driver on the Peace River High disposition? Or is it more a function of just capital allocation between your various assets?

It's for sure, the latter, it's capital allocation. I mean we've been thinking about selling the Peace River High complex for 2 or 3 years, to be honest, simply because it wasn't getting rewarded with growth capital because we had more attractive projects in the 2 gas complexes. And so it feels like this is probably the right time, and there's considerable interest in it. And worth flagging, Jamie, the interest is also what helps spur the process. There is interested parties that are looking to enter this basin, and they have unsolicitedly given us indications of value or interest in acquiring the asset. And so now running the process allows all of them to come to the table with their best number at the same time.

Your next question is from Josef Schachter from Schachter Energy Research.

Two of them. First thing, you guys have a great track record of making acquisitions in the past. When you look at your 2 core areas versus the M&A market, we just saw the NuVista deal, do you see M&A as part of the growth opportunity? Or is your internal opportunities just that much better?

Yes. We went through like 5 years of putting primarily the BC Montney gas complex together through or expanding it through a whole series of acquisitions from COVID on. And we have put in place now the BC build-out infrastructure for the next 5 or 6 years. Now we're going to go realize all the upside and all the value from those really well-timed acquisitions. So we'll always look at perhaps small asset tuck-ins. But right now, it's -- the focus is much more on organic growth from the extensive inventories we have really in both gas complexes.

Super. Second question, the Topaz question, did a big sell-down here. Do you see using more sales and then get below 10%, which then allows you to move without market fluctuations?

We have no plans in the short or medium term to dispose of any more of the Topaz shares. But we're super excited how that the whole Topaz story has unfolded and grown. And I think it's just been great all the way along. So we're happy to be shareholders.

Your next question is from Fai Lee from Odlum Brown.

You just touched on it a little earlier about, I guess, growing power demand. There's obviously some bullish projections for gas demand to meet growing electric demand from data centers, artificial intelligence. And I'm just wondering how this on a longer-term basis could maybe possibly affect your strategy for marketing gas? And if you've had any consideration of specific steps you could take to capitalize on these opportunities. For example, do you think you'll ever have like direct gas supply agreements with data center builders? Or I'm just wondering how you're thinking about that.

Yes. We're evaluating that opportunity, Fai. And we would look at it as just another sleeve of our overall gas diversification. But we do have lots to offer. I mean we have many plant sites. We have water. We have power redundancy. We're close to fiber. We're close to the grid. We can provide the CCUS solution, although we have very low CI gas to begin with. And so yes, we're assessing whether that's an opportunity to further diversify our very diversified marketing portfolio already.

Okay. So you're looking at that. And I'm just wondering on the other side, have you been approached from data center builders or people saying, looking at the advantages that you can offer and say, maybe working with them. Is that kind of -- have we gotten to that level? Or it's just kind of just too preliminary at this point?

Yes, there's been lots of conversations, I would say, early in stage, where people are trying to understand how this is all going to work. One of the first things that people were trying to understand first was what the ASO allocation would be and who would be a recipient of that ASO allocation. So that's happened. And we would be the first to cheer on projects like greenlight because that will help consume gas in basin. And the reality is we can build a lot of these. 1 gigawatt on a high-efficient power plant will only consume roughly 150 million cubic feet a day. So we think you could do 10 in short order, and you would still find the basin in balance, and we'd be able to answer that call.

And so as operators understood how much ASO allocation they might get, now we're starting to move to that kind of Phase 2 where it's a bring your own power effort and operators are looking to add generation to their projects, and then they need gas supply for that generation. So we would fit naturally into all those conversations. We're having them. As Mike was saying, one of the areas I think we were probably most interested in is those colocation opportunities because it allows us to offer more than one service. And when you offer multiple services to a counterparty, you can enjoy that business.

And so we have great sites across our asset base that many of them actually are very, very suitable for this kind of activity. And I think over the next 12 months, we should see all sorts of different data center announcements, some of which should be in the Heartland and we connect to ASO and some of which will be closer to the resource and have a behind fence strategy. And I think we're working hard on making sure we're positioned well to participate in those that are attractive to us.

Your next question is from Neil Mehta from Goldman Sachs.

Talking through 2026 as well. And as we think about '26, maybe you could talk about cyclical versus structural cost deflation. We continue to be in a relatively favorable oil services environment for the E&Ps. And so just you're curious if you're able to capture some of that cyclical deflation as opposed to maybe some of the structural benefits as well. So just the cost environment going into '26.

Yes. It is -- you're right, Neil. It is a little bit more favorable on the service cost side and D&C costs through this winter. And I think we kind of eyeballed 5% reduction in the press release from where we were mid-2025. We're most excited about the operating cost reductions that we've started to achieve already, and they're structural and repeatable, and they will accelerate over the next couple of years, and they marry up well to base dividend increases.

And you talked a little bit about the LNG ramp in Western Canada, but maybe you could spend a little bit more time talking about the Shell ramp specifically and how you guys are thinking about that as the driver that could potentially tighten AECO because the counter to that is there just seems to be a lot of gas behind pipe. And so do you actually get the price response with the LNG pulp?

Yes. We think we will. I think Jamie outlined that we really don't think there is a lot of gas behind pipe right now. We think we're seeing pretty much everything that's available on stream at this point. We expect another Bcf plus of intra-basin demand when we get cool weather. We're not cold at all yet here, but that is coming in the second half of November. You've got another 1.2 Bcfs yet to come from LNG Canada when they get Phase 1 and both trains fully on stream. And I think we're eyeballing Q1 of for that.

And you still have, although, as I mentioned, for a few days here, the West Gate is fully open, but that's an extra 550 million a day that's still being backed into the basin. That's going to go away when the maintenance is done at the end of November. So in aggregate, you're well over 2 Bcf a day flip. And that's why Jamie was referencing it will be very instructive to see what the actual draws are from our storage during December because we think they're going to really drive a basis tightening once people figure out what's really happening.

And as far as refilling from the supply side by our gas industry, kind of the best we seem to be able to deliver on an annual basis is that 0.6 to 0.7 Bcf per annum. So it's going to be close to 3 years to replace that sink. And a lot of that relates to getting on to the system and basin hydraulics and getting meter stations and the long queues that are there already before you can bring new gas on the system. You want to bring gas on the system today or in 2026, you had to be organizing your firm service 4 years ago.

[Operator Instructions] There are no further questions at this time. Please proceed with closing remarks.

Thank you, everybody. We'll talk to you next quarter.

Thank you.

Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines.

Good morning, ladies and gentlemen, and welcome to the Tourmaline Q2 2025 Results Conference Call. [Operator Instructions]

Also note that this call is being recorded on Thursday, July 31, 2025.

And I would like to turn the conference over to Scott Kirker. Please go ahead, sir.

Thank you, Sylvie, and welcome, everyone, to our discussion of Tourmaline's financial and operating results as at June 30, 2025, and for the 3 and 6 months ended June 30, 2025 and 2024. My name is Scott Kirker, and I'm the Chief Legal Officer here at Tourmaline.

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'll start with Mike speaking to some of the highlights of the last quarter and our year so far. And after his remarks, we'll be open for some questions. Mike, please go ahead.

Thanks, Scott, and good morning, everyone, and we're happy to review our Q2 results and then answer some questions. Highlights. Second quarter average production was 620,757 boes per day, and that was at the midpoint of the guidance range that we provided on May 7 and up 10% from the second quarter of 2024.

Second quarter cash flow was $823 million or $2.16 per diluted share. On total EP expenditures of $490 million, and that generated free cash flow of $317 million for the quarter or $0.83 per diluted share. We've entered into a new long-term LNG feed gas supply agreement with Uniper. I'll talk more on that in a moment.

We've released an updated EP plan that outlines growth from our current production levels of approximately 650,000 BOEs per day to 850,000 BOEs per day in the next decade -- early in the next decade, and this build-out is fully funded by cash flow, and it will result in $2.5 billion to $3 billion of annual free cash flow at flat pricing on a maintenance budget by the end of the EP plan.

Given the continued strong free cash flow generation in Q2, the company has elected to declare and pay a special dividend of $0.35 per share on August 20 to shareholders of record on August 8.

Briefly on financial results. Second quarter '25 earnings were very strong at $515 million or $1.35 per diluted share. The full year '25 EP capital budget remains unchanged, and the range remains unchanged at $2.6 billion to $2.85 billion. We anticipate commodity prices to improve over the current strip in the second half of 2025 with the ramp-up of the LNG Canada facility on the West Coast, resulting in hopefully higher free cash flow in the second half relative to first half.

We continue to maintain a very strong balance sheet. Net debt at June 30, 2025, was approximately 0.5x net debt to '25 forecast cash flow. On the production front, as mentioned, second quarter average production was a little over 620,000 BOEs per day, and that was achieved despite reductions related to wildfires in the Peace River High complex, low commodity price-related periodic shut-ins in Northeast BC and multiple frac activity deferrals into the second half of this year, given low pricing.

Full year '25 average production of 635,000 to 650,000 BOEs per day is now expected given the EP activity deferrals first from Q2 to Q3 and now from Q3 into Q4 as we target higher pricing to bring new production on. The '25 exit average production of 680,000 to 690,000 BOEs per day and a preliminary '26 average production range of 690,000 to 710,000 BOEs per day is currently anticipated.

In the 5-year plan, we use the very bottom of that range to be conservative.

Looking at the '25 Capital Program, Q2 EP capital spending was $70 million less than forecast, primarily due to those aforementioned activity deferrals. And we'll continue to monitor local natural gas prices and defer capital from Q3 into Q4 of this year or into Q1 of '26 as required as we always optimize free cash flow.

Briefly on marketing. Our average realized natural gas price in the second quarter of this year was CAD 3.34 per Mcf, and that's 94% above the AECO 5A benchmark price of CAD 1.72 per Mcf. We continue to benefit from our diversified marketing portfolio and our strategic hedging program. We have an average of 1.1 Bcf per day hedged for the balance of this year at a weighted average fixed price of CAD 4.48 per Mcf.

We're pleased to disclose our third Gulf Coast LNG agreement. We've entered into a long-term LNG feed gas supply agreement with Uniper. Tourmaline will supply 80,000 MMBtu per day of natural gas in the U.S. Gulf Coast for an 8-year term, and that begins November 2028. We have secured long-term firm transportation to the U.S. Gulf Coast with TC Energy, and that allows Tourmaline's natural gas from both the Alberta Deep Basin and/or the BC Montney complexes to directly access European natural gas markets.

The firm transportation begins in November 2025, and that gives us the flexibility to sell locally in the Gulf or enter into short-term LNG feed gas supply deals prior to the start of the Uniper agreement. We are excited to provide more details regarding our multiyear Northeast BC Montney development project, certainly one of the largest EP projects in the Western Canadian Sedimentary Basin.

We have been systematically consolidating and delineating the Northeast BC Montney gas condensate complex for over 5 years, and we're now entering the next phase. We're in the significant financial benefits of all those activities, which began during COVID will be fully realized. We expect to add 1.1 Bcf per day of new gas production and over 50,000 barrels per day of condensate and NGLs over the next 6-year period.

And this project will develop Tourmaline's most profitable inventory. It's the lowest capital cost, lowest operating cost, most liquid-rich, highest margin inventory we have, and it will improve all of the company's operating metrics as production from this new development project becomes a larger proportion of the corporate production base.

The build-out consists of 2 new deep cut gas plants, one in the North Montney, one in the South Montney, expansion of 4 existing gas processing complexes, 3 new hydrocarbon liquid hubs, 5 water recycling facilities, electrification of 4 of the gas processing plants as well as several pipeline corridors connecting the company's large resource base to its existing and the new gas processing complexes.

Recall, we've been building gathering and processing infrastructure across Northeast BC and the Alberta Deep Basin since the company started, including over 10 new processing facilities. So we're good at this, and our cost management is very strong. This BC Montney development project has a strong focus on liquids growth and margin improvement, and the company already is the largest liquids producer in Northeast BC, and we'll continue to grow those volumes.

The infrastructure build-out actually commenced in 2024 with several components already built or underway, and they're disclosed in the press release. The first significant production addition to come from all this is expected in Q4 of 2026 with the AkenC38C plant expansion. And we feel that's a good time to add new basin volumes given that Phase 1 of LNG Canada should be at full volume certainly by that point.

The next production addition is Phase 1 of the Groundbirch 15 to 25 deep cut gas plant, and that's planned for the second half of 2027. And importantly, both of those projects have all the necessary permits and long lead procurement is underway.

Tourmaline expects production growth of 30% to 850,000 BOEs per day by 2031, cash flow growth of over 40% and free cash flow improvement of over 2.5x at flat pricing to $2.5 billion to $3 billion of free cash flow per annum once the overall project is completed and the EP program starts to trend towards maintenance capital levels.

We've updated our multiyear EP growth plan as well. And that, as you can see, through to 2031, grows current average production levels from 650,000 to 850,000 BOEs per day. Once the Northeast BC infrastructure build-out is completed early next decade, the production growth rate is expected to drop and the company intends to migrate towards a maintenance capital level, which we currently estimate at about $2.5 billion per annum to maintain 850,000 BOEs per day.

Associated free cash flow will grow to the $2.5 billion to $3 billion per annum mark at the flat price deck, and it does underscore the significant overall improvements that this BC Montney development project will impart. And at that point, we'll have a company that can continue to produce at these levels and more importantly, generate annual free cash flow of this magnitude for literally decades, given we control the largest future drilling inventory in North America.

And we've always taken a long-term view as we built this company, that includes building and owning your own infrastructure as that improves realized margins and partially insulates us against ongoing price volatility. So really, this is just another planned step in the evolution of the company. We will be a materially larger, more profitable company right about the time that we expect the continent to be getting short on resource.

And importantly, we'll continue to prioritize free cash flow on an annual basis as the new EP plan is executed, and we'll adjust the pace of capital spending accordingly. We can slow down if prices aren't cooperating or we can accelerate if prices are ahead of where we're expecting. That doesn't seem to happen very often, but we do maintain our strong natural gas outlook for the second half of this decade.

Just briefly on E&P, our '25 well results in both the Northeast BC Montney and the Alberta Deep Basin continue to outperform prior years with above forecast deliverability from multiple assets spread across both gas complexes. And this has allowed us to reduce capital spending and maintain in part production targets.

With lower local gas prices thus far in Q3 of '25, we've already deferred some BC frac activities into Q4, and we have released one of the Deep Basin drilling rigs for the balance of at least this year. And of note, multiple new pool successes in several formations in the South Deep Basin via the second half '24, first half '25 EP program are evolving into a significant new growth project for the company.

We plan several delineation wells over the next 12 months to further refine this multi-objective development, and it's certainly not included in the current EP plan. And I think that's it for the prepared remarks, and we're more than happy to answer any questions you may have.

[Operator Instructions]

And your first question will be from Kalei Akamine at Bank of America.

Look, thank you for the updated plan. I think this has been well telegraphed by you and your team versus our estimates, we found this very much in line. I'm hoping that I can get you to address maybe a couple of things here.

First, when I'm looking at Slide #8, some of the midstream projects associated with this build-out maybe could have some better definition. So wondering if there are moving parts and what those moving parts could mean for the plan. And then our broad read of this is that this is probably the most conservative version. Where do you think that you could improve on this plan? Is it something like liquids yield? Is it capital? Or is it synergies from prior deals?

Well, we'll work backwards with that. Where we can improve is significantly on the realized liquids margins. We've included the base minimum of $1 per barrel improvement, and we fully expect to do significantly better than that. I don't know what you were looking for as far as further detail on all of the existing plant expansions or new builds.

We've been kind of carefully planning this out for multiple years. So we kind of know exactly what we're going to build. So we can certainly take that offline and provide more detail for you. But maybe you can let us know what you're thinking there.

I guess, broadly, I'm looking at Slide #8 and specifically at Groundbirch and Conroy, where the build-out is up to a certain number. It seems like that up to number is still kind of influx. So maybe talk about what [ motiv ] to that number in between.

Sure. Well, there's going to be 2 sort of plant projects in Groundbirch. There's the Phase 1 deep cut, which will be 300 million a day, and that will handle the liquid-rich gas. And then on the ex Strathcona assets, we will expand that 60 million a day gas plant that they had to 150 million a day, and that will handle the dry gas component of the inventory that we're going to develop there. And then we have an opportunity in Phase 2 to take the Groundbirch to deep cut plant to higher levels.

That's helpful. My second question is, is it really about hedging. When you think about the big capital commitment over this period, does that motivate you to hedge maybe a tad more aggressively? Or given what your base case is for rates over the next several years, are you more motivated to perhaps hedge less and lean into the macro?

Yes. Well, we have those discussions daily, as you can imagine. Right now, we're probably just going to stick with the existing plan. And in any current year, we end up 30% to 35% hedged by the time that year is happening. If you look out, '26 isn't at that level yet, and that's mostly because we haven't seen the prices that we like.

But if you look historically, that's typically what we've done. And we typically -- just because we've had weaker prices in the Western Canadian Sedimentary Basin, that hedging tends to be summer focused and focus more on those hubs rather than our export hubs in the U.S. So that you kind of nailed it, is the AECO outlook going to be significantly better so that maybe you don't hedge as much in the summer of '26 and '27. And I'd say the jury is out on making that decision at this point.

Next question will be from Sam Burwell at Jefferies.

I just wanted to get a sense of whether 2026 is the heaviest year of infrastructure CapEx spend. Is it materially more than '25 and '27? Just trying to get a better sense of the infrastructure CapEx trajectory?

Yes, it's Jamie speaking. It's generally level loaded across the plan. Frankly, we're kind of building to sometimes and a bit gas plant in any given year. So this next several quarters is focused around the AkenC38C build-out. In '26, there is long lead spend now incorporated for Groundbirch, and that build-out has been completed in '27. And then we're getting into some of the Phase 2 elements of both the North and South Montney. Importantly, though, this infrastructure build-out does tail off in the 2030, 2031 time frame. And you can see that free cash flow expand as that capital drops.

Okay. Got it. Then a follow-up on the deferrals obviously makes sense given the AECO pricing you're seeing now, but the CapEx guidance was unchanged. So I'm just wondering if there is a downside bias to 2025 CapEx or perhaps there are volumes that show up in, say, 2026 where the capital is deployed in 2025. So just trying to reconcile the production guidance with the CapEx guidance for '25.

Yes. I think that's a distinct possibility. We'll probably migrate towards the lower end of capital. And we've -- as we announced in the press release, we are continuing to defer some capital activity out of Q3 to later in the year. We're still targeting if pricing improves in Q4, and we might get into a discussion on this call on where AECO is going to go here over the next couple of months, we can very quickly pivot and execute a significant piece of the program in Q4 and hit or exceed that exit target of 680,000 to 690,000 BOEs a day.

So maybe a little more U-shaped production profile than we've seen in previous years for us and that's strictly related to continuing weaker-than-expected summer gas prices. And those are -- a large part of that is being caused by export restrictions out of our basin due to maintenance. So there was maintenance at the East Gate through July, and that's continuing. And there's significant maintenance on the West Gate. And in aggregate, it's backing up close to 1 Bcf a day into the basin kind of at exactly the wrong time. And it's significantly more than the export backup than we were observing due to maintenance last summer.

So it's a bit of an aberration. And we think by September -- well, we know by September, that all goes away and perhaps you can start seeing the -- more clearly the impact of pulling increasing volumes west on CGL to LNG Canada.

Anything you want to add, Jamie?

I would say like the flip side of that is it coils the spring on how tight next year can get, and you're starting to see that being reflected in some of the basis markets. We've seen Chicago tighten up. We've seen even CAL '26 AECO Hub tighten up a bit here just in the last 10 sessions. And so the lack of ability to export this summer helps drain the storage capacity in the markets we would otherwise be exporting to, namely the Pac Northwest, California market and the Chicago market. And those markets have had generally a pretty hot summer, especially in the East, and that makes the '26 setup that much more interesting.

I think the other thing we'll be watching carefully, of course, is the LNG Canada ramp-up, which frankly, so far has been very strong, seeing pulls up to 400 million a day implied by the cargoes and the visible scrapes we see well over 100 million a day now at the end of July, and we understand that ramp to continue to go well through the back half of this year.

Next question will be from Josh Silverstein at UBS.

Just for the long-term plan and the build-out here, can you just talk about how much flexibility or optionality you have in the development plan? Can you adjust the project slate or timing depending on commodity prices? If you can offer a little bit more color there, that would be great.

We have a significant amount of flexibility. We're not projecting first production of any material nature really until Q4 of 2026 with the Aken start-up. And I don't think there's an opportunity to move that to midyear, but we can certainly have flexibility on when Groundbirch starts and when all the Phase 2 components actually start. I mean we've sort of got in the habit the last 2.5 years of just deferring everything because prices haven't cooperated. So we're kind of looking forward to the other side of this. Maybe prices are better than it is being forecast for '26 and '27, and we can accelerate several of the items in there.

Got it. And then I also wanted to ask on the shareholder return profile. Given all the CapEx that the free cash flow really is kind of back-end weighted here, are you limiting the potential growth in shareholder returns through this period? And then I see the buyback in that kind of chart in the back have kind of been pushed back out 5 years from now as well versus potentially earlier, you were thinking about maybe '26 or '27?

Yes. I mean we've got a big project to execute here between '25 and '31. So the focus really is on per share growth and dividend yield. If we were just talking about if prices are better than expected, then that growth of free cash flow to over $2 billion per annum comes sooner, and that can open up other options for shareholder returns.

Just to put some numbers on that, Josh. If you were to move AECO around like plus $1, that's over $500 million of incremental free cash flow for Tourmaline. And so I think it really does -- we are definitely well open to an improving gas price market in '26, and that can influence how we return cash to shareholders.

Next question will be from Jamie Kubik at CIBC.

A specific one actually, but with respect to Slide 6 and the updated EP plan, there's a great amount of detail on the infrastructure inclusions that you have in this plan. Can you talk a little bit about perhaps the percentage of new capital in the EP plan that is infrastructure weighted versus maybe new drilling capital compared to what was previously included?

Yes. So we did include facility capital for both Groundbirch and the North Montney that wasn't included before. But also, we also included the drilling and completion capital associated with that extra 100,000 BOEs a day. And so in general, for the next several years, we're going to be allocating $300 million to sometimes $350 million of infrastructure capital per year.

And then the D&C CapEx would be basically pushing at that $2.5 billion to $2.6 billion level. Once North Montney Phase 2 is completed, that infrastructure capital will thin. It's going to thin to roughly $100 million a year, sometimes less. And then also as declines are coming down through the plan, which is important, we'd be roughly at 32%, 33% decline rate today because of the way the BC Montney production contributes to the business and the advantageous nature of how those type curves shape, declines still we see coming down through the end of the plan into the high to mid-20s. That allows that DC capital also to decelerate. And so that's how you get to the $2.5 billion at the end.

Okay. Maybe I'll ask another one here. Just with respect to the liquids mix and the production profile, I guess, how is that trending this year versus your expectations? And how do you think that might change in the back half of '25 or into 2026?

Yes. I think ultimately, the mix won't change. There will be short-term aberrations in any given year. But ultimately, it's pretty much that 75% gas, 25% total liquid, and that's where it is at the end of the plan. We're down a little on liquids this year. We had an extended turnaround in the Peace River High complex, which reduced liquids for a longer period than we had forecast for Q2.

And then just the sequence of the pad drilling in the BC Montney, several of the early pads were in gassier areas. And some of the deferrals were -- when we were saving capital in Q2 were a couple of the liquid-rich pads. We subsequently completed those. And so you'll see total liquids production trend up here through the balance of the year.

Great. I'll sneak in one more here. Just with respect to shut-ins. Tourmaline did mention in its disclosures that you did have some shut-ins in Q2 related to natural gas. I guess, is that something that you're thinking about extending through Q3 by much just given where Station 2 and AECO pricing have gotten to? And how should we think about that part going forward?

We're certainly looking. We actually have a little bit of gas shut-in today. We'll see where prices go through the balance of August, but we've certainly left that as an option for us in August anyway, we expect September pricing to be better. And the shut-ins have been strictly on the BC Montney, generally the North Montney. It's gas that goes through third parties with higher OpEx. And of course, part of the infrastructure build-out is that gas comes into our own facilities in the future with much lower OpEx.

Next question will be from Aaron Bilkoski at TD Cowen.

A couple of small questions from me. The first is on margin expansion. You've obviously discussed margin expansion as you grow in Northeast BC. Some of that comes from higher revenue, some of it comes from lower costs. Of the dollar per BOE cost savings that you talked about, what would roughly the split between OpEx savings and transportation cost savings, if you have that available?

Yes, it's about 50-50, Aaron. And we'll see if we can do better on the OpEx, but that's what we're modeling in right now. So $0.50 on EBITDA.

And my second question is on the transport to the Gulf. I guess to what extent do you see Tourmaline being able to get more physical transport capacity down to the Gulf in the coming years?

Well, it's something we work really hard at. And I would expect sometime in the next 2 or 3 years, we'll find another pathway down there on existing pipes with lower tolls. There might be some further brownfield work that seems to be on the table again south of the border, which might help that exercise. But our marketers spend a lot of time trying to cobble together transportation routes from the Gulf all the way back into the basin.

Next question will be from [ Philip Lemoore ] at Lemoore Vineyard.

Mike, in years past, when we had Board meetings down in Tucson with Ron Wigham and Andy and Lee and John Elick, I remember we were running debt at about 2.5x cash flow thereabouts and talked about whether we should put a cap or suggest a cap of don't go over 3x cash flow. And now you're running 0.5x, paying a huge dividend, a very attractive dividend if people have their eyes open. And it's just amazing what you've accomplished. So I just wanted to thank you for what you've done.

[Operator Instructions]

And your next question will be from Fai Lee at Odlum Brown.

Mike, it's Fai here. I'm just looking on Slide 5, your 5-year plan. In 2031, you have like about $2.6 billion in your capital program. I'm assuming if this was a 6-year plan that there will be some production growth in 2032. Do I confirm that? And if that's the case, I'm just wondering, do you have -- if you can give me some sense of what sustaining capital, call it, would be to keep production flat at 850,000 BOEs. Just wonder what that number would be if it's not $2.6 billion.

Yes, you bet, Fai. Yes, we're modeling $2.5 billion to maintain that 850,000 BOEs per day. And the answer to the first part of your question is, yes, there probably will be some modest growth going forward, 2032 and beyond. In that -- the last slide in the deck, we do depict that to some extent, but we do show the production growth rate dropping from that 5% to 6% into the 1% to 2% per annum range. And so I mean, I think that's the type of production growth that you can think about for the years past the existing 6.5-year plan.

And at this time, Mr. Kirker, we have no further questions registered. Please proceed.

Thank you, Sylvie, and thanks, everyone, for attending the conference call. We'll see you again next quarter.

Thank you, sir. Ladies and gentlemen, this does indeed conclude your conference call for today. Once again, thank you for attending. And at this time, we do ask that you please disconnect your lines.