Tourmaline Oil Aktie

Good morning, ladies and gentlemen, and welcome to the Tourmaline Q2 2026 Results Conference Call. [Operator Instructions]

This call is being recorded on July 30, 2026. I would now like to turn the conference over to Scott Kirker. Please go ahead.

My name is Scott Kirker, and I'm the Chief Legal Officer here at Tourmaline Oil. 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 these 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 the year so far. After his remarks, we'll be open for questions. Go ahead, Mike.

Thanks, Scott. Thanks, everybody, for dialing in this morning. So a few highlights. Q2 '26 cash flow was $786 million, generating $192 million of free cash flow in the quarter. We've entered into a long-term agreement to increase propane and butane exports through the new AltaGas REEF terminal, increasing Tourmaline's exposure to premium LPG export markets by approximately 55% and improving realized margins for these products. Our strong well outperformance has continued with first half '26 performance now up 28% for the Northeast BC Montney complex and 14% for the Alberta Deep Basin over the prior five-year averages.

The Northeast BC infra build-out is on schedule and on budget with five of the six regional connector pipelines already completed and the Aitken plant expansion start-up on schedule for Q4 of this year. We're now scheduling a one-year pause between Phase 1 and Phase 2 of the BC infrastructure build-out, enhancing anticipated second half '27 and 2028 free cash flow and shareholder returns. Looking at production, Q2 average production was 594,000 BOEs a day, marginally below the guidance range of 595,000 to 605,000 BOEs per day.

That was by choice as we injected more nat gas into storage, deferred activity in response to low Q2 natural gas prices and also had some price-related shut-ins during the quarter. Storage injections at Dimsdale, Alberta, Dawn, Ontario and Wild Goose in California averaged 8,900 BOEs per day in the quarter, and that was higher than initially planned. These volumes are expected to be largely withdrawn from storage during the fourth quarter of this year and perhaps into the first quarter of '27, obviously, at a higher price than we injected the math. Full year '26 production range of 620,000 to 640,000 BOEs per day is still anticipated, including a '26 production exit target of 660,000 BOEs per day.

Given the activity deferrals from Q2, we have 67 wells ready to frac and an additional 21 wells to turn in line. We'll do that in concert with improving prices. Looking at our financial results and the capital budget. Net debt as of June 30 of this year was $1.5 billion, and that's below our long-term debt target of $1.75 billion. Second quarter OpEx was $4.59 per BOE, and that's down 10% from the corresponding quarter in 2025 and 3% from Q1 of this year.

Full year '26 operating costs of $4.50 to $4.60 per BOE are expected, and that will take us down between 7% and 9% from full year 2025. And we're maintaining the aggregate operating and transportation cost reduction target of $1.50 per BOE by 2031 relative to first half '25 levels. The full year 2026 EP capital budget remains at $2.55 billion, following the $350 million reduction to the full year budget that we announced on March 4 of this year. At current strip pricing, 2026 free cash flow is now estimated to be $880 million and the free cash flow benefit from the company's exposure to JKM and TTF pricing via our LNG export-related contracts is expected to continue through the balance of '26 and 2027.

We are now scheduling, as mentioned, a 1-year growth spending pause between the 2 phases of the BC Montney build-out and development project, and this will allow the company and shareholders to realize the full operational benefits and free cash flow growth from Phase 1 commencing in the second half of '27 and into 2028 prior to embarking on Phase 2. And the pause also lets us assess global natural gas supply/demand and various pricing outlooks around the globe. 27 EP spending is thus revised down to $2.55 billion and 2028 EP spending is revised down to $2.3 billion. On A&D activity, we continue to pursue small tuck-in acquisitions and working interest consolidation opportunities adjacent to existing company lands and operated infrastructure.

During the second quarter, we acquired Aduro Resources in the South Montney complex. That was for total consideration of $100 million, and that included net debt, and it consisted of $50 million of cash and approximately 1.5 million common shares of Topaz Energy Corp. The acquisition included modest current production in Infra as well as 174 net Tier 1 Montney locations adjacent to the Tourmaline Groundbirch-Monias deep cut plant that is currently under construction. And during the quarter, we also completed the sale of Ag on the Aduro lands as well as certain recently acquired Alberta Deep Basin lands to Topaz for cash proceeds back to Tourmaline of $38.7 million.

Briefly on marketing. Our average realized natural gas price in Q2 was $3.12 per Mcf as we continue to benefit from the diversified marketing portfolio and strategic hedging program that we continue to evolve. Tourmaline has an average of a little over Bcf a day of natural gas hedged for the remainder of '26 at a weighted average fixed price of $4.97 per Mcf. We have 220 MMBtus exposed to international pricing, both TTF and JKM in '26. For the balance of '26, JKM and TTF are trading over USD 15 per MMBtu, which is a 60% price appreciation for the same strip as at the beginning of this year.

The company is amongst Canada's largest propane producers and similar to the natural gas business, we have a long-standing propane marketing diversification strategy that we've been pursuing. And as mentioned, we've entered into a long-term agreement with AltaGas to increase our propane and butane exports through the Ridley Island Energy Export Facility, commonly known as REEF. The increased LPG volumes will be supplied to REEF from our planned unit train rail loading facility located adjacent to the Groundbirch-Monias deep cut plant that's already been built.

The new rail terminal is expected to improve our realized LPG margins by enabling direct rail shipments to the West Coast, and it's all part of that whole integrated Northeast BC infrastructure project. Our expanded natural gas storage capacity is yet another important component of the continued vertical integration of our entire natural gas business. On the EP front, we drilled a total of 43 wells and completed 33 wells during the second quarter of '26. And as you know, considerable EP activity was deferred from Q2 into the second half of this year. Importantly, strong well performance has continued in both gas complexes in the first half of the year.

As mentioned, the BC Montney well performance is up 28% in the first half of 2026 over the prior five-year average, based on the 25 wells that have actually reached IP 90. Recall that 25 was up 22% over the previous five years. Alberta Deep Basin is now also up, it's 14% up in the first half of 2026 over the prior five-year averages, that's based on 30 wells. We continue to evolve our EP approach to optimize deliverability, EUR, and IRR, so you're seeing those results. It's also in part the result of our machine learning-assisted multi-discipline data integration capability that we've been developing in-house.

On the inventory front, as mentioned, the Aduro acquisition added 174 net Tier 1 locations at a cost of $462,000 per location. In the Deep Basin land sales, which included the first disposition of previously restricted Alberta Caribou lands and other minor asset consolidations, added 110 locations at an average cost of $173,000 per location. I think you've probably observed that the location prices are a lot higher south of the border in Canadian dollars, as high as $10 million per location.

On the B.C. infra build-out, it's actually a major Canadian project that is fully funded by cash flow and currently being executed. The overall project, including both phases, will add 1.1 Bcf a day of gas and over 50,000 barrels per day of condensate and NGLs. Once completed, it's anticipated to generate over $400 million of structural incremental annual cash flow compared to first half 2025 cost structures, and that's above the cash flow generated by the growing natural gas business and product sales that the growth will deliver.

A substantial amount of the phase 1 build-out is complete. That includes the highway condensate hub, five of the six major pipeline interconnects, the Birch facility, the South Montney electrification project, and they're already leading to OpEx and transportation cost reductions in this year. You probably saw that Brian Robinson, our CFO, is going to retire effective November 1 of this year.

Brian's been here since we started Tourmaline in 2008, has done a brilliant job all the way along at Tourmaline, and of course, prior to that at Duvernay and Berkley. Safe to say, the best CFO in the sector over the past two and a half decades. I may be a little biased. Brian will remain on the board of directors of Tourmaline following his retirement as CFO.

I'm also very pleased to announce that Jamie Heard, currently our VP Capital Markets, will succeed Brian as our CFO. Jamie's been doing a tremendous job in the capital markets role, and we know that that will continue with his expanded scope beginning in November. Jamie also inherits the very strong and very deep finance team that Brian has built over his years with Tourmaline.

Finally, our board of directors intends to declare a quarterly-based dividend of $0.50 per share in early September, which will be payable on September 29th, 2026, to shareholders of record at the close of business on September 15, 2026.

That's all for comments, and all of us are here to answer your questions.

[Operator Instructions] We now have our first question, and this comes from Neil Mehta from Goldman Sachs.

Congrats, Brian. Jim, congrats to you as well for everything. So just wanted your perspective first on the pause between Phase I and Phase II of NEBC? And what drove it? What are you looking for in terms of confidence of bringing the project back. And then this will save you some cash here. So how do you think about allocation of that cash between reinvestment and shareholder return?

I think in the general comments that I made before really describe it. It does give shareholders that opportunity to see how much better the business is getting just from phase 1. We'll have 2 of the plants on Aitken and Groundbirch. You're already seeing an improvement in OpEx and transportation costs and the initiation of that sustained commodity price, independent incremental revenue and cash flow. We think it's the right thing to do. It's that balance between growth and shareholder returns.

We do listen to shareholders and get feedback to that end. We'll continue planning phase 2 all the way along. We don't actually make any significant capital investments on phase 2 or decisions to order the long lead time items really until mid-2027. If there's a 3-year sustained improvement in natural gas prices in $4 to $5, we can rethink the pause. Right now, we think it's the best thing to do for everybody. Jamie, anything you wanted to add to that?

Yes. We'll also be watching to see all the demand announcements we expect over the next 6 to 12 months. We expect several new LNG plants on the West Coast. We expect several power announcements in the province of Alberta, potentially one we're more closely involved with.

And we also expect to see a large demand increase for our product on the Northwest and the west side of the United States where we have an established transportation network, and we're kind of monitoring a quickly evolving data center build-out in many of these states that actually don't have growing gas supply. The ethos here is we want demand to pull gas, increase price. And then when we have that pull to answer, then we'll respond with supply and feed it into exactly where that demand is.

That makes a lot of sense. And that's kind of ties into the marketing side and the pricing side. Talk about the outlook for AECO gas and your confidence that the differentials will tighten up. Do you have confidence that your peers will show discipline as well in the basin to allow demand to pull price.

I'll start. I mean, a few comments on Western North American gas prices. California led the whole complex down in the first half of 2026, warm winter, record hydro that was available for the first 4 months of 2026. And now California is going to lead the complex back up. You've seen that already. There's heat in California. Storage has withdrawn, I think, 26 of the first 29 days in July.

Pricing has improved from USD $1.50 to well over USD 3 now. We think you'll see that start to drag AECO and Station 2 up towards the end of August when the current GTN maintenance that TransCanada has going on allows full volumes to flow west. So GTN exports hit a low of below 1.5. They're typically close to 3. They're running about 2.5 Bs a day right now, and there's room for another half B, and we expect that will fully flow west towards the end of this month, and then you'll start to see AECO and Station 2 follow the California PGE price up.

And local supply has remained disciplined, Anil, we have not seen a major push of supply growth. In fact, we're targeting roughly half a billion cubic feet a day of year-over-year supply growth. With the export restrictions and the economic impulse to bring less Canadian gas to the United States, normally you would expect local storage to ramp quickly. That hasn't been the case. We have definitely lagged the prior several years on our rate of injection, we do not expect to have a very full storage picture at the end of this year's injection picture.

As Mike was saying, as GTN maintenance comes off through August and we're unrestricted in September, that's going to be a very open period for pushing gas both south, but also east, as the east is still tight. LNG Canada should be running full as well.

We expect that continuing tightening picture for AECO to help bring hub AECO basis in, and we continue to see that long-term basis needing to get closer to $1 versus the $1.50 to $1.75 you see today, which for Tourmaline, is a meaningful cash flow improvement. That kind of size of cash flow improvement for Tourmaline would equate to roughly $0.5 billion of free cash flow.

And the next question comes from Patrick O'Rourke from ATB Capital Markets.

First off, just congratulations to both Brian and Jamie. well deserved on both fronts. First question is just with respect to the improvement in the type curves here and looks pretty markedly improved here in 2026. Now there's a numerator and a denominator to capital efficiency, and I know there's longer laterals, improved completions. Maybe some color with respect to at the capital efficiency level, the improvement that you're seeing from these type curves. And then if there is the potential that this could translate to some lower capital in the future given higher production?

Yes, that's right, Patrick. And I actually think that's where you've seen it shine through so far. Because markets haven't been buoyant in terms of price, we've taken these efficiencies as a result, have put less wells on production, yet have been able to maintain the profile we are hoping to achieve on production, so less CapEx. What you're seeing in the well results and the remarkable improvement over the five-year average is both higher completion intensity, it is also longer laterals, it's also some of our learnings in the play on landing some of the machine learnings that Mike was speaking to on tweaking the technology to optimize each individual assumption and component of the completion.

What you're also seeing along with this productivity increase is us maintaining capital cost per foot at flat or lower levels. And so we're doing more work in the well, higher tonnage, sometimes more water, more pressure, longer laterals, we've also been able to continue to push costs down, continue to expect OFS costs for Tourmaline to come down slightly this year, we hope to lower them again next year. That does allow us to have better capital efficiencies over time.

We haven't yet reflected that in all the forward plan years. We honor the last year's rate of efficiencies and the last year's type curves. As these soak into our actual results and our reserves, you will see commensurate improvements in the forward plan efficiencies, that will also drive higher free cash flow.

Great. Great. And maybe just to build on Neal and -- this may come off a little bit long-winded here as I'm sure you're all aware, I'm not known for my brevity. Considering your outlook for demand and the shift to demand pull here, the things from a secular growth perspective seem to be shaping up LNG export, increased power demand, not necessarily seeing it and the resource reflected in the equity today. Specifically in terms of the mode of those capital returns and the incremental free cash flow you guys have generated or will generate with the capital reduction or shifts with the Phase 2 plan. Any thought now at these equity prices to be a little bit more aggressive and potentially start to dip into the NCIB?

We always look at that, Patrick. Right now, I mean, it's fairly simple math at $2 gas, we can cover maintenance capital, the growth capital component for '26 and '27 and the base dividend, and there's not a lot of free cash flow left over beyond that. We do think that is going to change rapidly here. We're going to realize that free cash flow first and then look at what are our options.

I would say priority 1 would be a base dividend increase when we have enough free cash flow on a sustained outlook to fund that. And as you know, we use a very harsh price environment for 5 years when we contemplate base dividend increases. And as the free cash flow continues to accrete, Jamie mentioned that $1 on AECL, which really isn't very much from where we are now is $500 million in free cash, and then we will look at the full gamut of shareholder return options.

And the next question comes from Jamie Kubik from CIBC.

You touched on this a little bit earlier, but can you talk about the power opportunity or data center opportunity for Tourmaline and what something like that could look like?

I think we can all jump in on that one. I mean we're not going to build a data center. They're quite expensive. I just want to make that clear. But we do see it as another opportunity for our gas market diversification portfolio. So we'd be seeking a gas supply deal with pricing that reflects reliability and all the other services that we can offer, and those include land, water, power redundancy, fiber connect, further growth opportunities, low CI gas to begin with, but also the opportunity for full CCUS disposal. All those would translate into a higher fixed price contract. So we're well over a year into trying to co-locate with a hyperscaler at one of our plants. It's the Banche plant near Edson. It's about 40 kilometers from Edson. So nothing firm to announce on that, but we're quite far along in the process.

And Jamie, I'd say, first, we -- you always like your own cooking, right? Like at first, we thought we had a good site and we engaged partners to proceed with this project. Now that we're in market and trying to find offtakers for this, I think we firmly understand they think it's a good site, too. So our confidence in being able to try to build a project here is increasing. And I think these are -- these projects are complex and they take some time, so have patience with us. But we firmly believe when we do get this across the line, it will be a big win for Tourmaline.

Okay. That's good color. And then appreciating there's a number of moving parts in the guidance adjustments for '27, '28. But can you talk a little bit about the liquids guide for '26 as well and maybe the condensate outlook in particular, just with the update overnight. Any color on that side would be helpful.

Yes. Thanks, Jamie. I think if you pull well results for Tourmaline right now, you are going to be able to replicate that 26% upside, and you are also going to see very strong upticks on the liquids we are receiving out of the wells. We are winning on both products. One of the effects of slowing down is all businesses in resource plays have a slightly higher decline rate on liquids than they do on gas.

So when you bring less wells into market, you are going to have a slight decrease in liquids relative to gas as an MBOe mix. We are going to have that come back to us this fall. As we get all these wells that we have drilled and completed and now are able to complete more through Q3 and turn them in line, you are going to see the liquids mix really ramp into the back of the year.

I am comfortable with the guidance we have out for 2027 and thereafterward. Condensate is a big part of the NACB build-out. We are going to have very rich condensate wells contribute to both the Aitken plant start-up and the Groundbirch plant start-up. It is going to be a meaningful cash flow driver for Tourmaline. It has just been on the bench a little bit as we have had to slow down due to weak gas prices this year and last year.

The other thing is the market is really -- we're seeing much more potential for strength in condensate pricing with the build-out of oil sands projects and the attention to oil pipeline, et cetera. And the ability to bring condensate back in via Cochin and Southern Lights is lifted. So we'll see that premium rise. And in tandem with that, of course, that creates another demand source for nat gas too that goes along with that because we think every 1 million barrels of additional oil sands production is about 0.7 Bcf of new gas demand.

And the next question comes from Sam Burwell from Jefferies.

Congrats again to Brian and Jamie on the respective moves. I wanted to follow up on the data center aspect. Mike, I appreciate you confirming that you won't be building the data center itself. But just curious like what type of capital commitments, if any, would there be at the Tourmaline level? It sounds like you're just interested in doing a gas supply contract rather than delving into power. But sort of just curious like how this Emerald entity might be capitalized if there's any Tourmaline contribution contemplated or this would be funded by partners or external financing kind of at the Emerald level?

You're right, Sam. It's low capital commitment from Tourmaline. That's our mantra for this whole thing. It really is just gas diversification. There may be opportunities on the power side that remains to be seen. And we're keen to help get this whole gas demand sleeve from data centers moved along in Alberta. So that's one of the reasons we'd like to help get that going with the project of our own.

And as Jamie referenced, they're very complicated and very expensive, and there's a very long due diligence process. But there's been one announcement, and we think there's going to be several others. And ultimately, we want to see or we believe that it could be up to 1 Bcf a day of incremental in-basin demand, which will just be wonderful for the AECO market and tighten it even further. It's almost like another LNG project happening in the basin.

Yes, for sure. And I guess on the topic of LNG, Cheniere Energy has been in the news. They've been selling more gas, which is good. And you and I think a few other companies exited the Rockies LNG consortium. So curious for your outlook on that project's time line, whether you think it can be a meaningful driver of demand pull in the early 2030s? And are you guys more confident now that you can execute a bilateral arrangement where you might get a JKM linked price by selling gas into that facility at some point?

Yes. I mean you hit it at the end of your comment. That's what we'd be seeking from a contract standpoint. And we really hope Cheniere Energy goes ahead and hope that we're in a position to be a supplier to that pipeline.

And the next question comes from Fai Lee from Odlum Brown.

To Brian and Jamie as well. Just the last question, I was just wondering in terms of the type of agreement that you'd be looking on a long-term basis, would you be looking for some locked in fixed price? Or would you be looking for some variability around -- how are you thinking about in terms of marketing in terms of these potential LNG agreements?

Are you talking about additional LNG agreements or the data center, just to clarify?

Yes, sorry, the additional LNG agreements.

Yes. So we like access to international pricing, whether it be JKM, TTF or something of that ilk. And then we are willing to pay a fixed deduction below those prices. And those deductions are based on shipping costs. So obviously, on the West Coast, shipping costs are much lower than the Gulf Coast, but they're also based on liquefaction costs and liquefaction costs will be borne out of the capital cost that was made to construct the facility. And so to date, we have 7 different agreements in the Gulf Coast, many of which we supply physically, some of which we supply locally and then enjoy a knit delivery point. And those deductions have been very competitive.

And in fact, if you look at our portfolio, we are in some of the lowest cost LNG facilities in the world. And that's how we've driven our decision-making because it allows us to make money through the entire LNG price cycle. When we're looking at these West Coast opportunities, we're looking at it under the same lens. And we think as they expand and also more are announced, we're going to be able to blend down that liquefaction cost to a competitive level, and they already have the shipping cost advantage. And so we continue to seek to try to replicate our Gulf Coast strategy on the West Coast on a similar contract style.

And no further questions that came through at this time. I will now turn the call over back to Scott Kirker. Please go ahead, sir.

Thanks, everyone, for checking in. We'll see you in the next quarter.

Thank you. This concludes our conference call for today. Thank you all for participating. You may now disconnect.

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.