Earnings call transcript: Tourmaline Oil Q3 2025 misses EPS forecasts

Tourmaline Oil Corp. reported its third-quarter earnings for 2025, revealing a significant miss in earnings per share (EPS) and revenue compared to forecasts. The company posted an EPS of CAD 0.49, falling short of the projected CAD 0.82, marking a surprise decline of 40.26%. Revenue also came in below expectations at CAD 1.48 billion, compared to the anticipated CAD 1.53 billion. Following the announcement, Tourmaline’s stock price dropped by 3.23%, closing at CAD 59.71.

Key Takeaways

• Tourmaline’s Q3 2025 EPS fell short of forecasts by 40.26%.
• Revenue was CAD 1.48 billion, missing expectations by 3.27%.
• Stock price declined by 3.23% in after-hours trading.
• Production averaged 634,750 BOEs per day, at the high end of guidance.
• New LNG supply contracts and natural gas storage agreements were secured.

Company Performance

Tourmaline Oil’s third-quarter performance was mixed, with strong production metrics but disappointing financial results. The company achieved an average production of 634,750 barrels of oil equivalent per day, which was at the high end of its guidance. Liquids production increased by 4% quarter-over-quarter, demonstrating operational efficiency. However, the weaker-than-expected financial results highlight challenges in the current market environment.

Financial Highlights

• Revenue: CAD 1.48 billion, down from the forecast of CAD 1.53 billion.
• Earnings per share: CAD 0.49, below the expected CAD 0.82.
• Cash flow for Q3 2025 was CAD 720 million.
• Earnings for Q3 2025 totaled CAD 190 million.

Earnings vs. Forecast

Tourmaline Oil’s EPS of CAD 0.49 was significantly below the forecast of CAD 0.82, representing a negative surprise of 40.26%. This miss is notable compared to previous quarters, indicating a challenging period for the company. Revenue also fell short, with a 3.27% miss against expectations, underscoring the difficulties faced in meeting market forecasts.

Market Reaction

In response to the earnings miss, Tourmaline’s stock price decreased by 3.23% in after-hours trading. The stock’s decline reflects investor concerns over the company’s ability to meet financial expectations. The current price is closer to its 52-week low of CAD 55.40, highlighting the pressure on the stock amidst broader market trends.

Outlook & Guidance

Looking forward, Tourmaline has set a production guidance of 690,000 to 710,000 BOEs per day for 2026, with an expected cash flow of approximately CAD 4 billion and free cash flow of CAD 0.9 billion. The company is also targeting a 5% reduction in operating expenses in the Deep Basin and exploring opportunities in data center power generation.

Executive Commentary

CEO Mike Rose emphasized the company’s focus on cost reduction and operational efficiency, stating, "We’re targeting a 5% OPEX reduction in the Deep Basin next year." He also highlighted the potential impact of LNG Canada on market dynamics, noting, "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."

Risks and Challenges

• Weak AECO and Station 2 gas prices, the lowest in 30 years.
• Competitive pressures in the natural gas market.
• Potential delays in LNG Canada impacting demand.
• Volatility in global energy markets.
• Execution risks associated with cost reduction initiatives.

Q&A

During the earnings call, analysts inquired about the potential sale of the Peace River asset and the company’s flexible capital spending approach based on gas prices. The management expressed interest in exploring data center power generation opportunities and remained optimistic about the positive impact of LNG Canada’s demand on market dynamics.

Full transcript - Tourmaline Oil Corp. (TOU) Q3 2025:

Conference Call Operator: Good morning, ladies and gentlemen. Welcome to the Tourmaline Q3 2025 results conference call. At this time, all lines are in listen-only mode. Following the presentation, we will conduct a question-and-answer session. If at any time during this call you require immediate assistance, please press star zero for the operator. This call is being recorded on Thursday, November 6th, 2025. I would now like to turn the conference over to Scott Kirker. Please go ahead.

Scott Kirker, Chief Legal Officer, Tourmaline: Thank you, operator, and welcome everyone to our discussion of Tourmaline’s financial and operating results as of September 30, 2025, and for the three and nine 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 CDOR and on our website. I also draw your attention to the material factors and assumptions in those advisories. I’m here with Mike Rose, Tourmaline’s President and Chief Executive Officer; Brian Robinson, our Chief Financial Officer; and Jamie Heard, Tourmaline’s Vice President of Capital Markets. We’ll start with Mike speaking to some of the highlights of the last quarter and our year so far.

After his remarks, we’ll be open for questions. Go ahead, Mike.

Mike Rose, President and Chief Executive Officer, Tourmaline: 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 2025 average production of 634,750 BOEs per day was at the high end of our anticipated guidance range of 625,000-635,000 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 Dinsdale 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 two short-term and one long-term LNG gas supply contracts, which complement our existing extensive portfolio, looking specifically at production.

Fourth-quarter production is expected to average between 655,000-665,000 BOEs per day, with a 2025 exit volume of 680,000-700,000 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 2026 average production guidance of 690,000-710,000 BOEs per day remains unchanged, as does the current multi-year 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 CAD 720 million, and third-quarter 2025 earnings were CAD 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.

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 US, by approximately 155 million cubic feet per day. 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 ended 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. 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-$2.85 billion. We closed a $71.7 million transaction with Topaz Energy Corp, whereby Topaz purchased a GORR on the recently acquired Seguerro and Strathcona ground-rich Northeast BC Montney development lands. 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 CAD 6.86 per MCF in the Western US markets. Q3 2025 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 Dinsdale 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 two. 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 MMBTU exposed to international pricing in 2026. That’ll grow to 250,000 by exit 2027 and 330,000 by exit 2028, so a very attractive progression.

Turning to the capital budget and the EP plan, as mentioned, spending in the quarter was CAD 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 2026 EP capital program is CAD 2.9 billion. That is unchanged from the release on July 29, 2025. Utilizing current strip pricing, our EP plan anticipates 2026 cash flow of approximately CAD 4 billion and free cash flow of approximately CAD 0.9 billion. The strip pricing includes a 2026 AECO basis of $1.66 per MCF, and we anticipate that basis tightening towards $1 US as the basin dynamics adjust for LNG Canada’s demand. For every $0.10 per MCF US that AECO basis tightens.

Our 2026 cash flow and free cash flow would increase by approximately $50 million. 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-$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 2026 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.

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. 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 CAD 1 per BOE as it is put in place over the next six years. 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.

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. These reductions are not captured in the multi-year EP plan yet because we’ll make sure we realize them first. 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.

This initiative is just a subset of the significant internal value creation opportunities that exist within the company’s overall portfolio. Specifically on EP in the quarter, we drilled 68 wells, completed 88 wells, and entered the fourth quarter with 38 ducks, 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 five-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. 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.

We have 12-15 new pool or follow-up delineation wells currently in the Q4 2025 and 2026 drilling program, so lots of exciting opportunities on that front. On the dividend, our Board has declared a special dividend of CAD 0.25 per share. That will be payable on November 25 to shareholders of record on November 14, 2025. The company intends to declare the quarterly base dividend of CAD 0.50 per share in December. We commenced paying special dividends in September of 2021, and that special dividend has varied between CAD 0.35 per share and CAD 2.25 per share until this quarter, where it is CAD 0.25. While the 2026 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.

I think that’s enough for formal remarks, and there’s four of us here. Ready to answer questions you may have. Thank you. Ladies and gentlemen, we’ll now begin the question and answer session. Should you have a question, please press the star followed by the number one on your touch-tone phone. You will hear a prompt that your hand has been raised. Should you wish to decline from the polling process, please press the star followed by the number two. If you are using a speakerphone, please lift the handset before pressing any keys. One moment, please, for your first question. Your first question is from Kyle Akman from Bank of America. Please go ahead. Hey, good morning, guys. Hi, Mike. 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. I guess fundamentally, if you do not see the price that you want, would you consider retaining the asset? The part B to 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, Kalei. I’m 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 does not hit a certain value, we are 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. I think we’d sell it all together rather than break it up. I did mention in the formal remarks, I mean, 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 had a rebirth where we had a different application of horizontal multi-phase fracking drilling for the Charlie Lake, and it’s worked extremely well. Why are we selling it? The reality is that the returns from investing in our two very large gas complexes kind of always outstrip the returns from growing the Peace River High asset in a material way. It has been essentially on maintenance capital for four to five years.

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 two gas complexes. That is kind of the rationale behind it. That is great, Mike. I appreciate that. For the second question, in the release, you called out a handful of what I will call cash management items. Given the recent price environment for AECO gas, I think that is prudent, although things seem to be on the mend today if we are looking at AECO prices. We just talked about the Peace River sale, but there is also Topaz Equity, and there are CapEx deferrals that you have in your back pocket. I will leave the Topaz question for someone else, but I am wondering how you would characterize the CapEx deferral of CAD 200 million-CAD 250 million.

Is that drilling related, or is that infrastructure related? It would be primarily drilling related. If we exercised on that in a weaker price environment than we’re in today, we would carry on with the BC infra build-out. I think you can see the rationale for that, that if prices are significantly weaker, we’d hold the volumes back, and so that would mean the D&C budget would be reduced. Great. I appreciate it. Thank you, Mike. Thank you. Your next question is from Patrick O’Rourke from ATB Capital Markets. Please go ahead. Hey, good morning, guys. Maybe just a follow-on with respect to the CAD 200 million-CAD 250 million and potential reductions here. Just wondering, what’s sort of the timeframe for those decision points, rolling out into 2026? Is there any sort of quantification on 2027, 2028, et cetera, from a volume perspective?

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, over two or three years, we think would fully replace the volumes from that complex. As far as timing on when we would make those decisions, I think we see if the Peace River High sells first because obviously there is a maintenance capital budget item associated with that complex in the current 2026 budget, so we would be adjusting the 2026 budget at that point.

By year end, I think we’ll have a pretty good look at where the 2026 strip is going to be, where basis gets to. Yeah, 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 is free and clear. We should be switching to, or flipping to, withdrawals from storage now, and that will drive price. 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. LNG Canada was not taking the same volumes west that they have been, which I think has gotten up as high as 800 tons. Is that right, Jay? Yep. Yeah. Okay. Great. Thanks for that, Kalei.

And then just thinking about sort of the interplay between the balance sheet and potential for special dividends, I know, I do not want to call it caution, but obviously it has been a sweep of free cash flow. Debt was a little higher. You have got the proceeds coming in from the Topaz share sale, so that will help. 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? Yeah. I mean, we are thinking about all those things. 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 two quarters of the lowest AECO prices in 30 years is a rare circumstance. For Q3.

Paying the special using the balance sheet was one of those rare circumstances. We will continue to look at the growth capital and the special dividend potential and find that balance. Okay. Thank you very much. Your next question is from Sam Burwell from Jefferies. Please go ahead. Hey, good morning, guys. It’s another question on the CapEx flexibility. Just curious, what drives that decision? How do you frame it? Is it based on not wanting to outspend after paying the base dividend? What sort of timeframe in terms of viewing the strip or your view on gas prices are we looking at? Is this months, some sort of medium-term time horizon? Just curious about how you’re thinking about potentially flexing down the CapEx. Yeah. I mean, the main control, of course, is the gas price, and then everything flows from that. Yeah.

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 curtail volume today. You’re kind of seeing fully loaded receipts, and it’s not scary. Your growth is very modest, and we think that’ll allow this winter strip to improve. Tourmaline has a natural recalibration every spring and breakup. 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.

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. Okay. Understood. Then sort of tying into that a little bit on the Canadian gas macro, supply has come up a bit. Granted, the shut-in is coming back, and it’s sort of typical seasonality and the prices come up. Do you think that there’s more room for supply to come on? I’m just asking this because we are going to get more demand from train one pulling more consistently and then train two pulling another 1 BCF a day next year. 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 two. Yeah. We regularly refresh this work. As I was saying, November looks relatively flat to last year, and we do not believe we are curtailed much at all as a basin today. Our expectation is next year grows well shy of a billion cubic feet a day on an annual RANA basis. Our number would be around 0.6-0.7 exit of our exit growth. We think actually might even be shy of that, around 0.5 BCF a day. 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.

That is 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. We think that will transpire over the next several months. We think there are other tailwinds at play. We believe the Bison expansion on the Northern Border is a benefit to the Canadian export picture. It tightens up our basin ever still. We also think there is going to likely be power consumption and power announcements over the next 12 months that help spur long-term demand thinking and tighten up that 2027, 2028, 2029 basis picture as well. 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 rescon. I think it will take Canada and Alberta specifically getting a little cooler here in the next three weeks to see what the draws ultimately look like on a year-over-year basis. 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. I think that starts to wake the market up. Yeah. The last time the basin had a demand increment like LNG Canada adds the two fees a day was the startup of Alliance, and I think that flipped the differential for three years. That’s right. Yeah. Okay. Understood. Really helpful color, guys. Appreciate it.

Your next question is from Aaron Balioski from TD Cowen. Please go ahead. Thanks. Good morning, guys. 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 multi-year plan, or is the plan to simply redirect some of that maintenance capital that was being spent on the Charlie Lake into the Montney in the Deep Basin? Yeah. More of the latter, Aaron. At this point. I think in order for us to add capital in the VP plan, we would want to see strong commodity prices provide that signal. At this point, it is going to deliver the balance sheet, and it is another source of funding for this infrastructure growth that is going to start to add that incremental cash flow and free cash flow that, frankly, we are going to see.

We saw some of it this quarter. We are going to see more of it in 2026. As Aiken comes on and Ground Burch comes on over the years ahead, you are going to see that structural cash flow and pre-cash flow start. It is funding that build-out. Perfect. Thanks, guys. Yeah. Thank you. Your next question is from Jamie Kubik from CIBC. Please go ahead. Yeah. Good morning. Thanks. Aaron sort of asked the question I was going to ask her, but I will ask a little bit of a different one. Can you just talk about how you are thinking about debt levels in the business? Is there a target in mind that you are driving to? Is it a function of forward cash flow? Just a bit more color on your thought process around this would be great. Thank you.

I think we hit our kind of peak debt metric right now at 0.5-0.6 times at the bottom of the cycle. That will drive down to 0.2-0.3 as we move towards a, we think, a more sustainable long-term price cycle. We are going to keep that pristine balance sheet focus that we have always had, Jamie. Okay. Can I ask maybe, is the peak debt level where you are 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? Thanks. For sure, the latter. It is capital allocation. I mean, we have been.

Thinking about selling the Peace River High complex for two or three years, to be honest, simply because it was not getting rewarded with growth capital because we had more attractive projects in the two gas complexes. It feels like this was probably the right time, and there is considerable interest in it. Worth flagging, Jamie, the interest is also what helps spur the process. There are interested parties that are looking to enter this basin, and they have unsolicitedly given us indications of value or interest in acquiring the asset. Now running the process allows all of them to come to the table with their best number at the same time. Okay. Thank you. That is all for me. Thanks. Your next question is from Joseph Schachter from Schachter Energy Research. Please go ahead. Good morning, everyone, and thanks for taking my questions. Two of them.

First thing, you guys have a great track record of making acquisitions in the past. When you look at your two 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? Yeah. We went through five years of putting primarily the BC Montney gas complex together 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 five or six years. Now we’re going to go realize all the upside and all the value from those really well-timed acquisitions. We’ll always look at perhaps small asset tuck-ins, but right now the focus is much more on organic growth from the extensive inventories we have really in both gas complexes. Super.

Second question, the past 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. We are super excited how the whole Topaz story has unfolded and grown, and I think it has just been great all the way along. We are happy to be shareholders. Super. Okay. Thanks very much. That answers my questions. Your next question is from Faye Lee from Odlum Brown. Please go ahead. Thanks. It is Faye here. Hi, Mike. You just touched on it a little bit earlier about, I guess, growing power demand. There are obviously some bullish projections for gas demand to meet growing electric demand from data centers or fuel intelligence.

I’m just wondering how this longer-term basis could maybe possibly affect your strategy for marketing gas. If you’ve had any considerations of specific steps you could take to capitalize on these opportunities. For example, do you think you’ll ever have direct gas supply agreements with data center builders? I’m just wondering how you’re thinking about that. Thanks. Yeah. We’re evaluating that opportunity FIE. We would look at it as just another sleeve of our overall gas diversification. We do have lots to offer. 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 little CI gas to begin with. Yeah, we’re assessing whether that’s an opportunity to further diversify our very diversified marketing portfolio already. Okay. You’re looking at that.

I’m just wondering, on the other side, have you been approached from data center builders or people looking at the advantages that you can offer and 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? Yeah. 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 AECO allocation would be and who would be a recipient of the AECO allocation. That has happened. We would be the first to cheer on projects like Greenlight because that’ll help consume gas in basin. The reality is we can build a lot of these.

One gigawatt on a high-efficient power plant will only consume roughly 150 million cubic feet a day. We think you could do 10 in short order, and you would still find the basin in balance, and we would be able to answer that call. As operators understood how much AECO allocation they might get, now we are starting to move to that kind of phase two where it is a bring-your-own-power effort. Operators are looking to add generation to their projects, and then they need gas supply for that generation. We would fit naturally into all those conversations that we are having with them. As Mike was saying, one of the areas I think we were probably most interested in is those co-location opportunities because it allows us to offer more than one service. When you offer multiple services to a counterparty, you can enjoy that business.

We have great sites across our asset base that many of them actually are very, very suitable for this kind of activity. I think over the next 12 months, we should see all sorts of different data center announcements, some of which would be in the heartland and would connect to AECO, and some of which will be closer to the resource and have a behind-the-fence strategy. I think we are working hard on making sure we are positioned well to participate in those that are attractive to us. Okay. No, that is great. Excellent color there. Thank you. Thanks. Bye. Your next question is from Neil Mehta from Goldman Sachs. Please go ahead. Yeah. Thanks for all the color and talking through 2026 as well. As we think about 2026, maybe you could talk about what cyclical versus structural cost deflation.

We continue to be in a relatively favorable oil services environment for the EPs. Just curious if you’re able to capture some of that cyclical deflation as opposed to maybe some of the structural benefits as well. Just the cost environment going into 2026. Yeah, you’re right, Neil. It is a little bit more favorable on the service cost side and D&C costs through this winter. I think we kind of eyeballed a 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. They’re structural and repeatable, and they will accelerate over the next couple of years. They marry up well to base dividend increases. 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. Do you actually get the price response with the LNG pull? Yeah. We think we will. I think Jamie outlined that we really do not think there is a lot of gas behind pipe right now. We think we are seeing pretty much everything that is available on stream at this point. We expect another 1 BCF plus of intra-basin demand when we get cool weather. We are not cold at all yet here, but that is coming in the second half of November. You have got another 1.2 BCF yet to come from LNG Canada when they get.

Phase one and both trains fully on stream. I think we’re eyeballing Q1 of 2026 for that. You still have, although, as I mentioned, for a few days here, the West Gate’s 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. In aggregate, you’re well over 2 BCF a day flip. That’s why Jamie was referencing it’ll 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. 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 0.6-0.7 BCF per annum. So it is going to be close to three years to replace that sink. And a lot of that relates to getting onto 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. If you want to bring gas on the system today or in 2026, you had to be organizing your firm service four years ago. Okay. Great color, guys. Ladies and gentlemen, as a reminder, should you have any questions, please press the star key followed by the number one. We will pause for further questions. 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.

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