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 will be open for questions. Go ahead, Mike.

Thanks, Scott, and thanks everybody who dialed in. We're pleased to announce our Q4 2025, disclose year-end reporting, and update on '26 activity so far.

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.

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 0.5 times 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 as 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. 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 will replace that with new low-cost production streams flowing through newly constructed Tourmaline facilities. 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 two 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 buildout split between the next two years, and that's the phase one buildout. 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 multi-year EP plan and the COV, and it's been updated for results in '25, asset sales, very strong wall 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 US 10 cents per mcf that AECO pricing improves, our '26 cash flow and free cash flow increase by approximately $45 million.

Similarly, because we are exposed to these markets, for every dollar per mcf US that both JKM and TTF improve, '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. 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. 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-and-perf-style completions, mostly in the Northeast BC Montney. We also increased future facility capital in the year-end '25 report.

These one-time 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 Canadian $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. That's Dawn, Ventura, Chicago, Iroquois, Emerson, and ANR Southeast.

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 two expansion of that facility.

In '26, we'll have access to 6 BCF of storage capacity, and that starts in April of this year. Then next year, in mid-'27, it increases to 10 BCF, and that's for a 10-year term.

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. 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. We're excited by the rapid progress that we've made already.

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%, our '26 opex guidance is $4.50 per BOE. With the success of the cost-reduction initiatives to date, we are revising our aggregate operating and transport cost reduction target that was a dollar per BOE by 2031 to $1.50 per BOE, and approximately 70 cents 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, and 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 buildout 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. That'll flow through to lower corporate break-evens 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 were 22% higher in '25 than the previous 5-year average, and that's based on the IP90 of 102 wells. This outperformance has been across the full suite of the BC Montney assets from Aitken/Birch/Gundy in the north to Groundbirch/Doe/Mica 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/Mica gas plant projects in BC. Aitken is on schedule for a Q4 '26 completion, and Mica 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. 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, or 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're 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.

The timing of this is significant given the ongoing negotiations on methane between the province of Alberta and the federal government. There's 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 50 cents per share, payable on March 31, '26, to shareholders of record at the close of business on March 16, '26. 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. That's it for the formal remarks, and we're here to answer questions.

Hey, good morning, guys, Mike and team. Thanks for taking my question.

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 break-up season kind of around the corner, I imagine that decision would be eminent. What factors would influence your decision?

How do you allocate the reduction across the asset base? 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?

Yeah. Cutting the capital budget in '26, sorry, is exactly what we did in '25 and '24.

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 two plant projects in BC on schedule. Total facility spending in BC is sort of between $250 [million] and $300 [million] for those particular projects, we do have quite a bit of flexibility.

You mentioned break-up. It gives us a bit of time, probably two to three months, to watch where prices go.

We are starting to see AECO move upwards from its sort of $1.60 level. PG&E was constrained.

Usually that's a huge premium market for us. Usually trades two bucks US above Henry Hub, now it's a dollar below Henry Hub, which we haven't seen in the nine 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, lots of excess hydro.

Then there's a particular maintenance project at the Grand Coulee Dam where they have to do dry dam maintenance that starts on March 15th. 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, it certainly hasn't helped gas. Now, we expect that price to start improving when the maintenance starts, and then that 6 gigs is gone for an extended period of time.

They do the maintenance, and then they have to refill. We're positive on our outlook for where PG&E prices are going to go.

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, if we got to the marvelous price of $2.25, all of a sudden our free cash flow is over a billion dollars.

Kind of puts it in context. 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.

Thanks, Kalei.

Thanks, Mike. 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 programs 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.

We're up to 75% of the wells in BC on plug and perf. 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. We did take the entire booked inventory well cost up primarily because of this evolution to plug-and-perf-style completions.

Our 2P F&D, because we're carrying the booked inventory, would have been $5.88 a BOE rather than the $9.08 because we basically recalibrated the entire inventory, and you eat the capital all in year one. Sets us up nicely for even lower F&D in future years.

We're always working on it and figuring out the best recovery, the best deliverability, and the best economic return on the wells.

Got it. Thank you, Mike.

Thank you.

Hey, good morning, guys. I wanted to piggyback on Kalea's question on the CapEx deferrals.

First, were these in the Deep Basin primarily or in Northeast BC or spread all over the place? Then how does this impact 2027 and beyond?

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. 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.

That's essentially what we did in the second half of 2025. We shaped the production growth curve to the improving price curve.

December prices actually were good in '25, and we're able to do that very quickly. Deep Basin break-even is about two bucks 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.

Right now we're weak locally at AECO and Station 2, and on the west coast in the US. We're strong in the east and obviously a recent tailwind with our exposure to JKM and TTF.

We remain very flexible. I think we can pivot faster than anybody with our EP program, and we will.

Great. Then the next one just on the ethane rejection decision.

Is that idiosyncratic to just those particular contracts at certain plants, coupled with the desire to just cut cost? Or is this any wider indication of ethane recovery economics across the basin?

The only place we recover ethane was in Alberta, none of the BC buildout is impacted by that because there isn't an ethane business out there. 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. Generally we made very, very little to nothing off ethane.

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. 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.

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. 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.

Got it. Thank you, Mike.

Thank you, Sam.

Good morning, all, and thank you for taking my questions. 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 of special dividends? 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?

We are always available and willing to sweep additional free cash to shareholders, and our preferred method has been the 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 in the last couple days alone, that's added several hundred million dollars to our forward outlook of free cash flow. 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 could propel JKM and TTF prices to a point where free cash flow is well over a billion dollars for Tourmaline. We're monitoring that.

It's also affecting our FEI pricing of propane. That's up quite a bit relative to where it was last week for our forward outlook.

It's also adding to our free cash flow outlook. As we march through the year, we'll continue to monitor our forward free cash flow profile.

If there's ample free cash flow over and above the base dividend, we will return it.

Great, thank you. That's very helpful.

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 buildout relating to data center demand in Western Canada?

Have you seen timelines or just broader conversations progressing as expected? Have these discussions been of the scale or magnitude that would encourage you to participate in a potential project?

We're a year into a process exploring the possibility of co-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 if a hyperscaler wanted a full green solution, if you like. We will know what we're going to do specifically this year in 2026.

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'll 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 two on-grid projects, we kind of see it as a minimum B and a half a day of gas consumption inside the basin.

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 say, Greta, 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's still in that phase. The second phase was reigniting brownfield assets or mothballed assets.

This third phase has been brand new greenfield development with behind-the-fence power generation matched with a data center. 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, into Montana. 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.

As we see these buildouts, we're excited for the opportunity to participate in the province of Alberta, whether it be our co-location project that we're directly involved in or a firm supply agreement with a project that is near one of our asset bases. We also think that Tourmaline's gas in the western part of the northwest of United States is going to have preferential access to the vast buildout that's already occurring into basins that, frankly, have a declining local supply environment.

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 2027, 2028, and beyond.

Great. Thank you very much.

Good morning, guys. You've been pretty nimble with the shorter-cycle EP 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.

I think we want to keep the first two plants in the Montney buildout on schedule. As I mentioned, so that would be Aitken and Groundbirch/Mica.

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 two of the BC Montney buildout. We can take a year off if we need to and build significant free cash flow in that particular annum.

We're just going to see how it plays out, but as you mentioned, we are nimble and can pivot quickly.

Perfect. Thanks, Mike.

Thanks, Aaron.

Thanks. Good morning, guys.

I wanted to touch on the LNG exposure that you have given the capacity and contracts signed, and 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. Could 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?

Thanks.

Hi, Josh, it's Jamie speaking. Your numbers are roughly correct.

We ran the strip that you're seeing for '26 and '27 in the five-year plan on March 2nd, 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 a quarter of that, that's also in the hedge disclosure available in our financials and website. We have taken steps to lock in some of this spike that we've seen, but we're totally aware that a long-term outage specifically of a 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.

The sensitivity is a dollar change in JKM or TTF together is roughly $50 million of free cash flow this year and $70 million next year. We've seen obviously these markets go into the $20s, $30s, $40s on supply disruptions before.

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.

Thanks. 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. I'm talking about, yeah, holding Hub flat, if JKM and TTF move a dollar, that's your sensitivity.

It's a sensitivity of just the floating market. We're not going to get into the slopes and the deductions, etc., those are all confidential in contracts.

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.

Then just on cash allocation, in a year of $1.5 billion at the end of the year, you're taking $500 million down from that, you're at a billion dollars, 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?

Thanks.

Hey, 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, the $1.5 billion is after receiving the effective consideration of the Arch.

Maybe I'll let Mike talk about our M&A outlook.

Yeah. Right now the M&A is focused on small asset tuck-ins in and around existing infrastructure or infrastructure to be built.

We're not looking at anything large at the current time. Persistence and patience are the key to prying assets out of large companies, and so we'll continue with that approach.

M&A is not a big piece of the equation right now.

Got it. Yep.

Thanks for the clarification. Thanks.

Thank you.

Yep, thanks for taking my question. Just with respect to forward pricing, AECO and Station 2 aren't really sustainably above three bucks a GJ until 2028.

Should we think about potential for shut-ins through the summer from Tourmaline? I guess when do you expect that forward pricing turns for the better here?

Thanks.

If the price gets low enough, and we've shut in before, of course we're always thinking the price is going to go up. 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.

We can be very nimble about when we inject and when we withdraw. It's a very high-deliverability reservoir.

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, it's kind of fun that way.

Just some comments on LNG Canada and it's on, and gosh, the price is two bucks 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 three Bs a day out the west gate and the other B that comes down through the Westcoast system into the Pacific Northwest to clear.

We see the PG&E prices will start to help with that. There's an order of fill with the LNG Canada facility.

The first train, most of the fill came from the direct connects that a couple of the large operators have. Then it was, as you brought train two on, the first volumes for that were off the Enbridge system, so that meter station is Sunset West.

The last station to get gas, which is the one that affects AECO and the NGTL system, is Willow. It's had really strong volumes over the last three or four weeks, and so AECO, NGTL get the positive impact last.

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. We're going to end up well into the 200s of withdrawal.

That's positive. 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 a billion cubic feet a day.

Exit-over-exit was actually down. February was much milder, we didn't have freeze-offs this year, but we still average, call it 0.6, 0.7, and then that's thinning to, call it 0.4, 0.5 today as we see supply.

The local S&D is good. 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.

As that market strengthens, AECO can strengthen. There's no long-term glut issue locally.

It is this idiosyncratic demand issue you've had with just a very bizarre winter, which was very east-focused and not very west-focused.

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

We kind of schedule our turnarounds, or try to, to when the scheduled TC and Enbridge turnarounds are happening. 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.

Thanks. That's all for me.

I'll turn it back.

Thanks, Jamie.

Thank you. Hi, Mike.

Just trying to get my head wrapped around your five-year plan and the AECO pricing assumptions. Given the futures 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.

Is that something related to the PG&E demand that's improved, that you see moving up closer to that, or what's your confidence interval around the $4 outlook for 2028 and beyond?

Hi, Fai, this is Jamie speaking. The first two years, as you mentioned, are on strip, and we just honored the strip that's offered on the day.

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. 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'll be volatility in either side of that.

Then in a $4 Hub environment, we believe AECO should price at transport economics, and transport economics would imply a basis of roughly a dollar US. In the current foreign exchange environment, a dollar US basis is effectively offset by the FX, $4 Canadian would be your implied AECO price.

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-annum 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.

We thought the flat deck was a better way to illustrate how the profitability of the business was getting better

in the out-years

in the out-years.

I understand the rationale, and I don't have an issue with what you've just said. I just trying to understand if the reality turns out to be closer to the future strip, which is closer to, call it $2.50, $2.55, does that change your marketing strategy or, a lot of time we talk about capital plans, I guess, as well.

How are you setting up your five-year plan if that outlook isn't really $4? I guess would you consider, in 2027 and beyond, you're increasing your AECO exposure, would that change if it's closer to the $2.50 in reality?

Everything would change. I did reference that when Aaron asked his question, we can slow down on the North Montney Phase 2 buildout in BC, so that's addressing the capital side of the equation.

We are the most diversified producer in North America, right now it's about 1.3 Bs a day of our 3 BCF a day is exported. Usually we win on those markets, although this winter we did not win on California.

We'll continue to look for diversification opportunities, which help the overall financial picture of the company. We are very flexible and nimble, as has been referenced on the call.

We know the price break points and when we should slow down and when we should speed up, and so we are paying attention to that every single week, Fai.

Okay. Just really quick, I know you've given that 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 function of the hedge book.

Thank you.

Thank you.

Thank you, operator. Thanks, everyone, for participating.

We look forward to our discussion next quarter. See you then.