Good morning, ladies and gentlemen, welcome to the Tourmaline Q4 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 0 for the operator. This call is being recorded on March fifth, 2026. I would now like to turn the conference over to Scott Kirker. Please go ahead. Thank you, operator. Welcome everyone to our discussion of Tourmaline's financial operating results for the quarters and years end 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 2026 activities so far. A few highlights. We had record production in Q4 of 2025, and that carried on and set a new record in January of this year. We added 829 million BOEs of 2P reserves in 2025, including a corporate record single year organic 2P addition of 457 million BOEs. We realized continued corporate operating cost reductions in Q4 of 2025, down over 9% from the first half of 2025, to current CAD 4.66 per BOE. Peace River High asset sale was completed in February 2026 for proceeds of CAD 765 million. Net debt at year-end 2025 of CAD 1.5 billion, inclusive of the impact of the Peace River High asset sale, was down from Q3 2025 net debt of CAD 2.3 billion and represents 0.5 times forecasted 2026 cash flow. On production, in addition to record Q4 production, our Q4 2025 average liquids production was a record 152,673 barrels per day. January 2026 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 2026 operating net back by approximately CAD 65 million and forecasted 2027 operating net back by approximately CAD 110 million. That's through the elimination of deep-cut processing fees as well as C2 plus 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 2025 cash flow was CAD 890 million or CAD 2.29 per fully diluted share, full year 2025 cash flow was CAD 3.4 billion. As mentioned, we've sold the Peace River High complex to a Canadian senior producer for cash proceeds of CAD 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 2009 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, CAD 500 million for permanent long-term debt reduction and the remaining CAD 265 million to fund in part the BC infrastructure build-out, split between the next two years, the phase one build-out. As mentioned, net debt year-end 2025 was CAD 1.5 billion, down from CAD 2.3 billion in Q3 2025. We've set a long-term net debt target of CAD 1.75 billion. A few comments on the capital budget. We have updated the multi-year EP plan and the COV. It's been updated for results in 2025, 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. That's exactly what we're doing. Q4 2025 EP CapEx was CAD 813 million. 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 2026 full year EP CapEx program will be reduced by CAD 350 million to CAD 2.55 billion, along with a CAD 50 million cut in our non-EP capital for a total CapEx reduction of CAD 400 million. This reduction includes the CAD 175 million of originally planned CapEx on the Peace River High Complex and a further CAD 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 2026 production guidance given much stronger than anticipated 2026 well performance to date. We have identified an additional CAD 200 million of D&C capital that could be deferred from the 2026 EP capital program if commodity prices remain weak. At strip pricing, Tourmaline's revised EP plan anticipates 2026 cash flow of CAD 3.4 billion and free cash flow of a little over CAD 0.7 billion. All else equal, for every $0.10 per Mcf that AECO pricing improves, our 2026 cash flow and free cash flow increase by approximately $45 million. Similarly, because we are exposed to these markets for every $1 per Mcf that both JKM and TTF improve, 2026 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 six 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. At year-end 2025, 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 off 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 2025 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 book 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 2025 report. These one-time increases actually bump up the 2P F&D for 2025 alone by CAD 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 2026, and that's at a weighted average fixed price of CAD 4.54 per Mcf. In the Q1, 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 II expansion of that facility. In 2026, we'll have access to six Bcf of storage capacity, and that starts in April of this year. Next year, in mid-2027, 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-2025, 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 Q3 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 2026 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 $1 per BOE by 2031 to $1.50 per BOE. Approximately 70 cents per BOE have already been achieved since the first half of 2025. 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 2026. 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 CAD 500 million per year of aggregate commodity price, independent structural cost reductions, and that's compared to the first half 2025 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 2025, we delivered our best overall well performance in the past six years in the BC Montney gas condensate complex. We're 22% higher in 2025 than the previous five year average, and that's based on the IP90 of 102 wells. This outper-performance has been across the full suite of the BC Montney assets from Aitken, Birch, Gundy in the north, to Groundbirch, Doe, Monias in the south. It speaks to the size and scale of this fully de-risked asset base. We continue to increase lateral length, 2025 Deep Basin in 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 in BC are actually now in decline, and the stats are quoted there. The 2026 EP capital budget reduction that we've announced, the CAD 175 million, will not impact the original start-up of timing of the Aitken and the Groundbirch-Monias gas plant projects in BC. Aitken is on schedule for a Q4 2026 completion, and Monias completion is expected in Q4 2027. Our ongoing new zone, new pool exploration program has now resulted after approximately five 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 2026 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 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. 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-based dividend of CAD 0.50 per share, payable on March 31, 2026 to shareholders of record at the close of business on March 16, 2026. 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. Thank you. Ladies and gentlemen, we will now begin the question and answer session. Should you have a question, please press the star key 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 key followed by the number two. If you are using a speakerphone, please lift the handset before pressing any keys. One moment please while we assemble the queue. Your first question comes from Kalei Akamine from Bank of America. Please go ahead. 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 CAD 200 million of additional capital out of the 2026 budget. With the breakup 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? Well, cutting the capital budget in 2026, sorry, is exactly what we did in 2025 and 2024. Particularly weak local pricing and PG&E pricing, they're both below CAD 2, was the reason for that. Yes, we do have flexibility to cut an additional CAD 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 CAD 250 million and CAD 300 million for those particular projects. We do have quite a bit of flexibility. You mentioned breakup. It gives us a bit of time, so probably two to three months to watch where prices go. You know, we are starting to see AECO move upwards from its sort of CAD 1.60 level. PG&E was constrained. Usually, that's a huge premium market for us. Usually trades $2 US above Henry Hub. You know, now it's $1 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, so lots of excess hydro. There's a particular maintenance project at the Grand Coulee Dam, where they have to do dry dam maintenance that starts on March 15. They've been emptying that reservoir all winter, and that's been hammering 6 GW a day into that local market, which is a bit oversupplied anyway. Six gigs is about equivalent of a BCF a day of gas. It certainly hasn't helped gas. We expect that price to start improving, when the maintenance starts, and then, you know, that six gigs is gone for an extended period of time. First of all, they do the maintenance, and then they have to refill. You know, we're positive on our outlook for where PG&E prices are gonna 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 gonna head up. I did mention that, you know, it's CAD 45 million for each $0.10 on AECO, you know, if we got to the marvelous price of CAD 2.25, all of a sudden our free cash flow is over CAD 1 billion. Kind of puts it in context. We have some time. We certainly have some flexibility. The first DP capital cut, because of well low performance 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 LNG Canada is starting up sometime in the second half, 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, wondering if there are any incremental benefits that could be realized. Yeah, I mean, we're up to 75% of the wells in BC on plug-and-perf. You know, we continue to evaluate. It's particularly advantageous when you're in the more liquid-rich, tighter, Montney horizons, 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 completion. Our 2P F&D, because we're carrying the booked inventory, would have been CAD 5.88 a BOE, rather than the CAD 9.08, because we basically recalibrated the entire inventory and 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, you know, the best recovery, the best deliverability, and the best economic return on the wells. Got it. Thank you, Mike. Thank you. Your next question comes from Sam Burwell of Jefferies. Please go ahead. Hey, good morning, guys. Wanted to piggyback on Kalei'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? Then how does this impact 2027 beyond? I mean, is there CapEx that could be incremental to the numbers in the EP plan? 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. You know, one flexibility option we have, of course, is to continue to drill the pads and not frack them because the stimulation piece is 60% of the cost. You know, 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 2025, and we're able to do that very quickly. Deep Basin breakeven is about CAD 2 an Mcf, and so that's why the majority of the capital deferrals have been there. The BC Montney is CAD 1.40 for reference. You know, 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. We remain very flexible. I think we can pivot faster than anybody with our EP program and we will. Okay, great. 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? The only place we recover ethane was in Alberta, so none of the BC build-out is impacted by that because, you know, 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. And you know, generally we make, you know, 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. It fits perfectly with this, you know, broad initiative we have across the company, which is really working. You're gonna 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 CAD 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. Okay. Got it. Thank you, Mike. Thank you, Sam. Your next question comes from Greta Drefke of Goldman Sachs. Please go ahead. Good morning, all. 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 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? We are always available and willing to sweep additional free cash flow to shareholders, and our preferred method has been the special dividend. You know, prices are changing quickly and our cash flows can change quickly too. You know, just with the TTF and JKM move that we've seen over the last couple of days alone, that's added several hundred million CAD to our forward outlook of free cash flow. We see that as not yet settled. It's still transpiring. 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. They could propel JKM and TTF prices to a point where free cash flow is well over CAD 1 billion for Tourmaline. We're monitoring that. It's also affecting our FPI pricing of 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. 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. 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 build-out 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 of a hyperscaler wanted a full, green solution, if you like. You know, we will know what we're gonna 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, you know, very good for the basin and the market's understanding that this can be a big growth opportunity for Alberta. You know, by 2030, just adding up some of the behind the fence opportunities and the two on-grid projects, you know, we kinda see it as a minimum 1.5 Bcf a day of gas consumption inside the basin. That would be ahead of LNG Canada phase II. That would be very good timing for the S&D dynamics in our basin. Anything you wanna add, Jamie? I would say, Greta, you know, these dynamics extend just beyond the Alberta border as well into areas Tourmaline can easily reach with gas. You know, 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, you know, 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 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. As we see these build outs, 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 the United States is gonna have preferential access to the vast build out 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 gonna enjoy 2027, 2028 and beyond. Great. Thank you very much. Your next question comes from Aaron Bilkoski of TD Cowen. Please go ahead. Good morning, guys. You've been pretty nimble with the shorter cycle E&P capital cuts. 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 wanna keep the first two plants in the Montney build out on schedule. As I mentioned, so that would be Aitken and Groundbirch-Monias. If, you know, gas prices don't recover and they're, you know, lower than what any of us are actually expecting, you know, getting towards the end of the decade, you know, we have flexibility around the timing of the phase two 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. We're just gonna see how it plays out. As you mentioned, we are nimble and can pivot quickly. Perfect. Thanks. Bye. Thanks, Aaron. Your next question comes from Josh Silverstein of UBS. Please go ahead. Yeah, thanks. Good morning, guys. I wanted to touch on the LNG exposure that you have given the capacity and contracts signed and to, you know, understand some potential upside exposure. It looks like you're assuming kind of $12-$13 JKM versus $3.75-$4 Henry Hub. I'm guessing there's probably kind of an all in cost of maybe, you know, $5-$6 to get that JKM price. Can you just talk around some of the sensitivity around that if, you know, 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 2026 and 2027 in the five year plan on March 2nd. 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 out of the Qatar LNG plant, would rapidly reshape the S&D dynamics on the water. We are available for that upside, especially, you know, in the months ahead and into 2027 as our portfolio also expands into these markets. The sensitivity is a CAD dollar change in JKM or TTF together is roughly CAD 50 million of free cash flow this year and CAD 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 CAD 1 move higher relative to what it was trading at or that's a, that's a spread change? It's just a sensitivity. I'm talking about, yeah, holding Hub flat. If JKM and TTF move $1, that's your sensitivity. It's a sensitivity of just the floating market. You know, we're not gonna get into the slopes and the deductions, et cetera. Those are all confidential in contracts. Your characterization of roughly $4-$5 less is a fair estimate, inclusive of our transfer cost to the Gulf. Got it. That's helpful. Just on cash allocation. In a year, CAD 1.5 billion at the end of the year, you're taking CAD 500 million down from that. You're at CAD 1 billion. You're well below the CAD 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, you know, storage, you know, opportunities? Do you actually want to stay around kind of the CAD 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 CAD 1.5 billion is after receiving the effective consideration of the Arch. Maybe I'll let Mike talk about our M&A outlook. Yeah. I mean, right now, the M&A is focused on, you know, 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. You know, 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. Yeah. Yeah. Thanks for the clarification. Thanks. Thank you. Your next call comes from Jamie Kubik of CIBC. Please go ahead. Yep. Thanks for taking my question. Just, with respect to forward pricing, AECO and Station 2 aren't really sustainably above CAD 3 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. Yeah. If the price gets low enough, we've shut in before, of course, we're always thinking the price is gonna go up, we are quite constructive and Jamie and I can talk to that. Our storage position, you know, starts to factor into that summer equation. We can inject, I think, 67 million a day this summer, that number in 2027 summer triples, and that becomes a meaningful volume. We can, you know, be very nimble about when we inject and when we withdraw. It's a very high deliverability reservoir. And 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. you know, just some comments on, you know, LNG Canada, and it's on, and gosh, you know, the price is CAD 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 three Bcf a day out the West gate and the other Bcf that comes down through the Westcoast system into the Pacific Northwest to clear. you know, 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. 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, and it's had really strong volumes over the last three or four weeks. You know, AECO, NGTL get the positive impact last. Storage, if you look at it, will, you know, in about seven days, based on the weather, will eclipse the storage withdrawal that we had in all of last year's winter. We're gonna end up, you know, 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, you know, reasonably warm weather. We think that's what starts to move the AECO and Station 2 prices up. Anything else you guys wanna 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 one billion cubic feet a day. Exit over exit was actually down. You know, February was much milder, so we didn't have freeze-offs this year. 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 F&D is good. It's, you can't have AECO too strong because you need to be able to clear transport ex-economics into our main export, you know, 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 we've had with just a very bizarre winter, which was very east-focused and not very west-focused. Okay. Thanks for all the color there. Could you maybe talk a little bit about, you know, 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 when the scheduled TC and Enbridge turnarounds are happening. You know, it's about the same as last year. I think the scheduled pipeline turnarounds from the big midstreamers is a little bit less for 2026 versus 2025, particularly on the GTN system, which impacts us. Okay, thanks. That's all for me. I'll turn it back. Yeah. Thanks, Jamie. As a reminder, if you wish to ask a question, please press star one. Your next question comes from Fai Lee of Odlum Brown. Please go ahead. Thank you. Hi, Mike. I'm 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 CAD 2.50, which is what we're seeing in 2027. Just trying to understand how I can reconcile that with the CAD 4.00 that you have for 2028. Is that something related to the PG&E like demand, if that improved, that you see it moving up closer to that? Or what's your confidence interval around the CAD 4.00 outlook for 2020 and beyond? Hi, this is Jamie speaking. The first two years, as you mentioned, are on strip, and we just honor the strip that's offered on the day. We are totally aware that markets will disconnect the upside and the downside in any given year. 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 will be volatility on either side of that. In a $4 hub environment, we believe AECO should price at transport economics, and transport economics would imply a basis of roughly $1 U.S. In the current foreign exchange environment, a dollar U.S. basis is effectively offset by the FX. Four CAD 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, you know, 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. Yeah, 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 CAD 2.50, CAD 2.55, does that change your marketing strategy or your, you know, a lot of times when you talk about capital plans, I guess, as well. How are you know, setting up your five-year plan if the outlook isn't really CAD 4.00 and, you know, 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 CAD 2.50 in reality? Yeah, everything would change. I did reference that, you know, when Aaron asked his question. I mean, we can slow down on the North Montney phase two build-out in BC. 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 Bcf a day of our three Bcf a day is exported. Usually we win on those markets, although this winter we did not win on California. You know, 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, you know, referenced on the call, and we know the price breakpoints and when we should slow down and when we should speed up. We are paying attention to that every single week, Fai Lee. Okay. Just, like, 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 2027, that's mostly a flexibility of hedge book. Okay. Thank you. Thank you. 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.