Q4 2025 Tourmaline Oil Corp Earnings Call

March 5, 2026

Speaker #2: Following the presentation, we will conduct a question-and-answer session. If at any time during this call you require immediate assistance, please press *0 for the operator.

Speaker #2: This call is being recorded on March 5, 2020. I would now like to turn the conference over to Scott Kirker. Please go ahead. Thank you, operator, and welcome everyone to our discussion of Tourmaline’s financial and operating results for the quarters and years.

Scott Kirker: Thank you, operator. Welcome everyone to our discussion of Tourmaline's financial operating results for the quarters and years ending 31 December 2025 and 31 December 2024. My name is Scott Kirker. 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 Michael 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.

Speaker #2: 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 MDNA available on Cedar and on our website.

Speaker #2: I also draw your attention to the material factors and assumptions in those advisories. I am here with Mike Rose, Tourmaline's president and chief executive officer, Brian Robinson, our chief financial officer, and Jamie Hurd, Tourmaline's vice president of capital markets.

Speaker #2: 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.

Scott Kirker: After his remarks, we will be open for questions. Go ahead, Mike.

Michael Rose: Thanks, Scott, 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 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 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.

Speaker #2: Go ahead, Mike.

Speaker #3: Thanks, Scott, and thanks, everybody. Who dialed in. So we're pleased to announce our Q4, 2025 disclosed year-end reporting and update on 26 activities so far.

Speaker #3: So a few highlights. We had record production in Q4 of '25, and that carried on and set a new record in January. Of this year, we added 829 million BOEs of 2P reserves in '25, including a corporate record single year organic 2P addition of 457 million BOEs.

Speaker #3: We realized continued corporate operating cost reductions in Q4 of '25, down over 9% from the first half of '25 to the current $4.66 per BOE.

Speaker #3: Peace River High asset sale was completed in February 2026 for proceeds of 765 million. And net debt at year-end '25 of 1.5 billion, inclusive of the impact of the Peace River High asset sale, was down from Q3 25 net debt of 2.3 billion and represents 0.5 times forecasted 26 cash flow.

Michael Rose: 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 0.5x 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.

Speaker #3: 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.

Speaker #3: 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.

Speaker #3: 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 netback by approximately $65 million and forecasted 2027 operating netback by approximately $110 million.

Michael Rose: 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.

Speaker #3: And that's through the elimination of deep-cut processing fees as well as C2 plus transportation and fractionation fees. And really, this is all part of the overall cost reduction and margin improvement initiative that's ongoing.

Speaker #3: Looking results, Q4 25 cash flow was 890 million or 229 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.

Speaker #3: 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.

Michael Rose: 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, and that's the phase one build-out. As mentioned, net debt year-end 2025 was CAD 1.5 billion, and that's down from CAD 2.3 billion in Q3 2025. We've set a long-term net debt target of CAD 1.75 billion.

Speaker #3: And although we pioneered the Charlie Lake horizontal play in the first place in '09 and 2010, this disposition allows us to enhance the focus on our two massive natural gas complexes.

Speaker #3: 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.

Speaker #3: And that's the phase one buildout. As mentioned, net debt at 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.

Michael Rose: A few comments on the capital budget. We have updated the multi-year EP plan in the COV, and 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 E-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.

Speaker #3: 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.

Speaker #3: 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.

Speaker #3: 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 base and deep cut volumes will reduce total corporate production by a total of approximately 50,000 BOEs per day on a full-year basis.

Michael Rose: 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.

Speaker #3: Importantly, the 26 full-year EP capex program will be reduced by 350 million to 2.55 billion, along with a 50 million dollar cut in our non-EP capital for a total capex reduction of 400 million.

Speaker #3: 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.

Speaker #3: We believe it's prudent to defer certain gas-focused expenditures until we see a sustained, stronger local price, as both ACO and Station 2 prices in the Western Canadian Sedimentary Basin and the prices in the Pacific Northwest and California are unusually low.

Speaker #3: 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 DNC capital that could be deferred from the 26 EP capital program if commodity prices remain weak.

Michael Rose: We have identified an additional 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 US $0.10 per Mcf that AECO pricing improves, our 2026 cash flow and free cash flow increase by approximately CAD 45 million. Similarly, because we are exposed to these markets, for every $1 per Mcf US that both JKM and TTF improve, 2026 cash flow improves by CAD 50 million and 2027 cash flow by CAD 70 million. Some comments on reserves. Year-end 2025 PDP reserves were 1.47 billion BOEs, and that's up 27%, sorry.

Speaker #3: At strip pricing, Tourmaline's revised EP plan anticipates 2026 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 ACO pricing improves, our 2026 cash flow and free cash flow increase by approximately $45 million.

Speaker #3: 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.

Speaker #3: Some comments on reserves. Year-end '25 PDP reserves were 1.47 billion, BOEs, and that's up 20%. 27%, sorry, total approved reserves of 3.26 billion BOEs were up 20% over 2024.

Michael Rose: Total proved reserves of 3.26 billion BOEs were up 20% over 2024. Our 2P reserves eclipsed the 6 billion BOE mark, 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%.

Speaker #3: And our 2P reserves eclipse the 6 billion BOE mark, and they were up 15% year over year. So, after seventeen 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.

Speaker #3: 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 our historical booking average off the total inventory for the last few years.

Speaker #3: It's always around 15%. Reserve replacement was 356%, which is big for a large company—25 annual production of 233 million BOEs. With the 2P additions of 829 million BOEs.

Michael Rose: 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 book inventory, including the previously booked inventory. 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 bump up the 2P F&D for 25 alone by CAD 321 per BOE.

Speaker #3: The company has elected to increase DNC 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-purse style completions, mostly in the northeast BC Montney.

Speaker #3: We also increased future facility capital in the year-end '25 report. So these one-time increases actually bumped up the 2P F&D for '25 alone by 321 per BOE.

Michael Rose: Looking at some marketing highlights, the company has an average of about 880 million cubic feet per day of nat gas hedge in 2026, and that's at a weighted average fixed price of CAD 4.54 per Mcf. In 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.

Speaker #3: Looking at some marketing highlights, the company has an average of about 880 million cubic feet per day of net gas hedged in '26, and that's at a weighted average fixed price of Canadian 4.54 per MCF.

Speaker #3: 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.

Speaker #3: So that's Dawn, Ventura, Chicago, Iroquois, Emerson, and A&R Southeast. And that provided a strong uplift to our Q1 cash flow. We have entered into a long-term natural gas storage agreement with Altagas at their Dimmsdale storage facility.

Speaker #3: 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.

Michael Rose: Subsequently, AltaGas has announced a positive final investment decision for the phase 2 expansion of that facility. In 2026, we'll have access to 6 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.

Speaker #3: So in '26, we'll have access to six BCF of storage capacity, and that starts in April of this year. And then next year in mid-'27, it increases to 10 BCF, and that's for a 10-year term.

Speaker #3: And we view the acquisition of an additional large storage position as a strategic opportunity to improve financial performance and enhance our operational flexibility in periods of natural gas volatility.

Speaker #3: And it's really just another aspect of our ongoing efforts to fully integrate our natural gas business. Updating the cost reduction and margin improvement activities.

Speaker #3: We did embark upon that initiative in mid-'25, and the focus is on reducing all aspects of the cost equation. And we're excited by the rapid progress that we've made already.

Michael Rose: We're excited by the rapid progress that we've made already. Q4 OpEx was CAD 4.66 a BOE. That was down 3% from Q3 2025, and 9% from H1 2025, when costs were CAD 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 CAD 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 CAD 1.00 per BOE by 2031 to CAD 1.50 per BOE, and approximately CAD 0.70 per BOE have already been achieved since H1 2025.

Speaker #3: So Q4 OPEX was $466 a BOE. That was down 3% from the third quarter in 2025, and 9% from the first half of 2025 when costs were $514 a BOE.

Speaker #3: The Peace River High Complex sale will reduce go forward corporate OPEX by a further 7%. So our 26 OPEX guidance is 450 per BOE.

Speaker #3: With the success of the cost reduction initiatives to date, we are revising our aggregating or aggregate operating and transport cost reduction target that was a dollar per BOE by 2031 to a dollar 50 per BOE and approximately 70 cents per BOE of already been achieved.

Michael Rose: 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. This vertical integration of our sand business is estimated to save a minimum of CAD 40 million per year in capital costs. The ongoing Northeast BC infrastructure build-out will systematically reduce costs 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.

Speaker #3: 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.

Speaker #3: 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.

Speaker #3: 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 dollars per year of aggregate commodity price independent structural cost reductions and that's compared to the first half '25 cost structure.

Speaker #3: And that'll flow through to lower corporate breakevens and our free cash flow margin improvement. On the EP front, in 2025, we drilled 320 gross wells and we led the Canadian industry with a total of 1.7 million meters drilled during the year.

Michael Rose: 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.

Speaker #3: In '25, we delivered our best overall well performance in the past six years in the BC-Montney condensed gas condensate complex, where performance was 22% higher in '25 than the previous five-year average.

Speaker #3: And that's based on the IP90 of 102 wells. And this out performance has been across the full suite of the BC-Montney assets from Aitken Birch Gundy in the north to Ground Birch Dole Manias in the south.

Michael Rose: This 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, and it speaks to the size and scale of this fully de-risked asset base. We continue to increase lateral length, 25 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 26 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.

Speaker #3: And it speaks to the size and scale of this fully de-risked asset base. We continue to increase lateral length—25 Deep Basin in northeast B.C. program.

Speaker #3: Averaging 8,400 completed lateral feet and that's up 1,100 feet over 2024. D and C cost per foot in the deep basin in BC are actually now in decline.

Speaker #3: In 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 Ground Birch Manias gas plant projects in BC.

Michael Rose: Aitken is on schedule for a Q4 2026 completion, Monias completion is expected in Q4 2027. 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 One and Tier Two 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 Global Methane Certification Standard.

Speaker #3: Aitken is on schedule for a Q4 '26 completion. And Manias completion is expected in Q4 of '27. Our ongoing new zone, new pool exploration program has now resulted after approximately five years in 2.55 TCF equivalent of 2P reserve additions.

Speaker #3: And approximately 1,350 tier one and tier two drilling locations. And we've got several high-impact exploration and delineation wells planned in the 26 program. We figure this is by far the largest and most consistent exploration program in the basin.

Speaker #3: 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.

Michael Rose: 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. You can read those at your leisure. On the dividend, our board of directors has declared a quarterly base dividend of CAD 0.50 per share, payable on 31 March 2026 to shareholders of record at the close of business on 16 March 2026.

Speaker #3: 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.

Speaker #3: And the timing of this is significant given the ongoing negotiations on methane. Between the province of Alberta and the federal government. There are several other EP highlights as there always are.

Speaker #3: 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 50 cents per share.

Speaker #3: Payable on March 31, 26 to shareholders of record at the close of business on March 16, 26. And the weak Western Canadian sedimentary basin local gas pricing and unusually low pricing at the PG&E and Malin sales hubs this winter will limit free cash flow and constrain our ability to fund a special dividend in Q1.

Michael Rose: 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.

Speaker #3: Sustained stronger pricing and our ongoing margin improvement activities are expected to lead to further base dividend increases. 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.

Speaker #3: So that's it for the formal remarks and we're here to answer questions.

Operator: 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.

Speaker #1: 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.

Speaker #1: You will hear a prompt if your hand has been raised. Should you wish to decline from the polling process, please press the star key followed by the number two.

Speaker #1: 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 Kaleya.

Speaker #1: From Bank of America, please go ahead.

Kalei Akamine: 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?

Speaker #2: 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.

Speaker #2: With the breakup season kind of around the corner, I imagine that decision would be imminent. What factors would influence your decision? How do you allocate the reduction across the asset base?

Speaker #2: And in the case where there's additional flexibility needed in coming years, should we think about what you've done here as the template for future actions?

Michael Rose: Well, 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 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 wanna keep the two plant projects in BC on schedule. Total facility spending in BC is sort of between CAD 250 and CAD 300 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. And, you know, we are starting to see AECO move upwards from its sort of CAD 1.60 level.

Speaker #3: Yeah, well, cutting the capital budget in '26 is exactly what we did in '25 and '24. But particularly weak local pricing and PG&E pricing—they're both below $2—was the reason for that.

Speaker #3: Yes, we do have flexibility to cut an additional 200 million. Again, it would be focused on D and C because we want to keep the two plant projects in BC on schedule and total facility spending in BC is sort of between 250 and 300 for those particular projects.

Speaker #3: So 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.

Speaker #3: And we are starting to see ACO move upwards from its sort of $1.60 level. And PG&E was constrained—that was usually, that's a huge premium market for us.

Michael Rose: 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 15 March. 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 1 Bcf a day of gas. It certainly hasn't helped gas.

Speaker #3: Usually trades two bucks US above Henry Hub. Now it's a dollar below Henry Hub, which we haven't seen in the nine big winner in our portfolio.

Speaker #3: They had no winter. They had an enormous amount of rain. So lots of excess hydro. And then there's a particular maintenance project at the Grand Coulee Dam where they have to do dry dam maintenance that starts on March 15th.

Speaker #3: So they've been emptying that reservoir all winter, and that's been hammering six gigawatts a day into that local market, which is a bit oversupplied anyway.

Speaker #3: Six gigs is about equivalent to a BCF a day of gas. So it certainly hasn’t helped gas. Now, we expect that price to start improving when the maintenance starts.

Michael Rose: We expect that price to start improving when the maintenance starts, and then, you know, that 6 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 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, you know, it's CAD 45 million for each dime on AECO. You know, if we got to the marvelous price of CAD 2.25, all of a sudden our free capital is over CAD 1 billion. Kind of puts it in context. We have some time. We certainly have some flexibility.

Speaker #3: And then that six gigs is gone for an extended period of time. First of all, they do the maintenance, and then they have to refill.

Speaker #3: So we're positive on our outlook for where PG&E prices are going to go. And ACO and PG&E are directly connected and you can watch them.

Speaker #3: 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 ACO.

Speaker #3: So if we got to the marvelous price of 225, all of a sudden our free cash flow is over a billion dollars. So kind of puts it in context.

Speaker #3: So we have some time. We certainly have some flexibility. The first EP capital cut because of well-out performance doesn't affect the production. If we cut more capital out of the budget, it would affect production.

Michael Rose: The first DP 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.

Kalei Akamine: Thanks, Mike. I also think Costa Azul LNG 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, but wondering if there are any incremental benefits that could be realized.

Speaker #3: So thanks, Kaleya.

Speaker #2: Thanks, Mike. I also think Costa Zoo LNG is starting up sometime in the second half. So that should be supportive to that macro that you're talking about in California.

Speaker #2: The next question is, it’s just on plug and perf. We’ve seen more of the Motney program shifting from ball drop to plug and perf because of the results, I would assume.

Speaker #2: If that is more capital efficient—more resource for fewer 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 I'm wondering if there are any incremental benefits that could be realized.

Michael Rose: 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, 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 completion. Our 2PFND, because we're carrying the booked inventory, would have been CAD 588 a BOE, rather than CAD 908, because we basically recalibrated the entire inventory and eat the capital all in year 1. Sets us up nicely for even lower FND in future years.

Speaker #3: Yeah, I mean, we're up to 75% of the wells in BC on plug and perf. And we continue to evaluate it's particularly advantageous when you're in the more liquid-rich tighter Motoney horizons.

Speaker #3: And so we're certainly using it there. And we did take the entire booked inventory well cost up, primarily because of this evolution to plug-and-perf style completion.

Speaker #3: So our 2PF and 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 ate the capital all in year one.

Speaker #3: So, set this up nicely for even lower F&D and future years. So we're always working on it and figuring out the best recovery, the best deliverability, and the best economic return on the wells.

Michael Rose: 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.

Kalei Akamine: Got it. Thank you, Mike.

Michael Rose: Thank you.

Speaker #2: Got it. Thank you, Mike.

Operator: Your next question comes from Sam Burwell of Jefferies. Please go ahead.

Speaker #3: Thank you.

Speaker #1: Your next question comes from Sam Burwell of Jeffery. Please go ahead.

Sam Burwell: 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 B.C. or spread all over the place? 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?

Speaker #4: Hey, good morning, guys. I wanted to piggyback on Kaleya'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?

Speaker #4: And then how does this impact 2027 beyond? I mean, is there CapEx that could be incremental to the numbers in the EP plan? And if so, is there upside to production or is this sort of timing deferral already baked into those numbers that we're looking at in the EP plan?

Michael Rose: 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, 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.

Speaker #3: The deferrals and cuts were more in the Deep Basin than anywhere else. And one flexibility option we have, of course, is to continue to drill the pads and not frack them, because the stimulation piece is 60% of the cost.

Speaker #3: And so that's essentially what we did in the second half of 2025. We shaped the production growth curve to the improving price curve. And December prices actually were good.

Speaker #3: '25, and we're able to do that very quickly. Deep Basin break-even is about $2 per MCF, and so that's why the majority of the capital deferrals have been there.

Speaker #3: The BC Motoney is a dollar 40 for reference. We can add production into 2027 if we have a much more favorable pricing environment. I mean, right now we're weak locally at ACO and Station 2.

Michael Rose: I mean, 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.

Speaker #3: 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.

Speaker #3: So, we remain very flexible. I think we can pivot faster than anybody with our EP program, and we will.

Sam Burwell: Okay, great. Then next one just on the ethane rejection decision. Is that idiosyncratic to just those particular contracts at certain plants coupled with the desire to cut costs? Is this any wider indication of ethane recovery economics across the basin?

Speaker #4: Okay, great. And 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 cut costs?

Speaker #4: Or is this any wider indication of ethane recovery economics across the basin?

Michael Rose: Yeah. 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. Yeah, 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. You know, generally we make, you know, 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 weak.

Speaker #3: Yeah, the only place we recover ethane was in Alberta. So none of the BC buildout is impacted by that because there isn't an ethane business out there.

Speaker #3: But yeah, 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.

Speaker #3: And generally, we nothing off ethane. And even though it's such an important feedstock in the petrochemical business, the gas in Alberta has so much ethane in it that as soon as the price starts to improve, someone downstream goes and recovers that ethane.

Michael Rose: 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.

Speaker #3: And kind of keeps the market very, very weak. And so those contracts were coming due, and it was an opportunity for us to save costs, and it fits perfectly with this broad initiative we have across the company, which is really working.

Speaker #3: So you're going to get a double win. When our local prices finally improve because we're doing a whole bunch of things to make this business a whole lot better.

Speaker #3: And it's all masked by our very low sub-$2 ACO prices and the connected basin. So when those improve—and they will—you'll get kind of a double win.

Speaker #3: 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.

Sam Burwell: Okay. Got it. Thank you, Mike.

Michael Rose: Thank you, Sam.

Speaker #4: Okay, got it. Thank you, Mike.

Operator: Your next question comes from Neil Mehta of Goldman Sachs. Please go ahead.

Speaker #3: Thank you. Sam.

Speaker #1: Your next question comes from Greta Drefke of Goldman Sachs. Please go ahead.

Neil Mehta: 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?

Speaker #5: 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 ACO pricing environment that would position Tourmaline to return to paying out a special dividend?

Speaker #5: 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?

Michael Rose: 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 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. could propel JKM and TTF prices to a point where free cash flow is well over 1 billion CAD for Tourmaline. We're monitoring that. It's also affecting our AFEI pricing at propane.

Speaker #3: So we are always available and willing to sweep additional free cash to the shareholders, and our preferred method has been the special dividend. Prices are changing quickly.

Speaker #3: And our cash flows can change quickly too. Just with the TTF and JKM move that we've seen in the last couple of days alone, that's added several hundred million dollars to our forward outlook of free cash flow.

Speaker #3: And we see that as not yet settled. It's still transpiring. And if LNG out of that region, the Middle East, is constrained for more than a month, we see a pretty dramatic change in global S&D.

Speaker #3: They would could

Speaker #1: It propel GM and ETF prices to a point where free cash flow is well over $1 billion for Tourmaline Oil . So we're monitoring that .

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

Speaker #1: It's also affecting our FE pricing at propane. That's up quite a bit relative to where it was last week for our forward outlook.

Speaker #1: It's also adding to our free cash flow outlook. And as we march through the year, we'll continue to monitor our forward free cash flow profile.

Speaker #1: And if there's ample free cash flow over and above the base dividend , we will return it

Neil Mehta: Great. Thank you. That's very helpful. 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?

Speaker #2: Great . Thank you . That's very helpful . And then for my second question , I just wanted to ask a little bit more on the power demand outlook for the basin .

Speaker #2: Can you speak a little bit about your latest conversations with regulatory entities, hyperscalers, or other parties on the potential for power demand?

Speaker #2: Build out relating to data center demand in Western Canada ? Have you seen timelines or just broader conversations progressing as expected ? And have these discussions been of the scale or magnitude that would encourage you to participate in a potential project

Michael Rose: 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. 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.

Speaker #1: We've been we're a year into a process exploring the possibility of Cold Lake locating near one of our natural gas plants . We think Alberta has all kinds of advantages .

Speaker #1: 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 .

Speaker #1: If you like . You know , we will know what we're going to do specifically this year . And in 2026 . But we're excited about what's happening in Alberta altogether .

Speaker #1: 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 .

Speaker #1: 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 .

Michael Rose: 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 B and a half a day of gas consumption inside the basin. That would be ahead of LNG Canada phase two, so that would be very good timing for the S&D dynamics in our basin. Anything you wanna add, Jamie?

Speaker #1: You know, we kind of see it as a minimum B and a half a day of gas consumption inside the basin.

Speaker #1: And that would be ahead of LNG Canada Phase Two. So that would be very good timing for the S&D dynamics in our basin.

Jamie Heard: I would say, Neil Mehta, 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 masked 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.

Speaker #1: Anything you want to add , Jamie ?

Speaker #3: 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 .

Speaker #3: Alberta is still in that phase . The second phase was , you know , reigniting brownfield assets or mothballed assets . And this third phase has been brand new greenfield development with behind the fence power generation matched with a data center .

Speaker #3: And those assets have moved north and west . We've seen far more announcements of behind the meter data centers west of the Great Lakes into the Dakotas and the Montana , and those are assets that can access with gas .

Jamie Heard: 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.

Speaker #3: And it will also tighten the markets that already accesses , whether it be on northern border or into the Great Lakes region , or even into the market .

Speaker #3: And so as we see these build outs , we're excited for the opportunity to participate in the province of Alberta , whether it be our 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 .

Speaker #3: But we also think that Tourmaline Oil gas in the western part of the northwest of United States is going to have preferential access to the vast build out that's already occurring into basins that , frankly , have a declining local supply environment .

Jamie Heard: It's both a local and a broad strategy at Tourmaline. 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.

Speaker #3: So it's both a local and abroad strategy. At Tourmaline Oil, we see probably the next year being a pretty critical year to see all these things frame up.

Speaker #3: FID and put real dollars to work in consumption that we're going to enjoy . 27 , 28 and beyond

Neil Mehta: Great. Thank you very much.

Operator: Your next question comes from Aaron Bilkoski of TD Cowen. Please go ahead.

Speaker #2: Great. Thank you very much.

Speaker #4: Your next question comes from Aaron Binkowski of TD Cowan . Please go ahead .

[Analyst] (TD Cowen): Good morning, guys. You've been pretty nimble with the shorter cycle E&P capital cuts, but I'd be curious to know if there's a scenario where you would lower the longer-term growth trajectory through 2031.

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

Speaker #5: Good morning, guys. You've been nimble with the shorter cycle and E&P capital cuts, but I'd be curious to know if there's a scenario where you would lower the longer-term growth trajectory through 2031.

Michael Rose: Well, I think we wanna keep the first two plants in the Montney build-out on schedule. As I mentioned, 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.

Speaker #1: Well I think we want to keep the first two plants in the build out on schedule . So as I mentioned . So that would be Aiken and Groundbirch .

Speaker #1: If you know , gas prices don't recover . And they're , you know , lower than what any of us are actually expecting .

Speaker #1: You know , getting towards the end of the decade , we have flexibility around the timing of the phase two of the BC Montney build out .

Speaker #1: I mean , we can take a year off if we need to , and build significant free cash flow . And that particular annum .

Speaker #1: So we're just going to see how it plays out . But as you mentioned , we are nimble and can pivot quickly

[Analyst] (TD Cowen): Perfect. Thanks, Mike.

Aaron Bilkoski: Perfect. Thanks, Mike.

Michael Rose: Thanks, Aaron.

Operator: Your next question comes from Josh Silverstein of UBS. Please go ahead.

Speaker #5: Perfect. Thanks, Mike.

Speaker #1: Thanks , Eric

Speaker #4: Your next question comes from Josh Silverstein of UBS . Please go ahead

Operator: Yeah, thanks. Good morning, guys. I wanted to touch on the LNG exposure that you have, given the capacity and contract signed, and to, you know, 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, you know, $5 to $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.

Josh Silverstein: Yeah, thanks. Good morning, guys. I wanted to touch on the LNG exposure that you have, given the capacity and contract signed, and to, you know, 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, you know, $5 to $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.

Speaker #6: Yeah . Thanks . Good morning guys . I wanted to touch on the LNG exposure that you have given the capacity and contract signed and , you know , understand some potential upside exposure .

Speaker #6: It looks like you're assuming kind of 12 to $13 Jkm versus 375 for dollars . Henry hub . I'm guessing there's probably kind of an all in cost of maybe , you know , 5 to $6 to get that that jkm price .

Speaker #6: So can you just talk about some of the sensitivity around that ? If , you know , we remain at kind of this ten , $12 spread , just maybe how much upside there is ?

Jamie Heard: 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 02 March. 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.

Speaker #6: Thanks , Josh .

Speaker #3: It's Jamie speaking . So 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 price move incorporated within it .

Speaker #3: We have today over 200,000,000 cubic feet a day of LNG capacity that extends towards 330,000,000 cubic feet a day over the next several years. The details are in the deck.

Speaker #3: We've only hedged roughly a quarter of that. That's also in the hedge disclosure available in our financials and on our website. We have taken steps to lock in some of the spike that we've seen, but we're totally aware that a long-term outage, specifically of the LNG plant, would rapidly reshape the dynamics on the water.

Jamie Heard: 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 the Qatar LNG plant, would rapidly reshape the S&D dynamics on the water, and 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 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.

Speaker #3: And we are available for that upside, especially, you know, in the months ahead and into '27 as our portfolio also expands into these markets.

Speaker #3: So the sensitivity is a dollar change in JKM or TTF together. It's roughly $50 million of free cash flow this year and $70 million next year.

Speaker #3: And we've seen these, obviously, these markets go $30s, $40s on supply disruptions before. So we're aware that it's a very high convex market.

Speaker #3: And it could end up being a windfall. And we're widely open to it.

Operator: Thanks. Just to understand, that's a dollar move higher relative to what it was trading at? That's a spread change?

Josh Silverstein: Thanks. Just to understand, that's a dollar move higher relative to what it was trading at? That's a spread change?

Speaker #6: Thanks . And just to understand that's a dollar move higher relative to what it was trading at . Or that's that's a spread change .

Jamie Heard: 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 going to get into the slopes and the deductions, et cetera. Those are all confidential in contracts. Your characterization of roughly $4 to sometimes $5 less is a fair estimate, inclusive of our transfer cost to the Gulf.

Speaker #3: It's just a sensitivity. So I'm talking about, yeah, holding hub flat. If JC and ETF move a dollar, that's your sensitivity.

Speaker #3: So, it's a sensitivity of just the floating market. You know, we're not going to get into the slopes and the deductions, etc.

Speaker #3: Those are all confidential and contracts. But your characterization of roughly four to sometimes five dollars less is a fair estimate, inclusive of our transport costs to the Gulf.

Operator: Got it. That's helpful. Just on cash allocation, I know you're 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, or do you actually wanna stay around kind of the CAD 1 billion number, maybe kind of use the balance sheet if natural gas prices move lower? Thanks.

Josh Silverstein: Got it. That's helpful. Just on cash allocation, I know you're 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, or do you actually wanna stay around kind of the CAD 1 billion number, maybe kind of use the balance sheet if natural gas prices move lower? Thanks.

Speaker #6: Got it . That's helpful . And then just on on cash allocation , you know , your $1.5 billion at the end of the year , you're taking $500 million down from that .

Speaker #6: You're at $1 billion . You're well below the $1.7 billion target . Is the idea to sometime this year , maybe use some way .

Speaker #6: If it's not going to special dividends , could you use it for acquisitions ? Some additional storage , you know , 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 .

Jamie Heard: Hey, Josh, I just wanna 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.

Speaker #6: Thanks .

Speaker #3: Hey , Josh , I just want to add a quick clarification in our financials because the arch available for sale , our net debt includes the proceeds .

Speaker #3: So, the $1.5 billion is after receiving the effective consideration of the Arch. And maybe I'll let Mike talk about our M&A outlook.

Michael Rose: 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 we'll continue with that approach. M&A is not a big piece of the equation right now.

Speaker #1: 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 .

Speaker #1: So we're not looking at anything large at the current time . And you know , persistence and patience are the key to pricing assets out of large companies .

Speaker #1: And so we'll continue with that approach . But M&A is not a big piece of the equation right now .

Operator: Yeah. Yep. Thanks for the clarification. Thanks.

Josh Silverstein: Yeah. Yep. Thanks for the clarification. Thanks.

Michael Rose: Thank you.

Speaker #6: Okay. Thanks for the clarification. Thanks.

Operator: Your next call comes from Jamie Kubek of CIBC. Please go ahead.

Speaker #1: Thank you

Jamie Kubek: 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.

Speaker #4: Your next call comes from Jamie Kubik of CIBC. Please go ahead.

Speaker #7: Yep. Thanks for taking my question. Just with respect to forward pricing, ECO and Station 2 aren't really sustainably above three bucks a GJ until 2028.

Speaker #7: Should we think about the potential for shut-ins through the summer from Tourmaline Oil? And I guess, when do you expect that forward pricing turns for the better here?

Michael Rose: Yeah. If the price gets low enough, and 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. 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.

Speaker #7: Thanks .

Speaker #1: Yeah , if the price gets low enough and we've we've shut in before . We're actually of course , we're always thinking the price is going to go up , but we are quite constructive .

Speaker #1: 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 .

Speaker #1: But number in 2027 , summer triples . And that becomes a meaningful volume . And we can , you know , be very nimble about when we inject and when we withdraw .

Speaker #1: It's a very high deliverability reservoir. And again, we know quite a bit about it from previous employment. It's actually something I worked on at Shell many decades ago, when it actually had producible gas in it.

Michael Rose: 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. It is putting a cap on AECO because it is so weak. We need to get that 3 Bcf a day out the West Gate and the other Bcf that comes down through the West Coast 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.

Speaker #1: So it's kind of fun that way . You know , just some comments on , you know , LNG Canada and its on and gosh , you know , the price is two bucks or less .

Speaker #1: What's going on: part of it is that California equation that we talked about already. And it is putting a cap on ARCO because it is so weak, and we need to get that 3 B's a day out.

Speaker #1: The west gate and the other B that comes down through the west coast system into the Pacific Northwest to clear up . And , you know , we see the PG and E prices will start to help with that .

Speaker #1: And there's an order of fill with the LNG Canada facility . So the first train , most of the fill came from the direct connect .

Michael Rose: It was, as you brought train 2 on, the first volumes for that, we're off the Enbridge system, so that meter station is Sunset West. The last station to get gas, which is the one that affects AECO in the NGTL system, is Willow, and it's had really strong volumes over the last 3 or 4 weeks. You know, AECO, NGTL, get the positive impact last. Storage, if you look at it, will, you know, 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 gonna end up, you know, well into the 200s of withdrawal. That's positive.

Speaker #1: So, a couple of the large operators have, and then it was as you brought Train 2 on, the first volumes for that were off the Enbridge system.

Speaker #1: So that meter station is Sunset West . And so the last station to get gas , which is the one that affects Arco in the Ngtl system , is Willow , and it's had really strong volumes over the last 3 or 4 weeks .

Speaker #1: And so , you know , ACO ngtl get the positive impact last . And storage , if you look at it , will , you know , in about seven days based on the weather , will eclipse the , the storage withdrawal that we had in all of last year's winter .

Michael Rose: 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?

Speaker #1: So we're going to end up , you know , well into the two hundreds of of withdrawal . That's positive . And when we think you'll start seeing it set up is when they'll be really tepid injections in April and May , when you actually have reasonably warm weather .

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

Speaker #1: And we think that's what starts to move . The ACO and station two prices up . Anything else you guys want to add ?

Speaker #3: 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.

Speaker #3: The the numbers we see would be , well shy of 1,000,000,000 cubic feet a day . Exit over exit was actually down . You know , February was much milder .

Speaker #3: So we didn't have freeze-off this year, but we still average, call it 0.6, 0.7. And then that's thinning to, call it, 0.4, 0.5.

Speaker #3: Today as we see supply . So the local SD is good . It's you can't have ACO too strong because you need to be able to clear transport economics into our main export .

Speaker #3: Hub of northwest and PGE . And so as that market strengthens ACO can strengthen . There's no long term glut issue locally . It is this idiosyncratic demand issue .

Jamie Heard: 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.

Jamie Kubek: 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?

Speaker #3: We've had with just a very bizarre winter , which was very East focused and not very less focused .

Speaker #7: Okay . Thanks for all the color there . Could you maybe talk a little bit about , you know , the potential for , for turnarounds in Q2 or Q3 with respect to tourmaline or even perhaps more broadly , and how that could possibly help the situation ?

Michael Rose: Well, we kinda 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.

Speaker #1: Well , we kind of schedule our turnarounds or try to to when the scheduled T.C. and Enbridge turnarounds are happening . So , you know , it's about the same as last year .

Speaker #1: I think the scheduled pipeline turnarounds from the big streamers is a little bit less for '26 versus 2020. Five, particularly on the GTN system, which impacts US.

Jamie Kubek: Okay, thanks. That's all for me. I'll turn it back.

Michael Rose: Yeah, thanks, Jamie.

Operator: As a reminder, if you wish to ask a question, please press star 1. Your next question comes from Fai Lee of Odlum Brown. Please go ahead.

Speaker #7: Okay, thanks. That's all for me. I'll turn it back.

Speaker #1: Yeah . Thanks , Jamie

Speaker #4: As a reminder, if you wish to ask a question, please press star one. Your next question comes from Fei Li of Odlum Brown.

Fai Lee: 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 $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, like, demand, if that improves, that you see it moving up closer to that? Or what's your confidence interval around the $4 outlook for 2028 and beyond?

Speaker #4: Please go ahead .

Speaker #8: Thank you . Hi , Mike . I'm just trying to get my head wrapped around your five year plan , and the ACO pricing assumptions .

Speaker #8: Given the futures script for ACO seems to be closer to the 250 , which is what we're seeing in 2027 . Just trying to understand how I can reconcile that with the $4 that you have for 2028 , and is that something related to the PGE , like demand , if that improves that , you see , moving up closer to that or what's your confidence interval around the the $4 outlook for 2020 and beyond ?

Jamie Heard: Hi, Fai, this is Jamie speaking. The first 2 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 to 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 US, 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 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 US.

Speaker #3: Hi , this is Jamie speaking . So the first two years , as you mentioned , are on script . And we just honor the strip that's offered on the day .

Speaker #3: 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.

Speaker #3: So in our perspective, $65 WTI feels mid-cycle, $4 Henry Hub. Given the dynamics we see at play in the United States, where basins are starting to have performance degradation, feels like a new normal for a mid-cycle price.

Speaker #3: We are aware there will be volatility on either side of that , and in a $4 hub environment , we believe ACO should price at transport economics and transport economics would imply a basis of roughly $1 US in the current foreign exchange environment , $1 US basis is effectively offset by the FX , so $4 Canadian would be your implied ACO price .

Jamie Heard: In the current foreign exchange environment, a dollar US basis is effectively offset by the FX. CAD 4 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.

Speaker #3: So this is, from our perspective, a midcycle look at Tourmaline Oil cash flows. The reason why we felt flat deck was a good illustration.

Speaker #3: Here is the margin improvement of the business, as better borne out. You can see the margin improve on an atom to annum basis as we grow this business in BC, which is our most profitable rock.

Speaker #3: If you were to run strip every day, the contango turning to backwardation was always masking that which was hiding. This margin improvement.

Jamie Heard: We thought the flat deck was a better way to illustrate how the profitability of the business was getting better in the out years.

Speaker #3: That's inherent in the asset base. Even though, you know, year to year you'll definitely see it come through in the financials.

Speaker #3: So, we thought the flat deck was a better way to illustrate how the profitability of the business was getting better.

Fai Lee: 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 does... How are you know, setting up your five-year plan if the outlook isn't really CAD 4.00? 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?

Speaker #1: In the out years .

Speaker #3: In the out years .

Speaker #8: Yeah, I understand the rationale, and I don't have an issue with what you just said. I'm just trying to understand if the reality turns out to be closer to the future.

Speaker #8: Strip , which is closer to call it 250 to 55 , does that change your marketing strategy or your , you know , a lot of times , talk about capital plans .

Speaker #8: I guess , as well . But how does how are you ? You know , set up your five year plan ? Well , if the outlook isn't really $4 and , you know , I guess we do consider like in 2027 and beyond , you're increasing your ACO exposure .

Michael Rose: 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 3 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 break points and when we should slow down and when we should speed up.

Speaker #8: Would that change if it's closer to the 250? In reality, yeah.

Speaker #1: Everything would change . So 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 .

Speaker #1: So that's addressing the capital side of the equation . We are the most diversified producer in North America . So right now it's about 1.3 bees a day of our three BCF a day is exported .

Speaker #1: And usually we win on those markets. So this winter, we did not win on California. So, you know, we'll continue to look for diversification opportunities which help the overall financial picture of the company.

Speaker #1: But we are very flexible and nimble , as has been , referenced on the call . And we know the the price break points .

Michael Rose: We are paying attention to that every single week, Fai.

Speaker #1: And when we should slow down, and when we should speed up. And so we are paying attention to that every single week by

Fai Lee: Okay. Just, like, really quick. 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?

Speaker #8: Okay . And just really quick is that I know you've given the sensitivity for 2026 for ACO , but you haven't for 2027 .

Jamie Heard: It would be slightly larger. Call it 25% larger in 2027. That's mostly a flexibility of hedge book.

Speaker #8: Is that just because? Is that nimbleness, and things can change? Is that why?

Speaker #3: It would be slightly larger ? Call it 25% larger in 27 . And that's mostly a flexibility of hedge book . Okay .

Fai Lee: Okay. Thank you.

Michael Rose: Thank you.

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

Speaker #8: Thank you .

Speaker #3: Thank you

Speaker #4: There are no further questions at this time. I will now turn the call back over to Scott Kircher. Please continue.

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

Speaker #9: Thank you . Operator . Thanks , everyone for participating . We look forward to our discussion of next quarter . See you then

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

Q4 2025 Tourmaline Oil Corp Earnings Call

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