Thank you, Operator, and welcome everyone to our discussion of Tourmaline's financial and operating results as at March 31, 2026, and for the three months ended March 31, 2026 and '25. My name is Scott Kirker, and I am the Chief Legal Officer here at Tourmaline Oil Corp.

Before we get started, I refer you to the advisories on forward-looking statements contained in the news release, as well as the advisories contained in Tourmaline's 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'll start with Mike speaking to some of the highlights of the last quarter and the full 2025 year.

After his remarks, we will be opening for questions. Mike, go ahead.

Thanks, Scott. Thanks everybody for dialing in, and we're pleased to review our Q1 '26 results and provide an update on our broad range of activities.

The company achieved record production in the first quarter, generated very strong earnings, and our cash flow and free cash flow forecasts for '26 and '27 are steadily moving up. Some select highlights: continued new well outperformance in both gas complexes leading to production at the midpoint of guidance despite significant Q1 capital deferrals; the first two major facility projects in the Northeast BC infrastructure buildout, those being Aitken and Groundbirch, remain on schedule; due to strong global liquids prices and our access to Pacific propane exports, our '26 NGL realizations are anticipated to increase by approximately 30% over 2025; Q1 '26 cash flow was $862 million, and that generated $202 million of free cash flow for the quarter; our Q1 '26 net earnings were a very strong $658 million; we have steadily improving '26 and '27 full-year free cash flow outlooks; and net debt at March 31, '26 was $1.5 billion, which is below the long-term debt target of $1.75 billion, and is approximately 0.4 times net debt to cash flow.

Looking briefly at production, first quarter '26 average production was 666,089 BOEs per day, within the original guidance range; unchanged '26 average production of 620 to 640,000 BOEs per day is anticipated; we intend to maximize the use of our new Dimsdale, Alberta storage capacity, as well as existing long-term Dawn and California storage facility positions, along with potential in-basin production curtailment during periods of low prices this spring and summer; we've also scheduled the vast majority of our '26 facility maintenance into Q2 during low gas prices, which keeps gas volumes offline, today that equates to around 70 million per day, and some of that is higher-cost third-party gas, and that's all largely factored into '26 guidance and Q2 guidance. Briefly on financial results, as mentioned, we generated $202 million of free cash flow in the quarter, really despite extremely weak western North American gas prices this winter; first quarter opex was $4.75 per BOE, that's down 8% from Q1 2025, and our full-year '26 opex of $4.50 per BOE continues to be expected, and that's down 9% from full-year 2025, as we continue to make the business better primarily through our BC buildout; full-year '26 EP capital budget remains at $2.55 billion, that's following the $350 million reduction that we announced on March 4th of this year; we have identified an additional $200 million of what is primarily D&C capital that could be deferred from the '26 EP program should western North American nat gas prices remain weak through the whole year; Tourmaline's exposure to international LNG prices and increasing liquids pricing has improved current '26 free cash flow estimates to a little over 0.9 billion, and the free cash flow benefit from our exposure to JKM and TTF pricing via our LNG export-related contracts will not be realized until Q2, and that's due to the timing of LNG cargoes, so that benefit was not in our Q1 cash numbers; some marketing highlights, our average realized nat gas price in Q1 '26 was $3.59 per Mcf Canadian, significantly above the AECO 5A benchmark price of $2.05 per Mcf for that period, as we continue to reap the benefits of our diversified marketing portfolio and strategic hedging program; we have an average of 930 million cubic feet per day of natural gas hedged for the remainder of '26 at a weighted average fixed price of $5.13 an Mcf Canadian; we have an average of 220 million a day exposed to international pricing, TTF and JKM, in '26, and that systematically grows over the next two years; the company's also amongst Canada's largest propane producers, and similar to the natural gas business that we have, we have a long-standing propane marketing diversification strategy in place; currently, approximately 45% of our propane production receives the Argus Far East Index propane price; and with the benefits of this improved NGL pricing and reduced ethane production, we do expect '26 NGL realizations to average close to 30% higher than they did the prior year.

Looking at the EP program, as mentioned, well outperformance compared to prior five-year averages has continued in both gas complexes; in the BC Montney complex, '25 well performance was up 22% over the previous five-year period, that being 2020 to 2024; in Q4 '25 and Q1 '26, this has continued, BC Montney well performance on gas side is up 13% over the 2020 to now 2025 timeframe, and the Alberta Deep Basin is up 6% over the same time period, that's based on IP30 rates because we haven't had the wells on for as long. Just some specific well highlights, we've done extremely well as we generally do during Q1 of '26 in what we call the North Montney; we've delivered strong pad and well performance in all three sub-complexes in the north, at Aitken, the five-well Birch pad averaged IP90 rates of 3.4 million cubic feet per day and 419 barrels per day of C5+; at Gundy, the 11-well D4-G pad tested at average peak rates of 25 million cubic feet per day and 130 barrels per day of C5+, so that's across 11 wells, that's the average, it is important for investors to know that we're choking almost all of our high-deliverability gas wells in this current low local gas price environment; further north in Conroy, the eight-well Laprise pad averaged IP90 rates of 4.8 million a day and 283 barrels of C5+; Deep Basin also continued to deliver strong well results throughout the complex, not as robust as the BC Montney, but very strong for the Deep Basin, particularly on the liquid side; so Resthaven, three-well Wilrich A pad came on production in March, has an average IP30 of a little under 15 million cubic feet per day and 112 barrels per day of condensate along with that; the Ansel 8-11 three-well Wilrich pad came on in February, average IP30 of 11.7 million cubic feet per day and 217 barrels per day of C5+, which is well above normal; in the South Deep Basin, the Ferrier 2-22 well Glock pad started up in March, and it produced at average well rates of 724 barrels per day of C5+ and 2.7 million cubic feet per day of gas; and, safe to say, on a broader note, our year-end '25 2P natural gas reserves of 27.7 Tcf, achieved with only booking 15% of current drilling inventories, position the company very well, as recent international developments render sizable economic reserves in stable jurisdictions increasingly attractive; on the EP&I front, Tourmaline is the first Canadian company to be certified under the MiQ and the first company in MiQ's history to have certified integrated gas production and processing facilities, it applies to our full Northeast BC gas production base of 1.6 Bs a day, and it positions Tourmaline to access differentiated markets where verified methane intensity influences procurement decisions in landed jurisdictions; we continue to progress the multi-year diesel displacement strategy, that's a cost savings and an emissions reduction exercise, we've displaced over 250 million liters of diesel now since we started this and saved over $245 million to date, and that includes the cost of the nat gas fuel replacement, our new 10-year target is savings of $565 million, these are material cost savings; and then finally, our Board of Directors intends to declare a quarterly base dividend of 50 cents per share in early June, which will be payable on June 30th, 2026, to shareholders of record at the close of business on June 15th, 2026; so I think that's it for any kind of formal remarks, and we're all here to answer questions, thanks.

Hey, good morning, guys. I guess first off on gas dynamics, the West Coast arb, which has been a little bit of a headwind, looks open for the summer, curious if you think that exports can pick up meaningfully over the next few months, and then have we seen any reaction in the Malin and PG&E strips from lower hydro generation tied to the Grand Coulee and that stuff, or is that all still really yet to materialize?

It's starting to materialize. As we look at BC, Pac Northwest, and Northern California hydro, it's all moved down significantly from where it was.

Jamie can talk to the strips. Really all we need in California now is some heat.

We still have over a Bcf a day of gas on GTN that should be going west that is backed up into Alberta, we need to see PG&E improve first, and we think we will when they get some heat because hydro has moved off, the Grand Coulee Dam maintenance is underway, and we think that ultimately lifts AECO and Station 2. We think this happens during Q2, and there's a number of other green shoots that we've seen that we're excited about, but let's make sure it's not another false start.

All three markets have moved up over the past week, but let's see that happen on a sustained basis. Jamie, I think you've probably paid more attention to the strip,

so. We do see arbs coming into a place where we could expect exports to come back in July, August.

Even just in the last couple weeks, as Mike was saying, we've seen firmness in PG&E Malin directly translate into a better AECO strip, these markets are clearly connecting right now. Some other additional points, Costa Azul started taking gas a little earlier than we expected, so that's the LNG plant in Mexico, and long has been our thesis that that plant actually impacts the California corridor more than a Delaware egress point, and that's exactly how the strips reacted on feedgas.

SoCal was the market that seemed to react the strongest, and that will further tighten the California corridor. As Mike was saying, it's about a Bcf of export loss out of the WCSB today, and to put that in perspective, LNG Canada has recently been getting to nameplate, running at 2 Bcf a day, averaged about 1.5 Bcf per day in the first quarter.

Production in-basin is up modestly. It averaged roughly 0.7 Bcf a day in the first quarter, but at many times has been closer to flat.

We're closer to flat entering into Q2, and we were flat on exit. We would normally, with the LNG plant on at 1.5 going to 2 and production up less than 1, be in a pretty tight market.

What has masked that tightness completely is this lack of exports into that West Coast market. Now this LNG plant is going to be on for 40 to 60 years ahead of us, while this West Coast export outage or lack of economic pull is going to last until July if we get heat and August, September if we don't.

We think this temporary disruption in how AECO is trying to balance is indeed going to be measured in months, and then we turn into a much tighter basin in the two years ahead of us. When we look out a little further, we see the WCSB averaging over a Bcf of demand over the next five years.

Understood. Then just longer term, curious what you think of Canada's entrée into sovereign wealth, and could the Canada Strong Fund be a tailwind for a project like Cedar LNG getting financed and getting to FID?

Do you think that sovereign wealth or any other fiscal support can realistically drive additional LNG infrastructure on the West Coast beyond LNG Canada Phase 2 and beyond Cedar LNG?

I'd say yes would be the short answer to that question. If there's 25 billion of additional capital available, it certainly can't hurt.

All right, got it. Thank you, gents.

Thanks, guys. Good morning, and thanks for taking my question.

I guess just thinking about the potential of the incremental $200 million capital reduction that you've pointed to, I think that probably most reasonable people could assume that you want to see how sort of the summer plays out from a storage dynamics, probably overall, but also regionally. What's sort of the gating parameters around that decision point, and then to the extent that you're choking volumes and building DUCs here, does that act as a tailwind as well for the capital program in 2027?

Yes, it does, and really as soon as second half 2026, because really we went through the same exercise to some extent in 2025 and matched the production growth curve to the improving price curve and ended up achieving our production targets for 2025. By deferring production in Q2 and deferring capital expenditures in Q2, you make that cash all back up in the second half and actually exceed it because you're going to sell into what we think is going to be a higher price environment.

I think largely you're correct on that assumption.

Great. Then with the update here, you realized some of the improved waterborne gas prices, as well as some liquid pricing, incremental free cash flow.

Net debt is still below sort of the target level, and alluded to distribution of that. Can you walk through sort of how you see the mechanics of incremental free cash flow distribution going forward?

I think it's a very dynamic time. Prices are moving dollars, sometimes almost $10 a day.

Our strategy right now is to receive this free cash flow. We have some observations.

One of our observations is, especially in NGLs, the backwardation is incredibly steep. It's a less liquid market, there's less visibility and liquidity, and so it backwardates steeply, and so it could very well outperform what strip's say today.

Our go-forward plan is to receive these higher cash flows, definitely in Q2, cash flows will benefit from the tension the war has created in all of our markets. Then once that cash is received, then we'll proceed to the decision on how it's going to be distributed.

You're right, we're below our net debt target, and we definitely have a practice of continuing to deliver excess free cash flow back to shareholders. This time, we just want to make sure we have it in our pockets first, just because the day-to-day changes in outlooks are more dramatic in this current environment.

Thank you very much.

Good morning, team, and thanks for taking my questions. I was just wondering if you could speak a bit about your latest views on the outlook for in-basin power demand growth driven by data centers up in Canada.

What are you seeing in terms of Tourmaline-specific conversations, and are you seeing any new regulatory tailwinds, too?

Start at the end of that, on the regulatory side, the federal government deferred or eliminated the Clean Electricity Regulations, which promotes gas-fired power in Alberta. The Alberta government, with Bill 8, stacked the regulatory process rather than run it in sequence, logically that should make it go a little faster.

We've been exploring the possibility of co-locating with a hyperscaler at one of our sites, and are really a year into that evaluation process, and we offer a lot if it's all competitive on a North American basis. We could do that, or we could just simply be a provider of gas to another project.

We don't have anything to announce at this point on our own initiative, but are well into it and will certainly advise the market if something material transpires. Alberta's a great place to do this, I think our current government recognizes it.

It's something that has to get done relatively soon because there's not an infinite number of data centers that are going to get built, and we think the whole industry in Alberta on the data center behind-fence power gen looks a lot more legitimate as soon as a major announcement is made.

Great, thank you. Then just for my second question, I appreciate the color you provided on your outlook for local pricing over the next several months or so, but I was wondering if you could speak a bit more about your latest views and if you're looking to hedge out incremental local exposure in the near or medium term, if you're able to.

If we're able to. Reality is the strips over the past few months really haven't offered anything that looks attractive, but we certainly intend to run with a larger hedge book than say we did two and three years ago.

Brian and Jamie.

We have picked up a bit more LNG hedging, as well as taking advantage of the run-up in oil and liquid strips a little bit. Worth thinking about storage as a mechanism in your effective hedge book.

It's like a physical hedge. You're moving volume from one quarter to the next, and so the contango in AECO is steep.

I think it's going to be an incredible year to store gas for Tourmaline, and we now have 2 Bcf in storage with eight to go. We have lots of options and lots of times in the months ahead of us to inject when prices are low, and we expect to have many opportunities in the third and fourth quarter and the first quarter next year to withdraw that gas at a much higher price.

Thank you.

Thank you.

morning, everyone. Every time you turn on the TV on the business channels, you hear about OpenAI, Anthropic, and all kinds of AI stuff.

What's going on in terms of business side for Tourmaline? Are you finding benefits in the field, head office?

Can you give us some examples of things that you're integrating into your system, and does that impact materially in terms of productivity, does it impact your labor force? Just to get an idea of how a real company is using all of this new technology.

We're using it and evolving it in many aspects of our business currently, from learning software in the field to optimize production for wells that are on plunger lift, to drilling technology just behind the bit to learn and drill faster and faster wells. Then there's a whole myriad of opportunities within head office itself: AI bots going through 3D seismic volumes looking at the horizons that are outside what we're landing our horizontals in the Deep Basin and the BC Montney, and can really complement an exploration program that we have going on already, and are the only company in Canada at scale that is doing that.

The opportunities are endless. It's not going to distract us from what our main business is right now, and as tools, I think you just look at it as a series of tools and use them effectively.

Can you quantify yet productivity improvements, or is it too early?

I'd say too early.

Yeah.

We have one tech that we're quite pleased with, and they're a private business called Ambience. We partner with them and they're steadily working across our fleet, and it's on the artificial lift side, rod lift going to gas lift.

The quick math is with optimized well calls, it could be a 10,000 BOE a day uplift for our business. That's one example of lower base decline.

There's a slew of emission benefits and cost benefits on top of that, but we have found some real diamonds in our pursuit of looking at all the different applications that this can come into our business, and that's one we're really excited about and pleased with.

Super. Thanks very much for answering my questions.

Appreciate it.

Good morning, and thanks for taking my question. We saw a major announcement last week with respect to M&A and the Shell and ARC transaction.

Tourmaline's historically been an active acquirer, particularly when gas pricing is weak. Would you be able to just discuss how the team is thinking about M&A in the current environment?

Thanks.

I don't think we've changed our mantra from what we've been saying over the past year, Jamie, that post mid-2025, we're looking at small, complementary, tucked-in asset deals in and around existing assets and infrastructure, or infrastructure that we're going to construct over the next four to five years in BC, we're not pursuing large M&A at this point in time.

Thanks. Then we did see a dispose of an asset in this past quarter.

Are further dispositions on the table, or how are you thinking about that, Mike?

That was really a long-planned disposition. We sold our most mature production complex, a small component of the overall company, and essentially are going to replace it with brand new lower-cost production much earlier in life.

Really as we went through our M&A cycles over the almost 20 years of the company, we've been pretty good at disposing of assets that we didn't really felt fit in the long term, and so there's no big dispositions being planned by the company right now.

That's all for me. Thank you.

Thank you.

Hey, thank you for thinking long term for investors. In the short term, kind of tying into that last question with the ARC-Shell deal, we can all see all the metrics and the PV-10 and the production and the price they paid, and we know you used to do business with them or worked there.

Do you have any other comments about that deal, comparing and contrasting to what your assets are, and are there going to be any economies of scale that they're going to get that's going to impact you? Any ideas along that?

Thanks again.

I don't think there's economies of scale for us. From a macro standpoint, we hope this is the catalyst that gets Shell to FID LNG Canada Phase 2.

We know the metrics of that deal happened as well, and they're at a much higher per-share valuation for Tourmaline than where we're currently trading at based on existing 2P reserves. I'm kind of sad that ARC's gone.

This is a multi-decade company that's had a long, storied history in the basin, and it's kind of too bad that they're disappearing, but that's the business transaction that was arranged.

Thanks.

great, thank you. Mike, you've already had a couple questions about the Shell acquisition of ARC, but I'm just wondering, have you been seeing, given what's happened geopolitically, increased interest in the space from foreign buyers?

Like we saw Shell obviously, but they have some unique need there, but what about other players that possibly could be looking to invest in Canada? What's your thoughts around that?

I think there definitely is enhanced interest, Fai. We're seeing a whole lot of interest on the LNG side, and so we have a lot more approaches on doing supply deals for various liquefaction facilities across North America.

We're seeing more potential projects emerge that could add additional egress for the Western Canadian Sedimentary Basin. It's exciting times.

Natural gas, it's really evolved into the central core of the world's energy stack, and it's going to be like that for decades to come, and it's for all kinds of good, pragmatic reasons, we're excited. Just bear in mind that what's really exciting for us right now is that we're rapidly making a really good business that much better, from well productivity to improving costs to a fortress balance sheet to decades of booked reserves to an unmatched, high-quality drilling inventory.

Every aspect of our business is getting better, and lower western North American gas prices are masking that in the short term, but it's going to be a double win for shareholders when this all turns around, and we think it can happen within a quarter on the local pricing front.

Okay. On that note, I know Jamie talked about the temporary reasons why AECO gas might be depressed right now, and I understand it makes sense to take the actions you're doing in terms of more gas storage and increasing your DUC levels.

I'm just kind of wondering if, given it's temporary, what sort of AECO price would we have to see before in the future to avoid this kind of increased storage and DUCs? What kind AECO price, would it be $3, what price would you be looking at?

We don't plan to increase our capital budget from what we've laid out in that five-year plan or the cadence of it. We'll make sure the first two major facility projects in the North Montney Phase 1 buildout are accomplished on time.

When prices are getting weaker, what do we look at? It's on that inventory slide in our COV.

Our breakeven, half-cycle economic price for the Deep Basin is in the $1.90 to $2 range, so that's why most of the capital deferrals or cuts have been on that side of the ledger. Our BC Montney gas-condensate complex, the breakeven's $1.40, which is partly why the whole buildout's happening in the first place.

Those are the numbers that cause us to cut capital, and we've got a very well-thought-out, very detailed capital program over the next five years in the BC buildout that, as I mentioned, will continue to improve our margins and drop our costs.

That's great. Just a last quick question.

I was just assuming when I read your press release that you're going to get some excess cash flow in the second quarter due to the Iran war and that a little bit of a windfall, and I was just assuming it's going to be paid on special dividends, but it sounds like it may not necessarily be that case and you might consider other options. Which brings the question what would cause you to think about share buyback perhaps?

Let's see how much free cash flow we have, and that's what Jamie was basically saying is that because things are so volatile and short term, let's realize the free cash flow win above the base dividend obligation, and then make decisions on where it's going to be allocated.

Would you necessarily be looking at your share price or would be some other factors involved?

We'll look at all the various options.

Thank you.

Thanks.

Thanks, Josh. Thanks everyone for attending, and we'll talk to you at the end of next quarter.