Thank you, John, and welcome everyone to our discussion of Tourmaline's financial and operating results as at June 30, 2026 and for the 3 and 6 months ended June 30 in '26 and '25. My name is Scott Kirker and I'm the Chief Legal Officer here at Tourmaline Oil.

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 these advisories.

I am here with Mike Rose, Tourmaline's President, 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 from the last quarter and the year so far.

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

Thanks, Scott. Thanks, everybody, for dialing in this morning.

A few highlights: Q2 '26 cash flow was $786 million, generating $192 million of free cash flow in the quarter. We've entered into a long-term agreement to increase propane and butane exports through the new AltaGas REEF terminal, increasing Tourmaline's exposure to premium LPG export markets by approximately 55% and improving realized margins for these products.

Our strong well outperformance has continued, with first-half '26 performance now up 28% for the Northeast BC Montney Complex and 14% for the Alberta Deep Basin over the prior 5-year averages. The Northeast BC infra buildout is on schedule and on budget, with 5 of the 6 regional connector pipelines already completed, and the Aitken plant expansion startup on schedule for Q4 of this year.

We're now scheduling a 1-year pause between phase 1 and phase 2 of the BC infrastructure buildout, enhancing anticipated second-half '27 and 2028 free cash flow and shareholder returns. Looking at production, Q2 average production was 594,000 BOEs a day, marginally below the guidance range of 595 to 605,000 BOEs per day.

That was by choice, as we injected more nat gas into storage, deferred activity in response to low Q2 natural gas prices, and also had some price-related shut-ins during the quarter. Storage injections at Dimsdale, Alberta; Dawn, Ontario; and Wild Goose in California averaged 8,900 BOEs per day in the quarter, and that was higher than initially planned.

These volumes are expected to be largely withdrawn from storage during the fourth quarter of this year and perhaps into the first quarter of '27, obviously at a higher price than we injected them at. Full-year '26 production range of 620,000 to 640,000 BOEs per day still anticipated, including a '26 production exit target of 660,000 BOEs per day.

Given the activity deferrals from Q2, we have 67 wells ready to frac and an additional 21 wells to turn in-line. We'll do that in concert with improving prices.

Looking at our financial results and the capital budget, net debt as of June 30th of this year was $1.5 billion, and that's below our long-term debt target of $1.75 billion. Second quarter opex was $4.59 per BOE, and that's down 10% from the corresponding quarter in 2025 and 3% from Q1 of this year.

Full-year '26 operating costs of $4.50 to $4.60 per BOE are expected, and that'll take us down between 7 and 9% from full-year 2025. We're maintaining the aggregate operating and transportation cost reduction target of $1.50 per BOE by 2031 relative to first-half '25 levels.

The full-year 2026 EP capital budget remains at $2.55 billion following the $350 million reduction to the full-year budget that we announced on March 4th of this year. At current strip pricing, 2026 free cash flow is now estimated to be $880 million, and the free cash flow benefit from the company's exposure to JKM and TTF pricing via our LNG export-related contracts is expected to continue through the balance of '26 and 2027.

We are now scheduling, as mentioned, a 1-year growth spending pause between the 2 phases of the BC Montney buildout and development project, and this will allow the company and shareholders to realize the full operational benefits and free cash flow growth from phase 1, commencing in the second half of '27 and into 2028 prior to embarking on phase 2. The pause also lets us assess global natural gas supply, demand, and various pricing outlooks around the globe.

'27 EP spending is thus revised down to $2.55 billion, and 2028 EP spending is revised down to $2.3 billion. On A&D activity, we continued to pursue small tuck-in acquisitions and working interest consolidation opportunities adjacent to existing company lands and operated infrastructure.

During the second quarter, we acquired Aduro Resources in the South Montney Complex. That was for total consideration of $100 million, and that included net debt, and it consisted of $50 million of cash and approximately 1.5 million common shares of Topaz Energy Corp.

The acquisition included modest current production and infra, as well as 174 net Tier 1 Montney locations adjacent to the Tourmaline Groundbirch-Meneice deep cut plant that is currently under construction. During the quarter, we also completed the sale of a GOR on the Aduro lands, as well as certain recently acquired Alberta Deep Basin lands to Topaz for cash proceeds back to Tourmaline of $38.7 million.

Briefly on marketing, our average realized natural gas price in Q2 was $3.12 per Mcf Canadian, as we continue to benefit from the diversified marketing portfolio and strategic hedging program that we continue to evolve. Tourmaline has an average of a little over a Bcf a day of natural gas hedge for the remainder of '26 at a weighted average fixed price of $4.97 per Mcf Canadian.

We have 220 MMBtus exposed to international pricing, both TTF and JKM in '26. For the balance of '26, JKM and TTF are trading over $15 USD per MMBtu, which is a 60% price appreciation for the same strip as at the beginning of this year.

The company is amongst Canada's largest propane producers, and similar to the natural gas business, we have a long-standing propane marketing diversification strategy that we've been pursuing, and as mentioned, we've entered into a long-term agreement with AltaGas to increase our propane and butane exports through the Ridley Island Energy Export Facility, commonly known as REEF. The increased LPG volumes will be supplied to REEF from our planned unit train rail loading facility located adjacent to the Groundbirch-Meneice deep cut plant that's already being built.

The new rail terminal is expected to improve our realized LPG margins by enabling direct rail shipments to the West Coast, and it's all part of that whole integrated Northeast BC infrastructure project. Our expanded natural gas storage capacity is yet another important component of the continued vertical integration of our entire natural gas business.

On the EP front, we drilled a total of 43 wells and completed 33 wells during the second quarter of '26. As considerable EP activity was deferred from Q2 into the second half of this year.

Importantly, strong well performance has continued in both gas complexes in the first half of the year. As mentioned, the BC Montney well performance is up 28% in the first half of '26 over the prior 5-year average based on the 25 wells that have actually reached IP90, and recall that '25 was up 22% over the previous 5 years.

Alberta Deep Basin is now also up, and it's 14% up in the first half of '26 over the prior 5-year averages, and that's based on 30 wells. We continue to evolve our EP approach to optimize deliverability, EUR, and IRR, and so you're seeing those results.

It's also in part the result of our machine learning-assisted multi-discipline data integration capability that we've been developing in-house. On the inventory front, as mentioned, the Aduro acquisition added 174 net Tier 1 locations at a cost of $462,000 per location.

In the Deep Basin, land sales which included the first disposition of previously restricted Alberta caribou lands and other minor asset consolidations added 110 locations at an average cost of $173,000 per location. I think you've probably observed that the location prices are a lot higher south of the border, in Canadian dollars as high as $10 million per location.

On the BC infra buildout, it's actually a major Canadian project that is fully funded by cash flow and currently being executed. The overall project, including both phases, will add 1.1 Bcf a day of gas and over 50,000 barrels per day of condensate and NGLs.

Once completed, it's anticipated to generate over $400 million of structural incremental annual cash flow compared to first-half '25 cost structures, and that's above the cash flow generated by the growing natural gas business and product sales that the growth will deliver. A substantial amount of the phase 1 buildout's complete.

That includes the Highway Condensate Hub, 5 of the 6 major pipeline interconnects, the Birley facility, the South Montney Electrification Project, and they're already leading to opex and transportation cost reductions in this year. You probably saw that Brian Robinson, our CFO, is going to retire effective November 1st of this year.

Brian's been here since we started Tourmaline in 2008, has done a brilliant job all the way along at Tourmaline and of course prior to that at Duvernay and Berkley. Safe to say the best CFO in the sector over the past 2 and 1/2 decades.

I may be a little biased. Brian will remain on the Board of Directors of Tourmaline following his retirement as CFO.

I'm also very pleased to announce that Jamie Heard, currently our VP Capital Markets, will succeed Brian as our CFO. Jamie's been doing a tremendous job in the capital markets role, and we know that that will continue with his expanded scope beginning in November.

Jamie also inherits the very strong and very deep finance team that Brian has built over his years with Tourmaline. Finally, our Board of Directors intends to declare a quarterly base dividend of 50 cents per share in early September, which will be payable on September 29th, 2026 to shareholders of record at the close of business on September 15th, 2026.

That's all for comments, and all of us are here to answer your questions.

Thanks, and congrats Brian, and thanks Jamie and congrats to you as well for everything. Just wanted your perspective first on the pause between phase 1 and phase 2 of NEBC and what drove it, what are you looking for in terms of confidence of bringing the project back, and then this will save you some cash here, how do you think about allocation of that cash between reinvestment and shareholder return?

I think in the general comments that I made before really describe it. It does give shareholders that opportunity to see how much better the business is getting just from phase 1.

We'll have 2 of the plants on, Aitken and Groundbirch. You're already seeing an improvement in opex and transportation costs and the initiation of that sustained commodity price-independent incremental revenue and cash flow.

We think it's the right thing to do. It's that balance between growth and shareholder returns.

We do listen to shareholders and get feedback to that end. We'll continue planning phase 2 all the way along.

We don't actually make any significant capital investments on phase 2 or decisions to order the long lead-time items really until mid-2027. For now, we'll do the planning.

If there's a 3-year sustained improvement in natural gas prices in $4 to $5, we can rethink the pause. Right now we think it's the best thing to do for everybody.

Jamie, anything you want to add to that, or?

We'll also be watching to see all the demand announcements we expect over the next 6 to 12 months. We expect several new LNG plants on the West Coast.

We expect several power announcements in the province of Alberta, potentially one we're more closely involved with. We also expect to see a large demand increase for our product on the Northwest and West side of the United States, where we have an established transportation network, and we're kind of monitoring and quickly evolving data center buildout in many of these states that actually don't have growing gas supply.

The ethos here is we want demand to pull gas, increase price, and then when we have that pull to answer, then we'll respond with supply and feed it into exactly where that demand is.

That makes a lot of sense, and that's kind of Jamie ties into the marketing side and the pricing side. Talk about the outlook for AECO gas and your confidence that the differentials will tighten up.

Do you have confidence that your peers will show discipline as well in the basin to allow demand to pull price?

I'll start. A few comments on Western North American gas prices.

California led the whole complex down in the first half of 2026. Warm winter, record hydro that was available for the first 4 months of 2026, and now California's going to lead the complex back up.

You've seen that already. There's heat in California.

Storage has withdrawn, I think, 26 of the first 29 days in July. Pricing's improved from $1.50 to well over $3 US now.

We think you'll see that start to drag AECO and Station 2 up towards the end of August when the current GTN maintenance that TC Energy has going on allows full volumes to flow west. GTN exports hit a low of below 1.5.

They're typically close to 3. They're running about 2 and 1/2 Bs a day right now, and there's room for another half B, and we expect that will fully flow west towards the end of this month, and then you'll start to see AECO and Station 2 follow the California PG&E price up.

Local supply has remained disciplined, Neil. We have not seen a major push of supply growth.

In fact, we're targeting roughly half a billion cubic feet a day of year-over-year supply growth. Despite with the export restrictions and the economic impulse to bring less Canadian gas to the United States, normally you would expect local storage to ramp quickly.

That hasn't been the case. We have definitely lagged the prior several years on our rate of injection, and we do not expect to have a very full storage picture at the end of this year's injection picture.

As Mike was saying, as GTN maintenance comes off through August and we're unrestricted in September, that's going to be a very open period for pushing gas both south, but also east, as the East is still tight. LNG Canada should be running full as well.

We expect that continuing tightening picture for AECO to help bring hub AECO basis in, and we continue to see that long-term basis needing to get closer to a dollar versus the $1.50 to $1.75 you see today, which for Tourmaline is a meaningful cash flow improvement. That kind of size of cash flow improvement for Tourmaline would equate to roughly half a billion dollars of free cash flow.

Thanks, Mike. Thanks, Jamie.

Thanks, Neil.

Hey, good morning, guys, and thanks for taking my question. First off, just congratulations to both Brian and Jamie, well deserved on both fronts.

First question, just with respect to the improvement in the type curves here and looks pretty markedly improved here in 2026. Now, there's a numerator and a denominator to capital efficiency, and I know there's longer laterals improved, completions.

Maybe some color with respect to at the capital efficiency level, the improvement that you're seeing from these type curves, and then if there is the potential that this could translate to some lower capital in the future given higher production?

That's right, Patrick. I actually think that's where you've seen it shine through so far, because markets haven't been buoyant in terms of price.

We've taken these efficiencies, and as a result, have put less wells on production and yet have been able to maintain the profile we are hoping to achieve on production, and so less capex. What you're seeing in the well results and the remarkable improvement over the 5-year average is both higher completion intensity, it is also longer laterals, and it's also some of our learnings in the play on landing and some of the machine learnings that Mike was speaking to on tweaking the technology to optimize each individual assumption and component of a completion.

What you're also seeing along with this productivity increase is us maintaining capital cost per foot at flat or lower levels. While we're doing more work in the well, higher tonnage, sometimes more water, more pressure, longer laterals, we've also been able to continue to push costs down and continue to expect DCET costs for Tourmaline to come down slightly this year, and we hope to lower them again next year.

That does allow us to have better capital efficiencies over time. We haven't yet reflected that in all the forward plan years.

We honor the last year's rate of efficiencies and the last year's type curves. As these soak into our actual results in our reserves, you will see commensurate improvements in the forward-plan efficiencies, and that'll also drive higher free cash flow.

Great, great. Maybe just to build on Neil and this may come off a little bit long-winded here, as I'm sure you're all aware I'm not known for my brevity.

Considering your outlook for demand and the shift to demand pull here, the things from a secular growth perspective seem to be shaping up, LNG export, increased power demand. Not necessarily seeing it and the resource reflected in the equity today.

Specifically in terms of the mode of those capital returns and the incremental free cash flow you guys have generated or will generate with the capital reduction or shift with the phase 2 plan, any thought now at these equity prices to be a little bit more aggressive and potentially start to dip into the NCIB?

We always look at that, Patrick. Right now, it's fairly simple math.

At $2 gas, we can cover maintenance capital, the growth capital component for '26 and '27, and the base dividend, and there's not a lot of free cash flow left over beyond that. We do think that is going to change rapidly here.

We're going to realize that free cash flow first and then look at what are our options. I would say priority one would be a base dividend increase when we have enough free cash flow on a sustained outlook to fund that, and as we use a very harsh price environment for 5 years when we contemplate base dividend increases.

As the free cash flow continues to accrete, Jamie mentioned that a dollar on AECO, which really isn't very much from where we are now, is $500 million in free cash, and then we will look at the full gamut of shareholder return options.

Okay. Thank you very much.

Good morning. Thanks for taking my question here.

You touched on this a little bit earlier, but can you talk about the power opportunity or data center opportunity for Tourmaline and what something like that could look like? Thank you.

I think we can all jump in on that one. We're not going to build a data center.

They're quite expensive. Just wanted to make that clear.

We do see it as another opportunity for our gas market diversification portfolio. We'd be seeking a gas supply deal with pricing that reflects reliability and all the other services that we can offer, and those include land, water, power redundancy, fiber connect, further growth opportunities, low CI gas to begin with, but also the opportunity for full CCUS disposal.

All those would translate into a higher fixed price contract. We're well over a year into trying to co-locate with a hyperscaler at one of our plants.

It's the Banshee plant near Edson. It's about 40 km from Edson.

Nothing firm to announce on that, but we're quite far along in the process.

Jamie, I'd say at first you always like your own cooking, right? At first we thought we had a good site and we engaged partners to proceed with this project.

Now that we're in market and trying to find offtakers for this, I think we firmly understand they think it's a good site, too. Our confidence in being able to try to build a project here is increasing.

I think these projects are complex and they take some time, have patience with us, but we firmly believe when we do get this across the line, it will be a big win for Tourmaline.

Thank you. That's good color.

Then appreciating there's a number of moving parts in the guidance adjustments for '27, '28, but can you talk a little bit about the liquids guide for '26 as well and maybe the condensate outlook in particular just with the update overnight? Any color on that side would be helpful.

Thanks.

Thanks, Jamie. I think if you pull well results for Tourmaline right now, you're going to be able to replicate that 26% upside, and you're also going to see very strong upticks on the liquids we're receiving out of the wells.

We're winning on both products. One of the effects of slowing down is all businesses and resource plays have a slightly higher decline rate on liquids than they do on gas.

When you bring less wells into market, you're going to have a slight decrease in liquids relative to gas as an NGL mix. We're going to have that come back to us this fall.

As we get all these wells that we've drilled and completed and now are able to complete more through Q3 and turn them in-line, you're going to see the liquids mix really ramp into the back of the year, and I'm comfortable with the guidance we have out for '27 and therefore forward. Condensate is a big part of the NECB buildout.

We're going to have very rich condensate wells contribute to both the Aitken plant startup and the Groundbirch plant startup. It's going to be a meaningful cash flow driver for Tourmaline.

It's just been on the bench a little bit as we've had to slow down due to weak gas prices this year and last year.

The other thing is we're seeing much more potential for strength in condensate pricing with the buildout of oil sands projects and the extension to oil pipelines, etc. The ability to bring condensate back in via Cochin and Southern Lights is limited.

We'll see that premium rise. In tandem with that, of course, that creates another demand source for nat gas, too, that goes along with that, because we think every million barrels of additional oil sands production is about 0.7 Bcf of new gas demand.

Okay. Thank you for the color.

I will hand it back.

Thanks, Jamie.

Oh, thank you. Congrats to Brian and Jamie as well.

Just related to the last question, I was just wondering in terms of the type of agreement that you'd be looking on a long-term basis, would you be looking for some locked-in fixed price, or would you be looking for some variability around, how are you thinking about in terms of marketing in terms of these potential LNG agreements?

Are you talking about additional LNG agreements or the data center? Just clarify.

Sorry. The additional LNG term agreements.

We like access to international pricing, whether it be JKM, TTF, or something of that ilk, and then we are willing to pay a fixed deduction below those prices. Those deductions are based on shipping costs.

Obviously on the West Coast, shipping costs are much lower than the Gulf Coast, but they're also based on liquefaction costs, and liquefaction costs will be borne out of the capital costs that was made to construct the facility. To date, we have seven different agreements in the Gulf Coast, many of which we supply physically, some of which we supply locally and then enjoy a knit delivery point.

Those deductions have been very competitive, and in fact, if you look at our portfolio, we are in some of the lowest-cost LNG facilities in the world. That's how we've driven our decision-making, because it allows us to make money through the entire LNG price cycle.

When we're looking at these West Coast opportunities, we're looking at it under the same lens, and we think as they expand and also more are announced, we're going to be able to blend down that liquefaction cost to a competitive level, and they already have the shipping cost advantage. We continue to seek to try to replicate our Gulf Coast strategy on the West Coast on a similar contract style.

Great. That's what I was wondering about.

Thank you.

Thanks, Phil.

Thanks.

Thanks, everyone, for checking in. We'll see you in the next quarter.