Tourmaline Oil Corp. (TOU) Earnings Call Transcript & Summary

Good morning, ladies and gentlemen, and welcome to the Tourmaline Q2 2020 Results Conference Call. At this time, doing the presentation, we will conduct a question-and-answer session. [Operator Instructions] This call is being recorded on July 30, 2026. The I would now like to turn the conference over to Scott Kirker. Please go ahead.

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 3026 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 Germline 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 and Chief Executive Officer; Brian Robinson, our Chief Financial Officer; and Jamie Heard, German's Vice President of Capital Markets. We'll start with Mike speaking to some of the highlights for the last quarter and the year so far. After his remarks, we'll be for questions. Go ahead, Mike.

Thanks, Scott. Thanks, everybody, for dialing in this morning. So a few highlights Q2 2016 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 2016 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 build-out is on schedule and on budget with 5 of the 6 regional connector pipelines, already completed and the Akinplant expansion start-up on schedule for Q4 of this year. We're now scheduling a one-year pause between Phase 1 and Phase 2 of the BC infrastructure build-out enhancing anticipated second half 2017 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 595,000 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 the that. Full year 2016 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 30 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 2016 operating costs of $4.50 to $4.60 per BOE are expected, and that will take us down between 7% and 9% from full year 2025. And 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 2020 EP capital budget remains at $2.55 billion following the $350 million reduction to the full year budget that we announced on March 4 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, one year growth spending pause between the two phases of the BC Montney build-out 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 and commencing in the second half of 2017 and into 2028 prior to embarking on Phase I. The pause also lets us assess global natural gas supply demand and various pricing outlooks around the globe. Spending has thus revised down to $2.55 billion and 2028 EP spending is revised down to $2.3 billion. On A&D activity, we continue 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 Court. The acquisition included modest current production in infra as well as 174 net Tier 1 Montney locations adjacent to the terminal in Groundbirch Monias deep cut plant that is currently under construction. And during the quarter, we also completed the sale of or on the Aduro lands as well as certain recently acquired Alberta Deep Basin lands to Topaz for cash proceeds back to terming of $38.7 million. Briefly on marketing. Our average realized natural gas price in Q2 was CAD 3.12 per Mcf as we continue to benefit from the diversified marketing portfolio and strategic hedging program that we continue to evolve. Thermaline has an average of a little over 1 Bcf a day of natural gas hedged for the remainder of 26 at a weighted average fixed price of CAD 4.97 per Mcf. We have 220 MMBTUs exposed to international pricing, both TTF and JKM and 26 for the balance of 26 JM and TTF are trading over USD 15 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 experts through the Ridley Island energy export facility, commonly known as Reef. The increased LPG volumes will be supplied to reap from our planned unit train rail loading facility located adjacent to the Groundbirch Manish 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 -- and as you know, 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 over the prior 5-year average based on the 25 wells that have actually reached IP 90. 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 multidisciplined 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 another minor asset consolidations added 110 locations at an average cost of $173,000 per location. I think you 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 build-out, 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 million 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 build-outs complete. That includes the highway condensate hub, 5 of the 6 major pipeline interconnects, the Birch facility, the South Montney electrification project and they're already leading to OpEx and transportation cost reductions in this year. And you probably saw that Brian Robinson, our CFO, is going to retire effective November 1 of this year. Brian has been here since we started terminaling in 2008, has done a brilliant job all the way along at Termoli and, of course, prior to that at Duvernay and Berkeley. Safe to say the best CFO in the sector over the past decades, I may be a little biased. Brian will remain on the Board of Directors of Thermaline following his retirement. -- as CFO. And I'm also very pleased to announce that Jamie Heard, currently our VP, Capital Markets, will succeed, Brian, as our CFO Jamie has been doing a tremendous job in the capital markets role, and we know that, that will continue with this expanded scope beginning in November. And Game also inherits a very strong and very deep finance team that Brian has built over his years with terminalling. And finally, our Board of Directors intends to declare a quarterly base dividend of $0.50 per share in early September, which will be payable on September 29, and 20 to shareholders of record at the close of business on September 15, 2026. So that's all for comments, and all of us are here to answer your questions. Thank you.

[Operator Instructions] We now have our first question, and this comes from Neil Mehta from Goldman Sachs. Please go ahead.

Yes. And congrats, Brian. Thanks, Jamie, and congrats to you as well for everything. So just wanted your perspective first on the pause between Phase I and Phase II 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. So how do you think about allocation of that cash between reinvestment and shareholder return?

Yes. I mean 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. So we'll have 2 of the plants on Aiken and Groundbirch. I mean, you already see an improvement in OpEx transportation costs and the initiation of that sustained commodity price independent incremental revenue and cash flow -- so we think it's the right thing to do. It's that balance between growth and shareholder returns. So we do listen to shareholders and get feedback to that end. -- we'll continue planning Phase I 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. But for now, we'll do the planning. If there's a 3-year sustained improvement in natural gas prices, 4 to 5, we can rethink the pause. But right now, we think it's the best thing to do for everybody. Jamie, anything you want to add to that? Or.

Yes. 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 1 we're more closely involved with. And 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 a 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 James 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.

Yes, I'll start. I mean, a few comments on Western North American gas prices. California led the whole complex down in the first half of 20 warm winter, record hydro that was available for the first 4 months of 2026. And now California is going to lead to complex back up -- you've seen that already. There's heat in California storage as withdrawn, I think, 26 of the first 29 days in July. -- pricing's improved from $1.50 to well over USD 3 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 TransCanada has going on, allows full volumes to flow less. So exports hit a low of below 1.5. They're typically close to 3. They're running about 2.5 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 PGE price up.

And local supply has remained disciplined, meal. So we have not seen a major push of supply growth. In fact, we're targeting roughly 0.5 billion cubic feet a day of year-over-year supply growth with the export restrictions and the economic impulse to bring less Canadian gas in 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 a 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. And LNG Canada should be running full as well. So 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 $1 versus the $1.50 to $1.75 you see today. which for Permian is a meaningful cash flow improvement. That kind of size of cash flow improvement for Terminalling would equate to roughly $0.5 billion of free cash flow. SP1 Yes, sir.

And the next question comes from Patrick arc from ATB Capital Markets. Please go ahead.

First off, just congratulations to both Brian and Jamie, well deserved on both fronts. First question is just with respect to the improvement in the type curves here and looks pretty markedly improved here in in 2026. Now there's a numerator and 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?

Yes, that's right, Patrick. And 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 the completion. What you're also seeing along with this productivity increase is us maintaining capital cost per foot at flat or lower levels. And so 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 costs for Terminal to come down slightly this year, and we hope to lower them again next year. And so 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 in the last year's type curves. And so as these soak into our actual results and our reserves, you will see commensurate improvements in the forward plan efficiencies, and that will also drive higher free cash flow.

Great. Great. And 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 gravity. -- considering your outlook for demand and 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 any incremental free cash flow you guys have generated or will generate with the capital reduction or shifts 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, I mean, it's a fairly simple math at $2 gas, we can cover maintenance capital, the growth capital component for 26 and 27 in 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 you know, we use a very harsh price environment for 5 years when we contemplate base dividend increases and as the free cash flow continues to accrete. Jamie mentioned that $1 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.

And the next question comes from Jamie Kubik from CIBC.

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

I think we can all jump in on that one. I mean we're not going to build the data center. They're quite expensive. I just want to make that clear. But we do see it as another opportunity for our gas market diversification portfolio. So 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. So we're well over a year into trying to co-locate with a hyperscaler at 1 of our plants. It's the Vance plant near sand it's about 40 kilometers from Edson. So nothing firm to announce on that, but we're quite far along in the process.