Tourmaline Oil Corp.

Good morning, ladies and gentlemen, and welcome to the Tourmaline Q2 2024 results conference call. At this time, all lines are in listen-only mode. Following the presentation, we will conduct a question-and-answer session. If at any time during this call you require immediate assistance, please press star zero for the operator. This call has been recorded on Thursday, August 1, 2024. 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 Termaline's financial and operating results as of June 30, 2024, and for the three and six months ended June 30, 2024 and 2023. My name is Scott Kirker, and I'm the Chief Legal Officer here at Termaline 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 Termaline Annual Information Form and our MD&A that's available on CDAR and on our website. I also draw your attention to the material factors and assumptions in those advisories. I'm here with Mike Rose, Termaline's President and Chief Executive Officer, Brian Robinson, our Chief Financial Officer, and Jamie Hurd, Termaline's Vice President of Capital Markets. We'll start by speaking to some of the highlights from the last quarter and our year so far. And after Mike's remarks, we will be open for questions. Go ahead, Mike.

Thanks, Scott, and thanks, everybody on the line. So firstly, a few highlights. Second quarter average production of 562,000 BOEs a day was up 13% over second quarter 23 and within our second quarter 24 average production guidance range. Our second quarter cash flow was $755 million or $212 per diluted share on EP expenditures of $307 million in the second quarter and that generated free cash flow of $434 million or $1.22 per diluted share. Given the strong continued free cash flow generation in the second quarter and the full year financial outlook, we elected to increase the quarterly base dividend effective Q3 24 by 3% to $0.33 per share or $1.32 per share on an annualized basis. And that's our third base dividend increase of the year. We also declare and pay a special dividend of 50 cents per share on August 21st of this year. And importantly, we reduced net debt by $137 million during the second quarter as well. On the production front, during this quarter of low natural gas prices, we completed multiple planned facility maintenance turnarounds. We also maximized injection into our gas storage reservoirs in California and at Dawn, Ontario. Our full year 24 average production guidance range has been revised to 575,000 to 585,000 BOEs a day, down 5,000 from the 580 to 590 previously. This will account for select third quarter frack deferrals into Q4 as we shift production into an environment of stronger anticipated natural gas prices later this year or early next year. This less than 1% production deferral is expected to have minimal impact on our 24 cash flow and actually a positive impact on 25 cash flow and free cash flow based on current strip prices. Looking a little deeper at the financial results, we realized Q2 24 net earnings of $257 million or $0.72 per diluted share, and that underscores the profitability of the business even in an extremely weak natural gas pricing environment. As previously mentioned, we remain committed to our long-term net debt target of $1.2 to $1.4 billion. And we intend to continue to make progress toward that target through 2024. And as mentioned, we did reduce net debt by $137 million in the quarter. Also, our 45.1 million shares of Topaz has a market value of around $1.1 billion as of June 30th. On marketing, Tourmaline's average realized natural gas price in the second quarter is was $3.03 per MCF Canadian, significantly higher than the 8.05A index price of $1.20 per MCF over the same period. And we benefited from our multi-year market diversification and transportation portfolio. We keep growing our export volumes and now expect to exit 24 with a total of 1.26 BCFP. per day of natural gas going to these export markets. For 2024, the company has an average of 1.03 BCF hedged at a weighted average fixed price of 4.66 per MCF Canadian. We have reduced both ACO and Station 2 exposure for the second half of 24 to approximately 9% of our total natural gas portfolio, and that's actually the lowest it's ever been. On EP, we drilled a total of 47 net wells during the second quarter, completed 38 wells, and grew our duck inventory to 36, entering Q3. We're currently operating 14 drilling rigs, and we expect to increase that to 15 by adding a rig in the fourth quarter, and we'll run the 15 rigs through to 2025 spring break-up. So we'll end up drilling more multi-well pads than what's currently in the EP plan for second half of 24 and first half 25. And simply, we believe it's a good time to capitalize on our actual lower net drilling costs and our continuously improving drill times. We'll be positioned to deliver production above currently estimated 2025 levels. And of course, that'll depend on where the price is. but we do think we're moving into a period of stronger commodity prices. But the 2024 EP capital budget remains unchanged at $2 billion due to these steadily improving drilling efficiencies. As mentioned, given current weak natural gas prices, we've shifted some originally planned well stimulation activity from the third quarter to the fourth quarter of 2024. And what we're really trying to do is match our production growth to the natural gas price curve and deliver those flush production volumes into that stronger pricing environment. And do recall we previously removed our planned 2024 natural gas growth from the EP plan in March of this year in response to week ago pricing at that time, and that's approximately 100 million per day. And over the past three years, We've consistently matched our growth in natural gas production to our incremental egress out of the western Canadian sedimentary basin, and we'll continue with that market diversification strategy. Further on E&P, an update on our North Montney development. We're excited about how fast and well our Conroy Phase 1 development is actually proceeding. There's two important facility components that are being completed. During this year, the first, the liquids condensate hub, which we actually started late in 2023, it will service both the phase one and ultimately the phase two North Montney developments. And it provides 20,000 barrels per day of condensate mercaptan treating and 70,000 barrels of condensate storage and will have regional pipeline interconnections. The total capital cost for that project is approximately $70 million, and when we did our budget reduction in March of this year, we left that project in. The second, the Birch A44i compressor station expansion will be completed during this quarter, and it's expected to add a net 6,000 BOEs a day to tourmaline production levels in 2025. Some of the other facility components in the overall Conroy development include the Aitken sales compressor, the Gundy A20i compressor expansion. That'll be completed this year as well. And then the Aitken regional gathering lines and the Aitken plant expansion, which are expected to commence construction in 2025. So we'll add 10 to 15,000 BOEs a day in 2025 through completion of the ongoing 24 facility projects Ultimately, the North Montney Phase 1 development will add 50,000 BUEs a day over the next three years. Of note, the company has received an additional 63 drilling permits since March 6th of this year for a total of 315 new drilling permits in northeast BC since January 1st of 2023. Looking at our EPI, or Environmental Performance Improvement, the company's diesel displacement initiative and drilling and completion operations has displaced approximately 152 million litres of diesel and replaced it with nat gas, and that saved us approximately $150 million since June of 2017. And obviously this has reduced a significant volume of a myriad of emissions. Our joint venture with Clean Energy Fuels for CNG and long-haul trucks continues with one station now fully operational with Edmonton, and there's four other stations that are under construction, and we expect them to be operating in the first quarter of 2025. So this initiative is a further significant diesel displacement opportunity. Our methane... Technologies continue to be advanced at the NGIF, Tourmaline Perpetual Emission Testing Center, or the ETC. It's the only one of this scale in the world, and it recently received a $15 million grant from the Alberta government to enable acceleration of these technology initiatives around the measurement and mitigation of methane emissions. And that's all I was going to say for kind of formal remarks out of the press release, and We'll open it up for questions.

Thank you. Ladies and gentlemen, we will now begin the question and answer session. Should you have a question, please press star followed by the one on your touch-tone phone. You will hear a three-tone prompt acknowledging your request and your questions will be pulled in the order they are received. Should you wish to decline from the polling process, please press star followed by the two. If you are using a speakerphone, please lift the handset before pressing any keys. One moment, please, for your first question. Your first question comes from Michael Harvey with RBC Capital Markets. Your line is now open.

Yeah, sure. Good morning, guys. So a couple of quick ones for me. I guess first on the program, you mentioned lower drilling costs just as a driver for the added rig. Just curious if that's a tourmaline-specific item or if you're seeing lower costs anywhere in the industry, any color on that would be helpful. And then the second one, just more macro-related, Strip still above 325 in 2025. If you were to see that drop, is there a price where you'd pull back on growth? And I guess just on the flip side, is there a higher price where you'd look to accelerate? Just kind of trying to understand if there's a bit of a snack bracket in terms of where you think the budget's most suited, all in context of your marketing, of course. But that's it for me.

Okay. Yeah, thanks, Mike. I'll start. On drilling costs, our costs are certainly lower than they were in the previous cycle. So we renegotiate during the second quarter and then fix our costs for July 1 through to next breakup. And they are down. And I can't speak for everyone else in industry, but so we're realizing lower costs. And that gets coupled with the improving drill times. So we do think it's a good time to add that extra rigged. And just to put a little color on it, 80% of the time for us to drill and complete a pad is on the drilling side. So we're quite comfortable drilling these pads. We'll continue to watch the gas price. We always finalize our EP budget for the upcoming year in November and release that in Q3. So to kind of answer your second question, there is certainly upside in our production volumes in 2025. We'll get three months here to watch it and see how it shapes up by the beginning of November and then decide how much more activity we do or if the prices retreat, as you mentioned, is always a possibility. We can decide to add the volumes in the second half of 2025. So I think of the large Canadian gas producers, we've always been the most disciplined about watching the strip and not bringing extra volumes to our two hubs, ACO and Station 2, when prices are low. Great. Thanks, Mike.

Your next question comes from Josh Silverstein with UBS. Your line is now open.

Good morning, guys. Just wanted to focus on Cheryl's returns. You guys are pretty close to the high end of the target net debt range. As you get there, how do you think about the allocation of free cash flow? Can you get up to 100% or do you want to build some cash? And then maybe along the same lines, you guys are clearly biased towards the dividend, but mentioned that you do have the buyback at your disposal. How could that start to enter the shoulder return equation as well? Thanks.

You bet. Well, our free cash flow funds, dividends, debt reduction, midstream investments, expiration, and share buyback. We were very happy with the amount of free cash flow that we had in the second quarter, but we can't fund everything, so we chose debt reduction and a modest base dividend increase and the special dividend for the current quarter, but we're always looking at that mix of how we use and how we distribute that free cash flow.

The other thing I would mention is that our debt target, we're not aspiring to have it right back at that original 1.2 to 1.4 by the end of 24 by any means, so we'll continue to work on it through 25 and perhaps into early 26 before it's back down in that range. And then further, is not to forget the fact that we have a significant topaz position and that equity valuation has improved, which essentially acts as a bit of a counterweight to the net debt question.

Is there any shift in thinking about the buybacks versus dividends?

Well, we're always looking at it and evaluating how it correlates to the valuation of the company. And as I mentioned, we can't do everything with the amount of free cash flow we have, even though it's quite significant in second quarter.

I think we're also really happy with how consistent we've been with that special. And so we're able to continue to offer that special quarter after quarter. We see potential for it to grow in the years ahead of us as well. The buyback is always thought to be more defensive. And so if the stock were to become fundamentally dislocated, We've got it there and ready, and we would act on it, and we have acted on it before in 2020 and 2021.

Great, thanks. And then just as a follow-up, you did add a little bit of export capacity as well. With the startup of LNG Canada around the corner, how are you thinking about the level of ACO exposure versus weighing some additional transport that you guys may need as your volumes are growing?

Well, we'll end up with more ACO and Station 2 exposure as we execute that five-year development plan. And we always time the North Montney development Phase 1 to the start-up of LNG Canada because we do think that will be structurally positive for in-basin pricing here at the two hubs when you pull ultimately two BCF a day west out of a basin that's more or less in supply-demand balance. But at the same time, we'll continue to evolve more transport both south into the U.S. and west.

Great. Thanks, guys.

The next question comes from Jamie Kubik with CIBC. Your line is now open.

Yeah, good morning. Thanks for taking my question. Just similar to an earlier question that you had there, You do mention some productive upside in the program for 2025 with some of the drilling changes that you've undergone here. Are you able to help frame how much that could potentially be? And maybe second part of that is just around the gas macro for 2025. We've heard other operators similar trying to time production additions into a stronger price environment. Would you expect 2025 still to be relatively undersupplied in Western Canada? Is this starting to shift a bit? in your view. That's it for me.

Thanks. Yeah, we think 2025 is going to be undersupplied throughout North America. And so we're very bullish on gas. That being said, we'll continue to be very careful. So we've got a whole series of projects, you know, some of which we're building right now that can add volume in 2025 and 2026. But we'll see what that mix of projects looks like as we watch the gas price strip progress here for the next three months or so. So, you know, we can add another three to five percent to our 2025 volumes, but we're not going to do that if the price isn't sufficient.

Yeah, I think bear in mind, Jamie, is how big some of these changes in 25 are, you know, in terms of how many LNG plants are sparring up, how strong domestic power consumption has been. And We've all been watching peer calls south of the border. The impetus for additional activity in the back half of this year is very low. We have an outlook for declines in the Hainesville. We have an outlook for flat or tailed volumes in Appalachia. We're not carrying really any productive momentum or any capital momentum into 2025. And so that's part of what we've kind of designed here is providing some optionality in Tourmaline to be able to react quickly if the opportunity arises. But as Mike was speaking to, you know, if we don't get lucky on weather or there are hiccups along the way, we can always move those volumes throughout the 25-year into a period where that price is starting to strengthen.

Okay, that's good color. Thank you.

Ladies and gentlemen, as a reminder, should you have a question, please press star followed by the one. Your next question comes from Dane Gregoris with Anvinus. Please go ahead.

Hey, guys, thanks for taking my question. I was wondering if you could comment on the California natural gas market, particularly in light of anticipated data center buildup.

Sure. I think Jamie's probably the most versant on that. We obviously really like the California market, and we've been building our volumes to access that market for almost 10 years now, so we're up to almost half a BCF a day. accessing that market. And it's one of the premium price markets in all of North America. At times it trades almost at LNG pricing. And Jamie, why don't you take it from there?

Yeah, so as Mike was saying, we're roughly a quarter of the market share up in Northern California. Prices really strengthened even just recently over the last couple of weeks. We've seen it rocket from twos to threes on just heat. And the consumption of gas during heat still remains really, really high. and basically is the main service of how they balance their grid after 6 p.m. is gas is basically carrying the vast majority of the weight there. And when we look at how the state is planned going forward, we also see the data center build there similar to other areas that we also sell gas to. We see data center ads in ERCOT and MISO and KAISA will be no different. We definitely see data centers queuing to try to grab additional capacity, which will put ever more demand on the gas there. But in addition to data centers, we actually think one of the more interesting aspects of California is how it interconnects with the Mexico LNG build-out. Much of the Mexico LNG build-out is Pacific-facing. There is interconnection with how those gas flows interact with Southern California and, to some extent, Northern California. We've been beginning to add some of our transport into SoCal to have access to both of those markets. And as those plants fire up, it's going to have an additional strain in that system, which could have definitely increased upside in pricing. And from our perspective, there's no view of increased volume into that state from new pipe or expanded pipe. So it's going to be a very, very tight system that has rewarded tourmaline with extremely strong gas prices in both winter and summer and years prior. And as we look forward for the next five to 10 years, we think that could definitely happen again. And it's never fully appreciated in strips. You kind of have to get into the weather event or the scenario that creates the tightness. And then much of those gains are enjoyed in cash. And so it's not something that really sits in our five-year plan. And that's actually true of most of our demand markets. That upside potential for cash flows to be bolstered by a weather event or a demand event has to kind of occur in the quarter you're in. And so it's an upside to the financial forecast we show that just basically dictates your pricing.

Thanks, guys. That's excellent. Appreciate it.

Thank you. There are no further questions at this time. I will now turn the call over. One moment, please. Your next question is from Anthony Linton with Jefferies. Your line is now open.

Hey, guys. Thanks a lot for taking my questions this morning. Just a quick one from me and building off some of the questions that have already been asked. Can you just talk about how you're thinking about your hedging profile moving into 2025, just with some of the volumes ticking up on the quarter? Thanks.

Typically, we don't go above 50% hedged of total volumes, but we can go above that level in certain markets, which we have at ACO and Station 2. It's the most hedged we've ever been hedged. through Q2 and Q3 of this year. And then as you look out, 25 and 26 will steadily add to those hedge volumes. We've seen a lot of action on the Kurds, particularly south of the border. We think 25 has been kind of artificially pushed down with some very large hedge volumes by operators in the U.S. But as that strip recovers, we'll look at adding more hedges to our 25 book. And, you know, we sell at 16 different hubs, and each hub is a little different, and we have strategies that revolve around each of those hubs and take advantage of various price dislocations in various timeframes. So we typically don't hedge very large volumes programmatically. We're very surgical and site-specific about our program.

And a little more open in the winter. And then also, these premium markets were generally a little less hedged, if you look across our hedge book there into 25 and 26.

Got it. Okay, that's helpful. Thank you.

Thank you.

Thanks. I don't know for the questions at this time. I will now turn the call over to Tour Milling for closing remarks.

Thanks, everyone. We'll talk to you next quarter. Appreciate the time. Thank you.

Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines.