Tourmaline Oil Corp

TSX:TOU

Earnings Call Analysis

Tourmaline sees increased production, stronger financials in Q2 2024

Tourmaline reported solid financial and operational performance in Q2 2024. Average daily production rose 13% year-over-year to 562,000 BOEs. Cash flow was robust at $755 million, generating $434 million in free cash flow. Responding to strong cash flow, the company raised its quarterly dividend by 3% to $0.33 per share and declared a special dividend of $0.50 per share. Net debt was reduced by $137 million. Despite revised full-year production guidance, the company anticipates minimal impact on 2024 cash flow and positive effects on 2025 cash flow due to expected stronger natural gas prices.

Strong Production Growth

Tourmaline's Q2 2024 saw a significant 13% increase in production, reaching an average of 562,000 barrels of oil equivalent per day (BOEs/d) compared to the same period last year. Despite low natural gas prices, the company managed to maintain production within its guidance range, demonstrating strong operational efficiencies.

Solid Financial Performance

The company reported substantial cash flow of $755 million or $2.12 per diluted share, with EP expenditures at $307 million for the quarter. This resulted in a robust free cash flow of $434 million or $1.22 per diluted share. The strong cash flow generation enabled Tourmaline to increase its quarterly base dividend by 3% to $0.33 per share, and declare a special dividend of $0.50 per share.

Debt Reduction Efforts

Tourmaline made significant strides in reducing its net debt, cutting it down by $137 million during Q2. The company remains committed to its long-term net debt target of $1.2 billion to $1.4 billion, with plans to continue reducing debt through 2024.

Revised Production Guidance

Due to lower natural gas prices and strategic deferrals, Tourmaline adjusted its full-year 2024 production guidance to 575,000-585,000 BOEs/d. This slight reduction aims to position the company more favorably for anticipated stronger natural gas prices in late 2024 and early 2025, with minimal expected impact on the 2024 cash flow.

Hedging and Market Diversification

Tourmaline's average realized natural gas price was CAD 3.03 per Mcf in Q2 2024, significantly outperforming the AECO 5A index price. The company continues to grow its export volumes, expecting to exit 2024 with 1.26 Bcf per day. Tourmaline has hedged 1.03 Bcf per day for 2024 at an average of CAD 4.66 per Mcf to mitigate market volatility.

Investments in Growth and Efficiency

Tourmaline drilled 47 net wells and completed 38 wells in Q2, increasing its DUC inventory to 36 wells. The company plans to add a 15th drilling rig in Q4 and maintain this number through early 2025, capitalizing on improved drilling efficiencies and lower costs.

Strategic Facility Projects

The North Montney Phase 1 development is progressing well, with key facility components expected to enhance production capacity by 50,000 BOEs/d over the next three years. The first phase includes a condensate hub and the Birch a-44-I compressor station expansion, which alone will add 6,000 BOEs/d by 2025.

Environmental Initiatives

Tourmaline's diesel displacement initiative has saved approximately $150 million by replacing 152 million liters of diesel with natural gas since 2017. The company continues to invest in methane reduction technologies, supported by a recent $15 million grant from the Alberta government.

Market Outlook and Shareholder Returns

Tourmaline remains optimistic about future natural gas prices, anticipating North American undersupply in 2025. The company is strategically positioned to increase 2025 production volumes if prices are favorable. Shareholder returns are prioritized, with potential for further special dividends and tactical buybacks depending on market conditions.

Earnings Call Transcript 2024-Q2

[Operator]

Good morning, ladies and gentlemen, and welcome to the Tourmaline Q2 2024 Results Conference Call. [Operator Instructions] This call is being recorded on Thursday, August 1, 2024.

I would now like to turn the conference over to Mr. Scott Kirker. Please go ahead.

[W. Kirker, executive]

Thank you, operator, and welcome, everyone, to our discussion of Tourmaline's financial and operating results as at June 30, 2024, and for the 3 and 6 ended June 30, 2024 and 2023. 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 that's available on SEDAR and on our website. I also draw your attention to the material factors and assumptions in those advisories. I am here with Mike Rose, Tourmaline's President and Chief Executive Officer; Brian Robinson, our Chief Financial Officer; and Jamie Heard, Tourmaline'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.

After Mike's remarks, we will be open for questions. Go ahead, Mike.

[Michael Rose, executive]

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 $2.12 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 for the year.

We also declare and pay a special dividend of $0.50 per share on August 21 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 the Dawn, Ontario.

Our full year '24 average production guidance range has been revised to 575,000 BOEs to 585,000 BOEs a day, down 5,000 BOEs from the [ 580,000 to 590,000 BOEs ] previously. This will account for select third quarter frac 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 deferrals 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 billion to $1.4 billion, and we intend to continue to make progress towards 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 at June 30.

On marketing, Tourmaline's average realized natural gas price in the second quarter was CAD 3.03 per Mcf, significantly higher than the AECO 5A index price of $1.20 per Mcf over the same period. And we benefited from our multiyear market diversification and transportation portfolio. We keep growing our export volumes and now expect to exit '24 with a total of 1.26 Bcf 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 CAD 4.66 per Mcf. We have reduced both AECO 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 DUC 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 '25 -- 2025 spring breakup. 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 are continuously improving drill times.

We'll be positioned to deliver production above currently estimated 2025 levels. And of course, that will 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 the 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 '24. 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 a weak AECO pricing at that time, and that's approximately $100 million per day.

And over the past 3 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 2 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 serve as both the Phase I and ultimately, the Phase II North Montney developments, and it provides 20,000 barrels per day of condensate mercaptan treating and 70,000 barrels of condensate storage and we'll 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 a-44-I 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 a-20-I (sic) [a-21-I] compressor expansion that will 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 10,000 to 15,000 BOEs a day in '25 through completion of the ongoing '24 facility projects. Ultimately, the North Montney Phase 1 development will add 50,000 BOEs a day over the next 3 years.

Of note, the company has received an additional 63 drilling permits since March 6 of this year for a total of 315 new drilling permits in Northeast B.C. since January 1, 2023.

Looking at our EPI, our environmental performance improvement, the company's diesel displacement initiative and drilling and completion operations has displaced approximately 152 million liters of diesel and replaced it with nat gas, and that saved us approximately $150 million in that 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 4 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 invested 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.

[Operator]

[Operator Instructions] Your first question comes from Michael Harvey with RBC Capital Markets.

[Michael Harvey, analyst]

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's 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 strips still above $3.25 in 2025. If you were to see that drop, is there a price where you pulled back on growth? And I guess just on the flip side, is there a higher price where you 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 is most suited all in context of your marketing, of course, but that's it for me.

[Michael Rose, executive]

Okay. Yes. Thanks, Mike. I'll start. On drilling costs, our costs are certainly lower than they were in the previous cycle. So we renegotiated during the second quarter and then fixed our costs for kind of July 1 through to next breakup and they are down. And I can't speak for everyone else in the industry, but -- so we're realizing lower costs. And that gets coupled with the improving drill times, and so we do think it's a good time to add that extra rate.

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 breaks. 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 3 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 2 hubs AECO and Station 2 when prices are low.

[Operator]

Your next question comes from Josh Silverstein with UBS.

[Joshua Silverstein, analyst]

Just wanted to focus on shareholder 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 shareholder return equation as well?

[Michael Rose, executive]

You bet. Well, our free cash flow funds, dividends, debt reduction, midstream investments, expiration and share buybacks. So 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.

[Unknown Executive]

And 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 billion to $1.4 billion 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 acted a bit of a counterweight to the net debt question.

[Joshua Silverstein, analyst]

That's helpful. And then is there any shift in thinking about the buybacks versus dividends?

[Michael Rose, executive]

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 the 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.

[Joshua Silverstein, analyst]

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

[Michael Rose, executive]

Well, we'll end up with more AECO and Station 2 exposure as we execute that 5-year development plan. And we'd always time the North Montney development Phase I to the start-up of LNG Canada because we do think that will be structurally positive for in-basin pricing here at the 2 hubs when you pull ultimately 2 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.

[Operator]

Your next question comes from Jamie Kubik with CIBC.

[James Kubik, analyst]

Just similar to an earlier question that you had there. You do mention some productive upside in 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 China 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.

[Michael Rose, executive]

Yes. 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, some of which we're building right now that can add volume in '25 and '26, but we'll see what that mix of projects looks like as we watch the gas price strip progress here for the next 3 months or so. So we can add another 3% to 5% to our 2025 volumes, but we're not going to do that if the price isn't sufficient. Bear in mind, Jamie, is how big some of these changes in '25 are in terms of how many LNG plants are aspiring 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 Haynesville.

We have an outlook for flat to curtail volumes in Appalachia. We're not carrying really any productive momentum or any capital momentum into '25. 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, 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.

[Operator]

[Operator Instructions] Your next question comes from Dane Gregoris with Enverus.

[Dane Gregoris, analyst]

I was wondering if you could comment on the California natural gas market, and particularly in light of anticipated data center buildout?

[Michael Rose, executive]

Sure. I think Jamie is 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 0.5 Bcf a day accessing that market, and it's one of the premium priced markets in all of North America at times it trades almost at LNG pricing. And Jamie, why don't you take it from there?

[Jamie Heard, executive]

Yes. So as Michael was saying, we're roughly 1/4 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 2 to 3, 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 6:00 p.m. as gas is basically carrying the vast majority of the weight there. And when we look at how the state is plan 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 CISA 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 buildout.

Much of the Mexico LNG buildout is specific 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 stream 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 5 to 10 years, we think that could definitely happen again. And it's never fully appreciated in strip. 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 5-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 showed that just basically dictates your pricing.

[Operator]

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.

[Anthony Linton, analyst]

Just a quick one for me in 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 picking up on the quarter?

[Michael Rose, executive]

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 AECO and Station 2, it's the most hedge we've ever been through Q2 and Q3 of this year. And then as you look out '25 and '26, we'll steadily add to those hedge volumes. We've seen a lot of action on the curves, 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 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 time frames. So we typically don't hedge very large volumes programmatically. We're very surgical and site specific about our program.

[Unknown Executive]

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

[Operator]

Are no further questions at this time. I will now turn the call over to Tourmaline for closing remarks.

[W. Kirker, executive]

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

[Operator]

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