Tourmaline Oil Q2 2024 Earnings Call Transcript

Quartr
Provided by Quartr
August 1, 2024

There are 7 speakers on the call.

Operator

Good morning, ladies and gentlemen, and welcome to the Tourmaline Q2 twenty twenty four Results Conference Call. At this time, all lines are in listen only mode. Following the presentation, we will conduct a question and answer session. This call is being recorded on Thursday, August 1, 2024. I would now like to turn the conference over to Scott Kirker.

Operator

Please go ahead.

Speaker 1

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 6 months ended June 30, 20242023. My name is Scott Kirkland, I'm the Chief Legal Officer here at Tourmaline Before we get started, I refer you to the advisories and forward looking statements contained in the news release as well as the advisories contained in the Tourmaline Annual Information Form and our MD and A that's available on SEDAR and on our website. I'll 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 Hurd, 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.

Speaker 1

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

Speaker 2

Thanks, Scott, and thanks, everybody on the line. So firstly, a few highlights. 2nd quarter average production of 5 62,000 BOEs a day was up 13% over Q2 'twenty 3 and within our Q2 'twenty 4 average production guidance range. Our 2nd quarter cash flow was CAD755 1,000,000 or CAD2.12 per diluted share on EP expenditures of $307,000,000 in the second quarter. And that generated free cash flow of $434,000,000 or $1.22 per diluted share.

Speaker 2

Given the strong continued free cash flow generation in the 2nd quarter and the full year financial outlook, we elected to increase the quarterly base dividend effective Q3 'twenty four by 3 percent to $0.33 per share or 1 point

Speaker 3

$3.2 per share on an annualized basis, and that's our 3rd

Speaker 2

base dividend increase of the year. We also declare and pay a special dividend of $0.50 per share on August 21 this year. And importantly, we reduced net debt by $137,000,000 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.

Speaker 2

Our full year 'twenty four average production guidance range has been revised to 575,000 to 585,000 BOEs a day, down 5,000 from the 580,000 to 590 previously. This will account for select 3rd quarter frac deferrals into Q4 as we ship 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 'twenty four cash flow and actually a positive impact on 'twenty five cash flow and free cash flow based on current strip prices. Looking a little deeper at the financial results, we realized Q2 'twenty four net earnings of $257,000,000 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 $1,200,000,000 to 1,400,000,000 dollars and we intend to continue to make progress towards that target through 2024.

Speaker 2

And as mentioned, we did reduce net debt by 137,000,000 dollars in the quarter. Also, our 45,100,000 shares of Topaz has a market value of around 1,100,000,000 dollars as at June 30. On marketing, Tourmaline's average realized natural gas price in the second quarter was CAD3.03 per Mcf, significantly higher than the AECO 5A index price of CAD1.20 per Mcf over the same period as 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.

Speaker 2

We have reduced both AECO and Station 2 exposure for the second half of 'twenty four 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 Q2, 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 Q4 and we'll run the 15 rigs through to 2025 spring breakup. So we'll end up drilling more multi well pads and what's currently in the EP plan for second half of twenty twenty four and first half twenty twenty five.

Speaker 2

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 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 $2,000,000,000 due to these steadily improving drilling efficiencies.

Speaker 2

As mentioned, given current weak natural gas prices, we've shifted some originally planned well stimulation activity from the Q3 to the 4th quarter of 'twenty four. 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 weak AECO pricing at that time, and that's approximately $100,000,000 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 and P, an update on our North Montney development.

Speaker 2

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 service both the Phase 1 and ultimately the Phase 2 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.

Speaker 2

The total capital cost for that project is approximately $70,000,000 And when we did our budget reduction in March of this year, we left that project in. The second, the Burge 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 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 10000 to 15000 BOEs a day in 2025 through completion of the ongoing 24 facility projects.

Speaker 2

Ultimately, the North Monty 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 this year for a total of 3 15 new drilling permits in Northeast PC since January 1, 2023. Looking at our EPI or Environmental Performance Improvement, the company's diesel displacement initiative and drilling and completion operations has displaced approximately 152,000,000 liters of diesel and replaced it with nat gas and that saved us approximately $150,000,000 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 or CNG and long haul trucks continues with 1 station now fully operational in Edmonton and there's 4 other stations that are under construction and we expect them to be operating in the Q1 of 2025.

Speaker 2

So this initiative is 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 $15,000,000 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

Thank you. Ladies and gentlemen, we will now begin the question and answer Your line is now open.

Speaker 4

Yes, 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?

Speaker 4

Any color on that would be helpful. And then the second one, just more macro related. Strip still above $325,000,000 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 look to accelerate?

Speaker 4

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.

Speaker 2

Okay. Yes. Thanks, Mike. I'll start. On drilling costs, our costs are certainly lower than they were in the previous cycle.

Speaker 2

So we renegotiate during the Q2 and then fix our costs for kind of 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 rig. 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.

Speaker 2

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 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 twenty twenty five.

Speaker 2

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.

Speaker 4

Great. Thanks, Mike.

Operator

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

Speaker 5

Thanks. Good morning, guys. 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?

Speaker 5

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? Thanks.

Speaker 2

You bet. Well, our free cash flow funds dividends, debt reduction, midstream investments, expiration and share buyback. So we were very happy with the amount of free cash flow that we had in the Q2, 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.

Speaker 6

I mean, 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 'twenty four by any means. So we'll continue to work on it through 'twenty five 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 question. That's helpful. And then, is there question.

Speaker 5

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

Speaker 2

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.

Speaker 2

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 2021.

Speaker 5

Great. Thanks. 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 execute that 5 year

Speaker 2

development plan. And we always execute that 5 year development plan. And we always time the North Montney development Phase 1 to the startup 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.

Speaker 2

And west.

Operator

Your next question comes from Jamie Kubik with CIBC.

Speaker 3

Just similar to an earlier question that you had there, you do mentioned 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?

Speaker 3

Is this starting to shift a bit in your view? That's it for me. Thanks.

Speaker 2

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 2025 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.

Speaker 2

Okay. Thanks. I think bear in mind, Jamie, is how big some of these changes in 2025 are in terms of 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.

Speaker 2

We have an outlook for declines in the Haynesville. We have an outlook for flat to curtailed volumes in Appalachia. We're not carrying really any productive momentum or any capital momentum in the 25%. And so that's part of what we have 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.

Speaker 2

Okay, that's good color. Thank you.

Operator

Your next question comes from Dane Gregorist with Anvinas. Please go ahead.

Speaker 3

Hey, guys. Thanks for taking my question. I was wondering if you could comment on the California natural gas market, up?

Speaker 2

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.

Speaker 2

And Jamie, why don't you take it from there? Yes. 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 2s to 3s 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 pm is gas is basically carrying the vast majority of the weight there.

Speaker 2

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 adds in ERCOT and MISO and Kyso 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, 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 specific facing.

Speaker 2

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.

Speaker 2

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 show that just basically dictates strip pricing.

Speaker 3

There are

Operator

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.

Speaker 2

Just a quick one for 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 AECO and Station 2. Is the most hedged we've ever been through Q2 and Q3 of this year.

Speaker 2

And then as you look out '25 and 'twenty six, 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 'twenty five book.

Speaker 2

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 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

Speaker 6

And then also these premium markets were generally a little less hedged if you look across our hedge book there into 2025 and 2026.

Speaker 2

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

Operator

There are no further questions at this time. I will now turn the call over to Tore Milling for closing

Speaker 1

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

Speaker 6

Thank you.

Operator

Ladies and gentlemen, this concludes your conference call for today. We thank you for participating in Assa. Please disconnect your lines.

Powered by Quartr
Earnings Conference Call
Tourmaline Oil Q2 2024
00:00 / 00:00