Tourmaline Oil Corp

TSX:TOU

Earnings Call Analysis

Earnings Call Transcript 2024-Q3

[Operator]

good morning, ladies and gentlemen, and welcome to the Tourmaline Q3 2024 Results Conference Call. [Operator Instructions] This call is being recorded on Thursday, November 7, 2024.

I would now like to turn the conference over to 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 of September 30, 2024, and for the 3 and 9 months ended September 30, 2024, and 2023. My name is Scott Kirker, 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 those advisories.

I'm 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 with Mike speaking to some of the highlights of 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. Good morning, everybody, and we're pleased to update on a very busy and successful quarter.

So a few of the highlights. Third quarter cash flow was $742 million or $2.09 per diluted share, and that was underpinned by average realized natural gas prices of CAD 3.19 per Mcf. Q3 net earnings were $355 million or $1 even per diluted share. We've declared a special dividend of $0.50 per common share to be paid on November 26 to holders of record on November 15. And thus far this year, we have distributed dividends of $3.25 per share that includes this special dividend. And that's going back to December 1, 2023. So an implied 5% trailing yield.

During the quarter, we closed the previously announced transaction with Topaz Energy Corp. during this quarter, and we received $278 million of proceeds. We closed the corporate acquisition of Crew Energy on October 1, and we're very excited about those assets. And as we outlined in the release, Deep Basin well productivity so far in 2024 is the best we've seen in the last 5 years.

Looking at production. Q3 '24 average production was a little over 557,000 BOEs a day. That's an 11% increase over Q3 '23 and at the high end of our previously announced average production guidance for Q3 of 550,000 to 560,000 BOEs per day. And third quarter production was reduced by unplanned third-party outages, and we quantified that, as well as low gas price-related frac and production start-up deferrals by the company.

Fourth quarter average production of between 600,000 and 620,000 BOEs a day is currently anticipated. Given the low pricing environment, we scheduled and have now completed an extensive turnaround of both phases of our large Gundy C-60-A gas plant complex. And we've also concentrated frac activity into the latter half of this quarter so that unhedged gas volumes come for exit in Q1 of 2025, where we're expecting higher pricing than we have today.

We expect to exit with very strong production levels of between 630,000 and 640,000 BOEs per day, and we're right on track for that. We anticipate '25 average production, we're using a range of between 635,000 and 665,000 BOEs a day, at 650,000 BOEs per day at the midpoint. And that range allows for both price-related EP activity deferrals or shut-ins in the event of lower-than-anticipated '25 nat gas prices. And conversely, if stronger prices materialize, then we can increase EP activity. And it will all be within that range that we outlined.

'25 forecast average liquids production is 162,000 barrels per day. So that's up a little bit from what we were expecting before. And we're slowly migrating our way to that 200,000 barrel per day level by the end of this decade.

A little bit on the financial results. Third quarter cash flow was $742 million, as mentioned, on total CapEx of $591 million, EP expenditures subset of that, $575 million. And that generated free cash flow in the quarter of $152.5 million. We had strong earnings as mentioned, $1 per share, and that underscores the profitability of the business even in an extremely weak natural gas pricing environment.

Our exit Q3 '24 net debt was $1.7 billion. And we've adjusted our long-term net debt target to $1.5 billion, and that represents between 0.3 and 0.4x '25 net debt to cash flow ratio. And that's because of the material growth in the underlying business over the past year. In addition, as at September 30, our 45 million shares of Topaz have a market value of a little over $1.2 billion.

On '25 capital budget planning. The Board approved a full year '25 EP capital budget range to match that production range of between $2.6 billion and $2.85 billion. And the range provides flexibility in this current volatile and uncertain commodity price environment. We do continue to expect steadily improving natural gas prices in '25. But should the recovery materialize in the second half of the year, we can sequence the capital program to be back half-biased. And we'll always optimize annual free cash flow, and that's our top priority.

We expect to drill approximately, in the mid-case, 365 wells in '25 across all 3 EP complexes. And we'll save the incremental gas volumes for higher prices. Of note, the North Montney Phase 1 project is the only development project fully in the 5-year plan. And it is still expected to add approximately 50,000 BOEs per day over the next 3 years. The Groundbirch, West Doe and North Montney Phase 2 development projects will be fully integrated into the 5-year plan during the course of 2025. So they're not in there now, although some of the facility spending for both Groundbirch and West Doe are in the '25 capital budget range that we quoted.

On the marketing side, our average realized nat gas price was $3.19 per Mcf. So that was significantly higher than the AECO 5A benchmark of $0.70 per Mcf. And we benefited, obviously, from our multiyear diversification portfolio and our hedging strategy. We expect to exit this year with total exports of 1.27 Bcf per day out of the basin, and the majority of that is directed towards premium demand pull markets.

For November and December of '24, we have an average of just a little over 1 Bcf a day hedged at a weighted average fixed price of CAD 4.01 per Mcf. And in '25, we have an average of 947 million cubic feet per day hedged at a weighted average price of CAD 4.58 per Mcf. And we have a lot of volumes that we leave open and unhedged to our stronger-priced export markets.

Briefly on EP program. We drilled 76.8 net wells and completed 75.9 wells during the third quarter of '24. And we have an inventory of 38 DUCs entering the fourth quarter. Currently operating 16 drilling rigs across the 3 core EP complexes and anticipate full year '24 EP spending of about $2.1 billion.

A big highlight for us is our Deep Basin well productivity. So far on IP-90s in 2024, we're up 20% on gas and 40% on condensate over the average of the previous 4 years, 2020 through 2023. And the performance is attributed to multiple Tier 1 plays across several strike areas within the Deep Basin. So it's not the result of a series of wells in just one subarea, it's across the board.

And as at September 30 of this year, the exploration program has added a little under 1,000 Tier 1 and Tier 2 drilling locations. And due to the ongoing success of the exploration program, we do continue in 2025, we can spend up to $150 million of free cash flow on exploration. But obviously, that -- there's complete flexibility around that spending.

On our EPI, our environmental performance improvement efforts. As part of our ongoing joint venture with clean energy fuels, we opened new CNG fueling stations for long haul trucks both in Calgary and Grand Prairie. And the partnership expects to have 7 of those stations operational by the end of 2025. And that's a continuation of our multiyear diesel displacement initiative utilizing abundant lower-emission natural gas. So this improves the environment and builds gas demand.

In '25 and '26 in the budget, we have 3 new water facilities to be constructed, and that will bring our total to 9 as we slowly migrate all operations off any freshwater in our fracking business.

And we're pleased to announce that Travis Toews has been appointed to our Board of Directors effective yesterday.

And I think that's it for going through the press release, and we're more than happy to answer questions.

[Operator]

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

[Michael Harvey, analyst]

Just a quick one on your '25 guide. You touched on this a bit in the comments. You got a pretty good wide range in there. But just wondering if you could put some goalposts on kind of what pricing might correspond to the bottom and the top for folks? For instance, is gas at $1 at the bottom and $4 at the top or something like that?

And then just additionally, on the capital range, it looks to be a bit tighter just in terms of the implied efficiency. Just wondering what projects you would do more of or less of within that range, just to kind of manage those pricing dynamics as you get through the year?

[Michael Rose, executive]

Sure. Well, I think we're at the bottom end of the range if the current prices continue through the winter. We always have a chance to reset if need be in Q2. And the high end of the range, something north of $3 or $3.50 an Mcf.

We don't actually have formal numbers in there. I mean, remember that we actually make money at anything above $1.50, but we're always reticent to bring extra volumes into the market when it's weak. And so I think we've shown that discipline over the past couple of years.

Lots of flexibility around the capital spend. We've got almost $300 million of facility spending, if you like, in the '25 budget. That includes electrification projects, so the prebuilds for both Groundbirch and West Aitken in the South Montney. And we'd like to do those. We also have pipelines at Groundbirch and in the North Montney Phase 1 of Aitken. And so we'd like to knock off some of that in '25, and that's in the budget. But we have full flexibility around whether we do those or not.

If we have weak first half pricing, we'd probably carry on. If it looks like the second half is going to be stronger because of the implied demand growth that we see from the startup of the 4 North American LNG projects that are in the hopper. But we'll always solve for optimizing free cash flow, as we've demonstrated in the past.

Anything you want to add, Jamie, or...

[James Heard, executive]

I think the other thing that we can point to is there's quite a bit of capital in flight here. We're bringing in a good load of DUCs in the beginning of the year. And so if Tourmaline did choose to respond to lower prices at the lower range, we've got quite a bit of tailwind in terms of wells already in progress. That could result in a very, very capital-efficient year.

But we're thinking out a little bit longer here. We have a view of a very, very high demand for gas in both '25 and then '26 and '27, and we're kind of preparing for that. And so it's getting this momentum going that's been part of the strategy. And I think that's going to pay major dividends in '25 and '26, just to be able to respond. Because we look across the playing field here, especially in the U.S., and there's many, many businesses that are kind of flat to down.

[Operator]

Your next question comes from Josh Silverstein with UBS Financial.

[Joshua Silverstein, analyst]

Maybe just building on the DUC question. I think you had 36 entering the third quarter, 38 now. Where do you expect to be at the end of the year?

And I guess, along the same lines, last quarter, you had talked about going to a 15th rig. Why did you add to that in the fourth quarter given current gas prices?

[James Heard, executive]

I can grab DUCs, and we can all kind of chip in on rigs. So as the plan currently stands, we'll have roughly 35 DUCs carry out. We have moved more of our frac activity into the latter half of this quarter. And so we could have some move over the calendar year end into January, and so that can move around a little bit.

But in general, as you mentioned, we've been adding these rigs. And as you add rigs, you also add work-in-progress completions. And so in 2025, on currently contemplated activity, we're actually going to be carrying out, call it, 40 to 50 DUCs. So that's a larger number that's reflective of the larger activity rate that we would be carrying through the year. And that is something that we could use as a form of efficiency or basically a toggle in terms of thinking about some of these capital numbers.

[Michael Rose, executive]

Yes. And we'd always planned to add that 16th rig at some point in the fourth quarter. And we talked to that with our Q2 release, that we're going to get all the pads drilled out, and we can be flexible on when and if we frac them. And that's 60% of the capital associated with bringing a productive well in the Montney or Deep Basin on stream. So we retain that flexibility.

But our drilling performance has been great, our costs are actually down a little bit. And so we're quite comfortable getting the pads drilled out.

[Joshua Silverstein, analyst]

Thanks for the color there. And then as a follow-up, on the 2Q call, you had talked about lower cost coming in and volumes able to be kind of 3% to 5% above the prior outlook that you had given on improving well performance. I'm just curious then why isn't there a lower CapEx or higher volume showing up in the 2025 guide then?

[James Heard, executive]

Well, the higher CapEx is mostly facility associated or exploration dollars that we may or may not spend. And so we don't associate volumes with those. So you'll see those volumes in '26 and '27 with the major facility startups that we'll experience. But that's why it's all facility spend. It's not going to add production.

[Michael Rose, executive]

And Josh, like if you take a look at this year, I would say volumes, we're really happy with, especially for instance third quarter volumes. And capital continues to come in under expectations. So our lived experience is exactly what you say, enjoying those efficiencies with a strong well performance and generally not seeing all of that inflation, '25 is colored, as Mike said, by facilities. And I think we're having -- I think the exit is stronger than what people were carrying previously for '24.

[Operator]

Your next question comes from Kalei Akamine with Bank of America.

[Kaleinoheaokealaula Akamine, analyst]

I'm going to follow up on a couple of things here. I guess, firstly, my first question is on the '25 guide. From our perspective, production could have been a touch higher proportion to the spend when we consider the progress that you guys have made on the facilities capital side and the productivity side, with Alberta Deep Basin kind of being the case in point. So my question is, what efficiencies have you realized recently? Are they underwritten in this budget? And why wouldn't there be upside to your '25 guide?

[Michael Rose, executive]

Well, we have left some upside in the '25 guide, and we haven't carried through the well performance in the Deep Basin that we've experienced in '24 yet. So we're trying to -- tend to be a little bit more conservative. And we'll see how it plays out.

[Kaleinoheaokealaula Akamine, analyst]

I appreciate that, Mike. My second question is on the decision to build the DUCs in the first half of the year. I get wanting to be ready to respond to higher prices, but it seems that your peers are already taking that position. So maybe rather than push more molecules into the basin, why not save that drilling and frac capital for the special, and then come back when the market is more supportive?

[Michael Rose, executive]

Yes. I mean, that's a good point. We've decided to get the pads drilled out so that we can respond. Bear in mind that most of the gas growth that we've accomplished over the past 2 or 3 years, we've matched up to egress out of the basin so that we're not clogging up AECO and Station 2. And we do realize good prices with those volumes, particularly going to California or down to the Gulf Coast with our modest LNG volumes that began in January of 2023.

[Operator]

Your next question comes from Fai Lee with Odlum Brown.

[Fai Lee, analyst]

Mike, I'm just wondering, not looking for a forecast or predictions, but just wondering if you have any thoughts on the AECO strip pricing that's reflected in your 5-year plan, particularly top 2025, do you see more upside with LNG Canada coming -- demand...

[Michael Rose, executive]

Keep going, sorry.

[Fai Lee, analyst]

Yes, yes. No, I'm just wondering what your thoughts are on that, right? At $3 gas, it doesn't seem that exciting. But I'm just wondering if you have more...

[Michael Rose, executive]

Well, we agree with you. We think the AECO strip is understating what the impact of the ultimate start-up of LNG Canada will do. We see most -- almost all the volumes required for the initial 2 Bcf a day in the system now. So that gas is going to get pulled left, and we don't think that's reflected in the current differential at all. So we expect that to snap back in when appreciable volumes are getting shipped west, and that the AECO strip in the out years on the AECO strip will improve. But for now, we always honor the strip in our guidance and our 5-year plan. So we'll live with it, but I think there's certainly upside there.

[Fai Lee, analyst]

Okay. I appreciate it. I know you use the strip, but I just was curious about that.

[Michael Rose, executive]

Yes. Sometimes, we'd like not to.

[Operator]

There are no further questions at this time. I would like to turn the call back over to Scott Kirker.

[W. Kirker, executive]

Thanks, operator. And thanks, everyone, for your time today. We look forward to chatting with you at the end of next quarter.

[Operator]

Ladies and gentlemen, this concludes today's conference call. Thank you for your participation. You may now disconnect.