Q3 2024 Tourmaline Oil Corp Earnings Call
Good morning, ladies and gentlemen, and welcome to the Tourmaline Q3 2024 Results Conference Call. At this time, all lines are in listen-only mode. Following the presentation, we'll conduct a question-and-answer session. If at any time during this call you require immediate assistance, please press star zero for an operator.
Speaker Change: This call is being recorded on Thursday, November 7th, 2024. I would now like to turn the conference over to Scott Kirker. Please go ahead.
Scott Kirker: Thank you, Operator, and welcome everyone to our discussion of Termline's financial and operating results as of September 30, 2024, and for the three and nine months ended September 30, 2024 and 2023.
My name is Scott Kirker and I'm the Chief Legal Officer here at Tourmaline Oil.
Scott Kirker: 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 CDAR and on our website. I also draw your attention to the material factors and assumptions in those advisories.
Scott Kirker: 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.
Scott Kirker: Thanks a lot. 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 $209 per diluted share, and that was underpinned by average realized natural gas prices of $319.
Scott Kirker: 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.
Scott Kirker: Two holders of record on November 15th and thus far this year We've 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 1st, 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 five 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 frack and production startup deferrals by the company.
Fourth quarter average production of between 600 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-60A gas plant complex.
Scott Kirker: And we've also concentrated frack activity into the latter half of this quarter so that unhedged gas volumes come for exit and Q1 of 2025. 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.
Scott Kirker: 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 net gas prices, and conversely, if stronger prices materialize.
Scott Kirker: 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 you know by the end of this decade.
A little bit on the financial results.
Scott Kirker: Third quarter cash flow was $742 million, as mentioned, on total CapEx of $591 million. EP expenditures, a subset of that, $575 million. And that generated free cash flow in the quarter of $152.5 million.
Scott Kirker: 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.
Scott Kirker: 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 0.4 times 25 net debt to cash flow ratio.
Scott Kirker: 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.
Scott Kirker: 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 and 2.85 billion and the range provides flexibility in this current volatile and uncertain commodity price environment.
Scott Kirker: We do continue to expect steadily improving natural gas prices in 2025, but should the recovery materialize in the second half of the year, we can sequence the capital program to be back half biased.
Scott Kirker: And we'll always optimize annual free cash flow, and that's our top priority.
Scott Kirker: We expect to drill approximately, in the mid-case, 365 wells and 25 across all three EP complexes and we'll save the incremental gas volumes for higher prices.
Scott Kirker: Of note, the North Montney Phase 1 project is the only development project fully in the five-year plan.
Scott Kirker: And it is still expected to add approximately 50,000 BOEs per day over the next three years.
Scott Kirker: will be fully integrated into the five-year plan during the course of 2025. So they're not in there now, although some of the facility spending for both Groundwork and West Doe are in the 25 capital budget range that we quoted.
Scott Kirker: On the marketing side, our average realized nat gas price was $3.19 per MCF, so that was significantly higher than the 805A benchmark of $0.70 per MCF.
Scott Kirker: and we benefited obviously from our multi-year diversification portfolio and our hedging strategy.
Scott Kirker: 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.
Scott Kirker: For November and December of 2024, we have an average of just a little over a BCF a day hedged at a weighted average fixed price of $4.01.
for MCF Canadian.
Scott Kirker: And in 2025, we have an average of 947 million cubic feet per day hedged at a weighted average price of $4.5 billion.
Scott Kirker: $4.58 per MCF Canadian and we have a lot of volumes that we leave open or unhedged to our stronger priced export markets.
Scott Kirker: Briefly on the EP program, we drilled 76.8 net wells and completed 75.9 wells during the third quarter of 2004.
Scott Kirker: and we have an inventory of 38 ducks entering the fourth quarter. Currently operating 16 drilling rigs across the three core EP complexes and anticipate full year 24 EP spending of about $2.1 billion.
Scott Kirker: A big highlight for us is our deep basin well productivity.
so far on IP90s in 2024.
Scott Kirker: We're up 20% on gas and 40% on condensate over the average of the previous four years, 2020 through 2023.
Scott Kirker: 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 sub-area, it's across the board.
Scott Kirker: And as of September 30th of this year, the exploration program has added a little under a thousand Tier 1 and Tier 2 drilling locations.
Scott Kirker: And due to the ongoing success of the expiration program, we do continue in 2025, we can spend up to $150 million of free cash flow on expiration, but obviously there's complete flexibility around that spending.
Scott Kirker: as part of our ongoing joint venture with Clean Energy Fuels.
We open new CNG fueling stations for long haul trucks.
both in Calgary and Grand Prairie.
Scott Kirker: And the partnership expects to have seven of those stations operational by the end of 2025. And that's a continuation of our multi-year diesel displacement initiative, utilizing abundant lower emission natural gas. So this improves the environment and builds gas demand.
Scott Kirker: In 2025 and 2026 in the budget we have three new water facilities to be constructed and that'll bring our total to nine as we slowly migrate all operations off any fresh water in our fracking.
Scott Kirker: business and we're pleased to announce that Travis Cage 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.
Speaker Change: Thank you. Ladies and gentlemen, we will now begin the question-and-answer session. Should you have a question, please press star followed by 1 on your touchtone phone. You'll hear a prompt that your hand has been raised. Should you wish to remove your raised hand from the queue, please press star followed by 2.
Speaker Change: If you're using a speakerphone, please lift the handset before pressing any keys. One moment for your first question.
Speaker Change: Your first question comes from Michael Harvey with RBC Capital Markets. Please go ahead.
Speaker Change: Yeah, sure, good morning guys. Just a quick one on your 25 guide. You touched on this a bit in the comments. You've got a pretty good wide range in there. But just wondering if you could put some goal posts on kind of what pricing might correspond to the bottom and the top for folks. For instance, you know, is gas at $1 at the bottom and $4 at the top or something like that?
Scott Kirker: 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.
Speaker Change: continue through the winter. We always have a chance to reset.
if need be in Q2.
Speaker Change: 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 years.
Speaker Change: 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
Scott Kirker: electrification projects, so the pre-builds for both Ground Birch and West Aitken in the South Montagne and we'd like to do those. We also have pipelines at Ground Birch.
Scott Kirker: and in the North Monty Phase 1 up at Aitkin. And so we'd like to knock off some of that in 2025 and that's in the budget, but we have full flexibility around whether we do those or not.
Scott Kirker: If we have weak first half pricing, we'd probably carry on. If it looks like the second half is gonna be stronger because of the.
Scott Kirker: implied demand growth that we see from the startup of the foreign North American.
LNG projects that are
Scott Kirker: In the hopper, but you know, we'll always solve for optimizing free cash flow as we've demonstrated in the past
Anything you want to add, Jamie?
Jamie Heard: 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
Speaker Change: a good load of ducks 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.
Speaker Change: 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.
Speaker Change: for gas in well 25 and 26 and 27 and we're kind of preparing for that and so it's getting this momentum going has been part of the strategy and I think that's going to pay
Speaker Change: major dividends in 25 and 26 just to be able to respond because we look across, you know, the playing field here, especially in the U.S., and there's many, many businesses that are kind of flapped down.
Perfect. Appreciate the color, guys. Thanks. Thank you.
Speaker Change: Your next question comes from Josh Silverstein with UBS Financial. Please go ahead.
Josh Silverstein: Thanks, good morning guys. Maybe just building on the duck question, I think you had...
Speaker Change: 36 entering the third quarter, 38 now. Where do you expect to be at the end of the year?
Speaker Change: 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?
Speaker Change: I can grab ducks and we can all kind of chip in on rigs. So, as the plan currently stands, we'll have roughly 35 ducks carry out.
Speaker Change: We have moved more of our FRAC activity into the latter half of this quarter and so we could, you know, 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.
Speaker Change: And so, in 2025, on currently contemplated activity, we're actually going to be carrying out, you know, call it 40 to 50 ducks.
Speaker Change: 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.
Speaker Change: Yeah, and we'd always planned to add that 16th rig at some point in the fourth quarter, and we talked to that.
Speaker Change: 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 frack them. And that's 60% of the capital associated with bringing.
Speaker Change: 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.
Speaker Change: Good, thanks for the color there. And then as a follow-up, on the 2Q call you had talked about lower costs coming in and volumes able to be kind of 3 to 5 percent 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?
Speaker Change: Well, the higher capex is mostly facility associated or expiration dollars that we may or may not spend And so we don't associate volumes with those So you'll see those volumes in in 26 and 27 with the major facility startups That will experience but that's why it's all facility spent. It's not
going to have production.
Speaker Change: 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.
Speaker Change: and Capital continues to come in under expectations. So our lived experience is exactly what you say, enjoying those efficiencies of the strong well performance and generally not seeing offset inflation. You know, 25 is colored, as Mike said, by facilities.
Speaker Change: And I think we're having, I think the exit is stronger than what people were carrying previously for 24.
Thanks guys.
Speaker Change: Your next question comes from Kalei Ackermine with Bank of America. Please go ahead.
Speaker Change: Hey, good morning guys. Thanks for getting me on. I'm gonna follow up on a couple of things here. I guess firstly, our 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
Speaker Change: 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?
Speaker Change: 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.
Speaker Change: I appreciate that, Mike. My second question is on the decision to build the ducks in the first half of the year. I get wanting to be ready to respond to higher prices.
Speaker Change: 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 prod capital for the special and then come back when the market is more supportive?
Speaker Change: 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
Speaker Change: We've accomplished over the past two or three years, we've matched up the egress out of the basin, so that we're not clogging up ECO 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.
began in January of 2023.
I appreciate it. Thanks, Mike. Yeah, you bet. Thanks.
Your next question comes from Fai Lee
Speaker Change: Thank you. Mike, I'm just wondering, you know, not looking for a forecast or prediction, but I'm just wondering if you have any thoughts on the equal strip pricing that's reflecting your five-year plan, particularly
Speaker Change: past 2025? Do you see more upside with LNG Canada coming on?
as well.
Speaker Change: At $3 plus, it doesn't seem that exciting, but I'm just wondering if you have more. Well, we agree with you. We think the EcoStrip is.
understating what the impact of
Speaker Change: the ultimate startup of LNG Canada will do. We see almost all the volumes required for the initial two BCF a day in the system now, so you know that gas is going to get pulled west.
and we don't think that's reflected in the current differential.
Speaker Change: and that the eco-strip and the out-years on the eco-strip will improve. But for now, we always honour the strip in our guidance and our five-year plan, so we'll live with it, but I think there's certainly upside there.
Speaker Change: Okay, I appreciate it. I know you use a strip, but I just was curious about that. Thanks. Yeah, sometimes we'd like not to.
Speaker Change: There are no further questions at this time. I would like to turn the call back over to Scott Kirker.
Scott Kirker: Thanks operator and thanks everyone for your time today. We look forward to chatting with you the end of next quarter
Speaker Change: Ladies and gentlemen, this concludes today's conference call. Thank you for your participation. You may now disconnect.