Tourmaline Oil Corp.

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. 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.

Thank you, Operator, and welcome everyone to our discussion of Termaline's financial and operating results as of September 30, 2024, and for the three and nine months ending September 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 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, 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 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. Thanks, Scott. 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 per MCF Canadian. 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 26th to 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 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 C60A gas plant complex. 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. We anticipate 25 average production. We're using a range of between 635,000 and 665,000 BUEs a day at 650,000 BUEs 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, then we can increase EP activity, and it'll 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 0.4 times 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 30th, 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 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 2025, 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 2025 across all three EP complexes. and will save the incremental gas volumes for higher prices. Of note, the North Montney Phase 1 project is the only development project fully in the five-year plan, and it is still expected to add approximately 50,000 BOEs per day over the next three years. The Ground Birch, West Doe, and North Montney Phase 2 development projects 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 Ground Birch 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 805A benchmark of $0.70 per MCF. And we benefited, obviously, from our multi-year 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 a BCF a day hedged at a weighted average fixed price of $4.01 per MCF Canadian. And in 2025, we have an average of $947 million cubic feet per day hedged at a weighted average price of $4.58 per MCF Canadian. And we have a lot of volumes that we leave open or unhedged to our stronger priced export markets. Briefly on the 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 ducts 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. A big highlight for us is our deep basin well productivity. So far on IP 90s in 2024, we're up 20% on GAP and 40% on condensate over the average of the previous four years, 2020 through 2023. And the performance is attributed to multiple tier one 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. And as at September 30th of this year, the expiration program has added a little under 1,000 Tier 1 and Tier 2 drilling locations. And due to the ongoing success of the expiration program, we do continue in 2025. We can spend up to $150 million a free cash flow on expiration, but obviously there's complete flexibility around that spending. On our EPI, or environmental performance improvement efforts, 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. 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. 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 business. And we're pleased to announce that Travis Taves 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.

Thank you. Ladies and gentlemen, we'll now begin the question and answer session. Should you have a question, please press star followed by one 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 two. If you're using a speakerphone, please lift the handset before pressing any keys. One moment for your first question. Your first question comes from Michael Harvey with RBC Capital Markets. Please go ahead.

Yeah, sure. Good morning, guys. 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, you know, is gas $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.

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 in 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 pre-builds for both Ground Birch and West Aitken in the South Montney. And we'd like to do those. We also have pipelines at Ground Birch and in the North Montney Phase 1 up at 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 four 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?

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 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 that could result in a very, very capital efficient year. But we're thinking out a little bit longer here. We have a a view of a very, very high demand for gas in both 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 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. Perfect. Appreciate the color, guys. Thanks. Thank you.

Your next question comes from Josh Silverstein with UBS Financial. Please go ahead.

Thanks. Good morning, guys. Maybe just building on the duck 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?

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. We have moved more of our frack 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, you know, call it 40 to 50 ducks. 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.

Yeah, 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 frack 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.

Got it. Thanks for the call 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% 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 volumes showing up in the 2025 guide then?

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 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 have production.

And Josh, 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 of the strong well performance and generally not seeing low FF inflation. You know, 25 is colored, as Mike said, by facilities.

And I think we're having, I think the exit's stronger than what people were carrying previously for 24. Got it. Thanks, guys.

Your next question comes from Kalei Akamai with Bank of America. Please go ahead.

Hey, good morning, guys. Thanks for getting me on. I'm going to 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 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?

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.

I appreciate that, Mike. My second question is on the decision to build the ducts 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 product capital for the special and then come back when the market is more supportive?

Yeah, 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 two or three years, we've matched up to egress out of the basin so that we're not clogging up ACO 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.

I appreciate it. Thanks, Mike.

Yeah, you bet. Thanks.

Your next question comes from Fai Li with Audlum Brown. Please go ahead.

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 ACO strip pricing that's reflecting your five-year plan, particularly past 2025, do you see more upside with LNG Canada coming as they bring in demand?

Sorry, keep going.

I'm just wondering what your thoughts are on that. At $3 plus, it doesn't seem that exciting, but I'm just wondering if you have more thoughts.

Well, we agree with you. We think the ACO strip is understating what the impact of the ultimate startup of LNG Canada will do. We see almost all the volumes required for the initial 2 BCF a day in the system now, so that gas is going to get pulled west, 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 eco strip and the out years on the eco strip uh will improve but for now we always honor the strip in our guidance and our five-year plan so uh we'll live with it but uh i think there's certainly upside there 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

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

Thanks, Operator, and thanks, everyone, for your time today. We look forward to chatting with you in the next quarter.

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