Tourmaline Oil Corp. (TOU) Earnings Call Transcript & Summary

Good morning, ladies and gentlemen, and welcome to the Tourmaline Q4 2024 Results Conference Call. [Operator Instructions] This call is being recorded on Thursday, March 6, 2024. I would now like to turn the conference over to Scott Kirker. Please go ahead.

Thank you, Lina, and welcome, everyone, to our discussion of Tourmaline's financial and operating results for the 3 months and years ended December 31, '24 and December 31, '23. My name is Scott Kirker, I'm 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 advisers. 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 by speaking to some of the highlights of the last year, and after Mike's remarks, we will be open for questions. Go ahead, Mike.

Thanks, Scott. Good morning. Thanks, everyone, for dialing in. We're pleased to review our most recent results and provide the latest outlook and answer some questions. First, a few highlights. 2025 forecast free cash flow is now $1.4 billion based on current strip pricing, and that's up from previous guidance of $1.1 billion. Full year 2024 net earnings were $1.3 billion or $3.51 per diluted share, and that underscores the profitability of the business even in a very weak gas price environment. And to that end, we delivered strong earnings and free cash flow in 2024 during what turned out to be the worst AECO full year pricing environment in the last 25 years. We're very pleased to announce a quarterly base dividend increase of 43% to $0.50 per share, that's effective Q1 '25, and a special dividend of $0.35 per share. With continued growth in the base business and continued improvements in realized pricing, we're well positioned to increase returns to shareholders in 2025 relative to 2024. First quarter '25 production range of 630,000 to 635,000 BOE per day is currently anticipated. PDP reserves were increased 29% in 2024 after accounting for production and 2P reserves were increased 14% to 5.5 billion BOEs by the end of 2024. A few comments on production. Fourth quarter '24 average production was 605,000 BOEs per day, up 9% from the corresponding 2023 quarter. '24 average liquids production of 138,500 barrels per day was up 17% over 2023. Condensate and NGL production volumes are expected to increase significantly over the next 5 years with our North Montney, West Doe-Groundbirch, South Montney and North Deep Basin infrastructure projects. These projects will grow both our total volumes and materially improve our realized corporate margins. The '25 forecast production range of 635,000 to 665,000 BOEs per day remains unchanged. And the company expects to finalize the second half '25 EP capital program during the second quarter, and we'll see where gas prices are at over the next 3 months or so. As mentioned, first quarter '25 production of 630,000 to 635,000 BOEs per day is anticipated. We have approximately 51 wells to bring on production in March, which is expected to result in first quarter exit volumes well in excess of 640,000 BOEs per day. Some select financial highlights. Improving strip prices have increased full year forecast '25 cash flow to $4.3 billion. And as mentioned, full year forecast '25 free cash flow is now $1.4 billion. Full year 2024 cash flow was $3.2 billion, and full year '24 free cash flow was $1 billion. And as mentioned, given the strong growth in the base business over the past 3 years through a combination of high-margin organic growth and accretive acquisitions, Tourmaline's Board of Directors has elected to increase the base quarterly dividend from $0.35 per share to $0.50 per share, a 43% increase, and that's effective in the first quarter of 2025. The Board also declared a special dividend of $0.35 per share to be paid on March 25 to shareholders of record on March 13 and we do intend to pay special dividends in all 4 quarters of this year, inclusive of this Q1 special dividend. We paid $3.32 per share in combined base and special dividends in 2024, and that's a 5.3% trailing yield. Full year '24 CapEx was $1.9 billion, and that includes Q4 CapEx of $460 million. Exit '24 net debt was $1.7 billion, that's approaching our long-term net target of $1.5 billion, which is approximately 0.3 to 0.35x forecast net debt to cash flow. And we've always believed maintaining balance sheet strength puts the company in a strong position to deal with any new macro challenges and to take advantage of new opportunities that might arise. Briefly on reserves. Year-end '24 PDP reserves of 1.35 billion BOEs were up 29% after accounting for '24 annual production. Total proved reserves of 2.91 billion BOEs were up 19% and 2P reserves of 5.5 billion BOEs were up 14%. So after 16 years of operations, Tourmaline now has essentially 25 Tcf of economic 2P natural gas reserves and 1.36 billion barrels of 2P oil, condensate and NGL reserves, all of which are pipeline-connected to markets across North America. And at year-end '24, 80% (sic) [ 84 % ] of the current estimated drilling inventory of over 25,000 locations was not booked in the '24 year-end reserve report. Year-end '24 oil, condensate and NGL 2P reserves of 1.36 billion barrels represent the second largest conventional liquids reserve base in Canada based on public disclosure. Of particular note, given our size, we replaced 330% of '24 annual production of 212 million BOEs with 2P additions of 700 million BOEs, including '24 production. Our '24 PDP F&D costs were $8.45 per BOE, including changes in FDC, and that yielded a PDP reserve recycle ratio of 1.8x, which is pretty good for a predominantly gas producer in the harsh '24 gas price environment. 2P FD&A costs in '24 were $7.28 per BOE, including changes in FDC, and that yielded a 2P recycle ratio of 2.1x. And our 2P reserve value before taxes equates to $114 per diluted share. Revisiting the '25 capital program. Full year '25 EP capital budget range remains unchanged at $2.6 billion to $2.85 billion. The company expects steadily improving natural gas prices in 2025. Should that price recovery materialize later in the year, the capital program will be sequenced accordingly. Facility and pipeline expenditures of approximately $300 million remain in the total '25 EP capital budget and that includes ongoing Northeast B.C., North Montney Phase 1 infrastructure build-out components, electrification prebuilds for the '26-'27 West Doe and Groundbirch gas plant projects, and certain long-lead time facility preorders. So the majority of the 2025 growth capital is these facility expenditures. They don't create volumes in 2025 as clearly, this is a year in transition for gas prices. These volumes materialized in 2026 and 2027, a period when much improved gas prices are widely anticipated. We expect to finalize the sequencing of the entire future Northeast B.C. infrastructure buildout during this year, and that will include up to 4 new gas processing facilities. The Groundbirch development is now expected to consist of 2 separate 200 million per day deep-cut plants to be installed in the '27 to '29 time frame, pretty much exactly what we put on the ground at Gundy C-60-A. Some comments on marketing. The company's average realized natural gas price in 2024 was CAD 3.38 per Mcf, that's CAD 1.90 per Mcf above the average '24 AECO 5A index price of CAD 1.48 per Mcf. And our marketing diversification portfolio and strategic hedging program allow us to consistently outperform local hub pricing on a sustained basis. We expect to exit 2025 with over 1.3 Bcf per day in exports to targeted markets, including 904 million per day delivered to the U.S. Gulf, JKM, TTF, Western U.S. markets and Pacific Northwest premium markets. We also secured an additional 95 million per day of ANR service to the U.S. Gulf, and we did that during this quarter. We have an average of 1.06 Bcf per day hedged in 2025 at a weighted average fixed price of $5.07 per Mcf. We do remain encouraged by the very strong demand-driven outlook for North American natural gas prices, which have improved in the majority of the sales hubs accessed by the company over Q4 2024. Western Canadian gas prices have lagged this recovery despite winter natural gas storage withdrawals averaging approximately 1.43 Bcf per day versus a little over 0.7 Bcf per day last winter. So we'll continue to monitor the multiple local natural gas demand catalysts anticipated in '25, including the start-up of LNG Canada. We will manage our unhedged non-export, or local, volumes accordingly, and in the event of very weak spring/summer '25 gas prices, the company will optimize the pace of well stimulation and production start-up activities to shape the production profile to the highest cash flow outcome. Briefly on E&P, we drilled 286 gross wells in '24 and led the Canadian industry with a total of 1.425 million meters drilled during the year. We delivered our best overall well performance in the past 5 years in the Alberta Deep Basin complex. And this outperformance has been across the full suite of Deep Basin assets. We are currently planning to drill up to 365 net wells in 2025. As of January 1, 2025, the ongoing new zone/new pool exploration program has added a little over 2 Tcf of 2P reserves of that total of 25 Tcf and 1,068 Tier 1 and Tier 2 drilling locations since the program was started. There are several potential high-impact exploration wells in the 2025 program, so it will be an exciting year on that front. We continue to make select midstream investments to reduce costs and improve realized margins. Some material cost reductions realized already in the North Montney, and we expect similar improvements in the ex-Crew Groundbirch assets as we execute the infrastructure plan there. On EPI, our cleantech engineering team continues to develop and implement new proprietary emission reduction technologies, execute on expanded water management initiatives and explore industry-leading methane mitigation technologies at our ETC as well as manage related third-party environmental research. And we've touched on the dividend already. So I think we'll turn it over for questions. Thank you.

[Operator Instructions] Your first question comes from the line of Aaron Bilkoski from TD Cowen.

I'm going to start with a tougher one, but I think it's one that's on the minds of investors. So just to frame it, if I use mid-2023 as the starting point, it appears that production revisions for the 5-year plan haven't quite kept pace with the volumes acquired through Bonavista and Crew. Meanwhile, over the same time period, organic E&D CapEx in the plant has also increased. So I guess my question is, could you talk a little bit about some of the puts and takes in the 5-year plan over the past couple of years?

Well, some of it is infrastructure build-out. So there was $200 million approximately in '24 and there's the $300 million outlined in 2025. So in aggregate, about $0.5 billion that -- it's very important to get this multiple-faceted Northeast B.C. infrastructure buildout underway. But as mentioned, we don't really see the volume associated with that until '26 and 2027. The other thing I'd mention, Aaron, is obviously, when we were acquiring businesses in 2023 and 2022, strips were more buoyant. Tourmaline actually took quite a bit of capital out of the plan in 2024 and effectively moved a large part of our completion activity towards the end of the year and still generated $1 billion of free cash flow in '24. And now we're back on the front foot here in the first quarter with activity again. So I think in these gas price environments, you're going to see that plan executed, but we always retain the flexibility to move things around if prices are different.

And your next question comes from the line of Kalei Akamine from Bank of America.

My first question goes to the Crew synergies, and I'm going to try to tie together 2 comments. So first, you signaled wanting to pull forward Groundbirch. I imagine that's going to lift CapEx in '26 and '27, but I also think it's going to pull forward the synergies. So the second comment kind of points to cost reductions at Crew midstream. So can you kind of talk through the capital impact, but also the path to synergy capture? What do you need to do? And where are the synergies going to show up?

Well, on the Groundbirch plant build-out, when it's completely done, we expect a greater than 80% per BOE cost reduction over where we'll start from. And as I mentioned, that's the 200 million a day deep cuts. So it will actually be an even bigger margin improvement than what we saw from our Gundy and Aitken infrastructure build-outs and margin capture initiatives. There's lots of synergies throughout the EP operations. I mean, we can drill and complete wells for probably 20% to 30% less than what they were doing. We'll build out the water infrastructure, and that ultimately reduces costs and it also improves your overall environmental performance. The Crew volumes right now is between 29,000 and 30,000, when we picked it up, BOEs a day, and we're doing sort of 31,000 to 32,000 in the latest production report over the last few days. So yes, we're super happy with it. It was a big component of the reserve increase on a 2P basis that we saw in the year-end 2024 report. Anything else on the synergies, Brian, on the financial side?

No, I think -- I mean, their cash operating costs were a little bit higher. And as we move forward here, we'll be bringing those down as we're controlling more of the liquids barrels as well as getting some of our pipe pretty optimized so that we can drive down some of the midstream costs as well.

And then worth flagging that some of the investments we're making here are going to help us drive higher margins through realizations. So getting some of these products to higher premium markets, more flexibility for our team, more taking kind rights. And that doesn't really show up on the cost side of the ledger, that shows up on the realization side of the ledger. So we're really excited about that opportunity as well.

My second question goes to the signaling on the buyback. So on Slide 23, you show that the buyback is growing as a part of your cash allocation. What is the significance of the timing? Because you kind of show it creeping up from what looks like 2027, and that aligns with the tapering in your production wedge. So why do you think that's the right time to pivot and why not pivot harder into more specials?

Well, it's partly a function of exactly how much free cash flow we have every year. Back it up a little bit, our plan is to maintain that double-digit shareholder return and the composition of that return will change over time. We are entering 4- to 5-year period of growth that we'd always time to the start-up of LNG Canada, which we believe will be very positive for local hub pricing, AECO and Station 2. So there'll be 5-plus percent per share growth via production over the next 4 to 5 years, and we'll maintain that 5% to 6% dividend yield to gross up to over 10%. As we get to the end of that build-out, we'll be 750,000 BOEs a day plus, it will be harder to grow at 5% to 6% per annum. So we see the production growth tapering down to, call it, 2%, and we think that's the appropriate time to bring in a material structural buyback so that the per share growth is maintained at 5%. And then by then, we'd expect a 6%-plus yield, so that the total shareholder return maintains in that double-digit range. So that's the thinking. It is a bit diagrammatic on that slide, and I wouldn't say that the time frames are absolutely ironclad, but we do have a significant growth period ahead of us that we're super excited about.

[Operator Instructions] Your next question comes from the line of Jamie Kubik from CIBC.

I've got 2 questions for you guys here. So first one, your press release indicates delays in acquiring new surface disturbance permits in HB1 areas in Northeast B.C. that limited the ability to drill delineation pads and book 2P reserves. Can you talk about the changes that we'll see this improve in 2025?

Yes, it's been steadily improving over the past 2 years. And I think we secure the most drilling permits of actually any operator in Northeast B.C. They're just not always exactly where we want them. And I think the granting of permits and the finalizing of that process between BRFNand the B.C. government is scheduled to happen in 2025, so that we will get more permits in those HB1 areas. So I think, Scott, anything you want to add to that?

No. I mean the HB1 plan has been approved, and it's moving forward. I think we'll see real evidence of that here in the near future.

Okay. And then second question, recognize that we're in the early days of U.S. and Canada tariffs happening and this might be a bit of a longer-term question, but I'm wondering if you've seen any positive discussions emerging as it relates to additional LNG projects taking flight or pipeline construction or even project expansions in B.C. in particular to start here.

Sure. I would say there have been positive discussions, nothing concrete yet. I think it is pretty clear that Canada needs to look after itself and one of our best opportunities is growing oil and gas volumes and diversifying our markets. I think something like 75% of Canadians support building more pipeline. So this is the right time. Our federal and provincial governments need to move quickly to approve and support these new egress projects, I think they're in the national interest. And the Canadian producers are amongst the most environmentally responsible producing group in the world, and we continue to improve our emission performance. So yes, you're right, in this more insular and competitive world that we apparently have entered into, we need to take advantage of the extensive resources we're blessed with. We believe, on the gas side, if you include LNG Canada Phase 1 and Phase 2 because it's not quite onstream yet and build 1 additional pipeline, a little optimizing on existing pipelines, we can grow our overall industry natural gas production in Canada by 50% by 2030. And that doesn't include a whole bunch of other growth projects that you can dream about. So we're advocating on our front for build-out on the natural gas side. And long and short of it, it's apparent we need to look after ourselves and we have lots of ways to do it.

And your next question comes from the line of Josh Silverstein from UBS.

Just looking at the balance sheet and thinking about the return of capital profile for this year, do you plan to use $200 million of free cash flow to get to the $1.5 billion net debt target? Or will 100% of the free cash flow go back to shareholders in the form of the special dividends?

I mean I think the answer is we'll slowly bring our debt down in small increments over the next 12 to 18 months to that $1.5 billion level. Some of that might come about through a little bit stronger product prices. But in the end, we're still committed to the vast majority of our free cash flow being distributed back to our shareholders.

Yes. The good news is it looks like we have quite a bit more free cash flow in '25 than '24, and we'll see where that goes. And we just need to get these last 2 hubs doing a little better on the pricing front, and we're still optimistic that that's going to occur over the balance of 2025. So we'll see where it goes.

The other point I would add, too, year-over-year, our Tourmaline net debt has actually come down. So we have been trending in the exact right direction. And I think you can expect a similar cadence going forward.

Got it. And then maybe just following up on your commentary on the hubs and pricing. Last year, you guys ramped the rig activity. I think you're up at 18 now. Is the game plan to stay at 18 and then basically just adjust DUCs till timing? Are you actually planning to add rigs this year? Any more color there would be great.

We're not going to add any more rigs than where we are now. One of the decisions we'll make during Q2, during breakup when we certainly pare down operational activity, is do we stay at 17 or 18. And yes, you hit on it. If prices are slow to respond, then we have the ability to delay fracking. I think you know the math on it, 80% of the time to drill -- just let's pick a North Montney pad. 80% of the time required is drilling, but 60% of the cost is completions, but we can turn a pad around in 2 weeks. So we can really match the production growth profile to the shape of the pricing curve, and that's what we're going to do.

And your next question comes from the line of Fai Lee, Odlum Brown.

I just wonder about these tariffs, it sounds like they could be moved tomorrow, but who knows? But assuming the 10% is still in place, do you have to do anything on your hedges or contracts? Or how does -- mechanically, how does the tariff work? How are you affected by that? Or are you affected at all?

Well, we are affected. It's manageable, but it's not nothing. And it happens when our gas volumes cross the border. And then I guess our NGLs in some places cross the border as well. As you know, Fai, we have a mix on the NGL side. Some goes via RIPET and gets the Far East Asia index price. So that's unaffected, but some of our volumes on the NGL side do hedge. So I think we're all going to figure out the mechanics of how this works. We've done all our financial analysis. And as I said, it's manageable at 10%, but we'd prefer to not have any tariffs.

There are a couple of indirect impacts that we can't really quantify, but certainly, currency could work in our favor here that would mitigate some of that. Also, just to amplify a little more on Mike's point, although we do have a large export footprint, the vast majority of those volumes are going into markets where there are absolutely no other available supply sources for those customers. So over time, I would think the pricing would pass through to the consumer.

There are no further questions at this time. I will now hand the call back to Mr. Scott Kirker for any closing remarks.

Thanks, everyone, for attending, and we look forward to talking to you after Q1.

Thank you. And this concludes today's call. Thank you for participating. You may all disconnect.