Tourmaline Oil Corp.

Good morning, ladies and gentlemen, and welcome to the Tourmaline Q4 2024 results conference call. At this time, all lines are in listen-only mode. Following the presentation, we will conduct a question-and-answer session. If at any time during this call you require immediate assistance, please press star zero for the operator. 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, Lena, and welcome, everyone, to our discussion of Tourmaline's financial operating results for the three months and years, and in December 3124 and December 3123. My name is Scott Crocker, and 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 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 Robson, our Chief Financial Officer, and Jamie Hurd, 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 ACO 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 2025, and a special dividend of $0.35 per share. With continued growth in the base business and continued improvements in realized pricing, were 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. BDP 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 five years with our North Montney, West Dole ground birch, South Montney, and North Deep Basin infrastructure projects. These projects will grow both our total volumes and materially improve production. are 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 three 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 2024 free cash flow was $1 billion. And as mentioned, given the strong growth in the base business over the past three 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 25th to shareholders of record on March 13th. And we do intend to pay special dividends in all four quarters of this year, inclusive of this Q1 special dividend. We paid $332 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 0.35 times 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 BUEs were up 29% after accounting for 24 annual production. Total approved reserves of 2.91 billion BUEs were up 19%, and 2P reserves of 5.5 billion BUEs were up 14%. So after 16 years of operations, Termaline 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% 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 productions. Our 24 PDP F and D costs were $8.45 per BOE, including changes in FDC, and that yielded a PDP reserve recycle ratio of 1.8 times, which is pretty good for a predominantly gas producer in the harsh 24 gas price environment. 2P FD and A costs in 24 were $7.28 per BOE, including changes in FDC, and that yielded a 2P recycle ratio of 2.1 times. 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 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 BC, North Montney Phase 1 infrastructure build-out components, electrification pre-builds for the 26-27 West Dolan ground birch gas plant projects, and certain long lead time facility pre-orders. 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 materialize 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 BC infrastructure build-out during this year, and that will include up to four new gas processing facilities. The ground birch development is now expected to consist of two separate 200 million per day deep cut plants to be installed in the 27 to 29 timeframe. Pretty much exactly what we put on the ground at Gundy C68. Some comments on marketing. The company's average realized natural gas price in 2024 was $338 per MCF Canadian, That's $1.90 per MCF above the average 24-805A index price of $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 China, $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 $507 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 2025, including the startup of LNG Canada. We will manage our unhedged non-export or local volumes accordingly, and in the event of very weak spring-summer 2025 gas prices, the company will optimize the pace of well stimulation and production startup 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 five years in the Alberta Deep Basin Complex, and this outperformance has been across and assets. We are currently planning to drill up to 365 net wells in 2025. As of January 1st, 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 X-Crew ground bridge assets as we execute the infrastructure plan there. On an 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.

Thank you. Ladies and gentlemen, we will now begin the question and answer session. Should you have a question, please press star followed by the one on your telephone keypad. You will hear a prompt that your hand has been raised, and should you wish to cancel your request, please press star followed by the two. If you are using a speakerphone, please lift the handset before pressing any keys. One moment, please, for your first question. Your first question comes from the line of Aaron Wilkoski from TD Cowen. Please go ahead.

Good morning. Thanks for taking my question. I'm going to start with the 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 the production revisions to the five-year plan haven't quite kept pace with the volumes acquired through Bonavista and Carew. Meanwhile, over the same time period, organic E&D capex in the plan has also increased. So I guess my question is, could you talk a little bit about some of the puts and takes in the five-year plan over the past couple of years?

Well, some of it is infrastructure build-out. So there was $200 million approximately in 2024, and there's the $300 million outlined in 2025. So in aggregate, about half a billion dollars that it's very important to get this multiple-faceted northeast BC infrastructure build-out 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. You know, 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 a billion dollars 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.

Okay. Thank you.

Thank you. And your next question comes from the line of Kelly Akamine from Bank of America. Please go ahead.

Hey, good morning, guys. Mike, Brian, Jamie. My first question goes to the crew synergies, and I'm going to try to tie together two comments. So first, you signaled wanting to pull forward ground birch. 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 ground birch plant build-out, when it's completely done, we expect, you know, 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'll 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 the wells for probably 20 to 30% less than what they were doing. We'll build out the water infrastructure and that ultimately reduced costs and it also improves your overall environmental performance. The crew volumes right now was between 29 and 30 when we picked it up, 1,000 BOEs a day, and we're doing sort of 31 to 32,000 in the latest production report over the last few days. So, yeah, 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?

Well, 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 liquid barrels, as well as getting some of our pipe recharging. optimized so that we can drive down some of the industry costs as well.

And then with 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.

Thanks for all the detail there. My second question goes to 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 capital 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 a four- to five-year period of growth that we'd always time to the startup of LNG Canada, which we believe will be very positive for local hub pricing, ACO, and Station 2. So there'll be 5-plus percent per share growth via production over the next four to five 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 VOEs a day plus. It'll 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 timeframes are absolutely exact, ironclad, but we do have a significant growth period ahead of us that we're super excited about. Thanks, guys. Good update.

Thank you. Once again, should you have a question, please press star 4 by the 1 on your telephone keypad. Your next question comes from the line of Jamie Kubik from CIBC. Please go ahead.

Yeah, good morning. I've got two questions for you guys here. So first one, your press release indicates delays in acquiring new surface disturbance permits in HV1 areas in northeast BC that limited the ability to drill delineation pads and book 2P reserves. Can you talk about the changes that will see this improve in 2025?

Yeah, it's been steadily improving over the past two years, and I think we secure the most drilling permits of actually any operator in Northeast BC. They're just not always exactly where we want them. And I think, you know, the granting of permits and the finalizing of that process between DRFN and the BC government is scheduled to happen in 2025 so that we will get more permits in those HV1 areas. I think, Scott, anything you wanted to add to that?

No, I mean, the H2O plan has been approved and it's moving forward. I think we'll see real evidence of that here in the near future.

Okay, thank you. 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 BC 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 pipelines, 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. Yeah, 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 on stream yet, and build one additional pipeline, a little optimizing on existing pipelines, we can grow our overall production. industry natural gas production Canada by 50% by 2030, and that doesn't include a whole bunch of other growth projects that you can dream about. So, you know, 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.

Okay, good answer. Thank you. I'll hand it back.

Thank you. And your next question comes from the line of Josh Silverstein from UBS. Please go ahead.

Good morning, guys. 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.

And 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 two hubs doing a little better on the pricing front. And, you know, we're still optimistic that, you know, that's going to occur over the balance of 2025. So we'll see where it goes.

The other point I would add to year over year, our tournament 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. Thanks for that. And then maybe just following up on your comment there on the hubs and pricing, you know, 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 ducts, till timing? Are you actually planning to add rigs this year? So any more color there would be great. Thanks.

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 yeah, you hit on it, that 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, you know, we can turn a pad around in two weeks. So we can, you know, really match the production growth profile to the shape of the pricing curve, and that's what we're going to do.

Thanks. Thank you. And your next question comes from the line of Philly, Odlin Brown. Please go ahead.

I might get fired. I just wonder about these tariffs. Sounds like they could be moved tomorrow, but who knows? But assuming, you know, the 10% is still in place, do you have to do anything on your hedges or contracts or how does it, you know, mechanically, how does the tariffs work? You know, how are you affected by it 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, Fi, we have a mix on the NGL side. Some goes via RIPIT and gets the Far East Asia index price. So that's unaffected. But some of our volumes on the NGL side do head south. So I think we're all going to figure out the mechanics of 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.

Okay, fair enough. Thank you.

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, one would think the pricing would pass through to the consumer.

Okay. I understand. Thank you.

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

Thanks, everyone, for attending, and we look forward to talking to you at 51.

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