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

Good day, ladies and gentlemen, and welcome to Tourmaline Fourth Quarter 2023 Results Conference Call. [Operator Instructions] 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 Tourmaline's results for the years ended December 31, 2023, and December 31, 2022. My name is Scott Kirker, and I'm the Chief Legal Officer here at Tourmaline. 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 will start by speaking to some of the highlights of the last quarter and our year so far. And after Mike's remarks, we will be open for questions. Go ahead, Mike.

Thanks, Scott. Welcome, everybody, and we're pleased to review our 2023 results. A few of the highlights. Full year '23 cash flow was $3.71 billion or $10.73 per diluted share. Fourth quarter '23 cash flow was $918 million, we generated $1.69 billion of free cash flow in 2023. Full year earnings were $1.74 billion, a very strong $5.03 per diluted share. We successfully closed the acquisition of Bonavista during the fourth quarter. Tourmaline will pay a special dividend of $0.50 per share on March 21, 2024. And we intend to pay special dividends in all 4 quarters of '24. And we've also increased the quarterly base dividend by 7% to $0.30 per share. Year-end '23 proved developed producing reserves or PDP, of 1.2 billion BOEs were up 39.3%, total proved reserves of 2.61 billion BOEs were up 21% and 2P reserves of 5.01 billion BOEs were up 15.5%. After 15 years of operation, the company has 22.7 TCF of economic 2P natural gas reserves, all of which is pipeline connected to markets across North America. And at year-end '23, we'd still only book 16.5% of our extensive drilling inventory. Year-end '23 2P oil condensate and NGL reserves of 1.22 billion barrels represent the second largest conventional liquids reserve base in Canada based on public information. Given continuing weak natural gas prices this year, we have elected to reduce the forecast '24 capital expenditures from $2.35 billion to $2.13 billion, and we will continue to focus on optimizing free cash flow and shareholder returns. Our fourth quarter '23 production was 557,000 BOEs per day, and that was up 9% from the fourth quarter of '22, and full year '23 average production of a little over 520,000 BOEs per day was up 4% over the full year '22 average. In calendar 2024, we have an average of 726 million cubic feet per day hedged at a weighted average fixed price of $5.34 per mcf. Montney well performance in NEBC continues to improve with '23 wells -- 2023 wells outperforming wells from the previous 3 years, both natural gas and particularly liquids production are exceeding the previous year's performance. At current strip pricing, we expect to generate '24 cash flow of $3.32 billion and free cash flow of approximately $1.2 billion. Looking at production, a couple more stats with the announced significant '24 capital budget reduction, our '24 average production is now 580,000 to 590,000 BOEs per day, so 585,000 at the midpoint. And we expect Q1 average production of between 590,000 and 595,000 BOEs per day as the capital reductions did impact the first quarter. Forecast liquids production of approximately 144,000 barrels per day is actually ahead of original forecast. And daily liquids productions eclipsed 150,000 barrels per day on several days so far this year. reiterating a couple of the financial highlights. As mentioned, full year earnings were $5.03 per diluted share. We paid $6.55 per share in combined base and special dividends in 2023, and that's a 10% trailing yield. We have elected to increase the base dividend, as mentioned by 7% and for the first quarter of this year, and we have now increased the base dividend a total of 13x since we initiated the dividend in the first half of 2018. Exit 2023 net debt was $1.78 billion, including cash paid of $651 million and net debt assumed relating to the acquisition of Bonavista in the fourth quarter. We intend to reduce net debt throughout 2024, and we do remain committed to our long-term debt target of between $1.2 billion and $1.4 billion, which is in that 0.3x debt to cash flow range. We have only booked as we move into reserves. A couple more highlights. We've only booked 3,900 gross locations of a total drilling inventory of 23,724. So as mentioned, 16.5% of that inventory only is booked in the year-end '23 2P reserve category. We replaced 368% of our 2023 annual production of 190 million BOEs with 2P additions of 698 million BOEs. 2023, PDP finding our FD&A costs were $8.94 per BOE, excluding changes in future development capital, and that yielded a PDP reserve cycle ratio of 2.2. Our 2P reserve value before tax equates to a little over $117 per diluted share and after tax, a little over $90 per diluted share, and that's based on the Jan 1, '24 engineering price deck and a 10% discount rate. Specifically on the '24 capital program, as mentioned, we've elected to reduce forecast capital expenditures by about $220 million. The budget reductions include a reduction in the rig count, a deferral of select exploration drilling and certain facility projects. And we reiterate, although our extensive Tier 1 drilling inventory of over 17 years is actually profitable at AECO gas prices around $1.50 per Mcf. We do not believe that selling incremental gas volumes into the current very weak gas market is the best decision or return proposition for our shareholders. So forecast average 2024 natural gas production has been reduced by approximately $100 million per day from previous guidance or 4%. So we've essentially eliminated any gas growth in 2024, and we definitely think that's the right thing to do. Should prices improve on a sustained basis, we can pivot and materially grow production late in the year or early in 2025. Briefly on marketing. In 2023, our average realized nat gas price was $4.83 per Mcf. So that's 80% above the average 2023 AECO 5A index price, which was $2.68 per Mcf. And our marketing diversification portfolio and strategic hedging program allowed the company to consistently outperform local pricing. We expect to exit 2024 with approximately 1.21 Bcf per day in exports to targeted markets including a total of 754 million cubic feet per day delivered to a mix of JKM, the Western U.S. and the Pacific Northwest. Those are the key premium markets. In January of this year, we completed our second LNG agreement, increasing exposure to the JKM index by entering into a netback agreement with Trafigura based on 62,500 MMBtu for a 7-year term starting Jan 2027 with the potential for extension to December 2039. And that agreement is not dependent on incremental FERC approvals. Briefly on EP, we're excited about our Montney well performance in BC as it continues to improve with the '23 wells outperforming wells from the previous 3 years. In BC, we've received 252 new drilling permits since January of 2023. And the '24 program or the Q1 program has delivered several Alberta Deep Basin pads that are well above performance curve expectations,and they're at Smoky and Kakwa and along the ex Bonavista Glauconite trend. A couple of the big highlights, of course, 10 to 26, that's a three-well Wilrich C pad tested at average per well rates of 29.3 million cubic feet per day of gas per well over a 70-hour test during January. The Kakwa 10 to 2, again, a three-well, this is a Wilrich pad tested at average well rates of just a little under 20 million per day per well, over 112 hour test period and the 2 most recent Glauconite wells on down dip on the trend have significantly outperformed, first tested at an average gas rate of 7.7 million cubic feet per day and 946 barrels per day of condensate. That was on 134-hour flow cast. We turned that well over to production in February. And the second well averaged 8 million a day of nat gas, 850 barrels per day of condensate and 1,170 barrels per day of NGLs over the first 7 days of production. Importantly, we've also successfully drilled the first monobore well designed for the Glauconite, which we expect will ultimately reduce drilling costs by as much as 15% to 20%. On our continuing environmental performance improvement or our clean tech engineering team continues to develop and implement new proprietary commission reduction technologies, execute expanded water management initiatives, explore industry-leading methane mitigation technologies and manage a large amount of third-party related environmental research, which we pick and choose amongst. Since embarking on our diesel displacement initiative, which is just one of them for drilling rigs and frac spreads over 6 years ago, we've displaced a little over 135 million liters of diesel, which has provided an emission reduction that 87,000-plus tonnes of CO2 and importantly, saved approximately $129 million, and that includes the cost of the makeup nat gas replacing the diesel. We continue to strive to have the lowest freshwater intensity in industry in '22. We did at 0.11 barrels per BOE 12 months after fracturing. And that extensive water storage and recycling infrastructure that we've diligently built over the last 7 or 8 years, could prove highly beneficial in the event of drug-related water restrictions, which may or may not happen later in the year. So that was all I was going to say as far as formal remarks, and we're all here to answer questions you might have.

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

Just a couple of things. So on the liquids, you mentioned it was BC Montney driving that performance. Just wondering if you can comment on the specific subregions of the Montney driving that? Or if it was just kind of from all over. And then just the mix of those liquids in 2024, it looks pretty consistent with your last update in terms of the split between condensate, et cetera, but just checking in on that. And then last thing was just there was a small tech revision downward 46 million barrels. Just any color on where that came from, as I assume is bunch of moving parts in that figure that was provided.

Sure. On the liquids, yes, both of the corporate outperformance is driven by the Montney and most of that is in the North Montney in part relates to a little more plug-and-perf completion style on the tighter, more liquid-rich horizons. On the tech provision on the 2P of a little under 50 million BOEs, the lion's share of that related to a couple of zones of the 6 at Gundy underperforming what we had expected. And so it's a little under 1% of the total reserve base. And the mix -- sorry, Mike, you had a third question in there. The mix is largely the same between the liquids. I mean we're getting a lot more condensate in the Deep Basin right now, but we'll see how that performs through the balance of the year.

[Operator Instructions] Your next question is from Donald Textor from DFT Energy.

Mike, I know you're not directly involved in Canada LNG, but could you just -- you know a lot more about it than I do. Could you give us a status report there when you think can start putting gas in the line? And when do you think they really start exporting gas?

Yes. Well, actually, we probably don't know a lot more than you do in it because we just rely mostly on the same public data. We're hearing encouraging things that there's going to be some gas going through the CGL line, which is completed, and that's going to happen at some point in the second half of 2024. But we don't know the exact startup, and we don't know the exact volume. Jamie, anything else you want to add?

Yes, I think in general, we expect commissioning to kind of ramp up to the back end of the year and the plan to be hopefully fully commissioned in 2025, which will be 2 billion cubic feet a day pulled out of the WCSB, that's a 13% to 14% demand increase, and it's going to be significant for our market.

And would you care to give your guidance as to what's going to happen on differentials between AECO-C gas and NYMEX gas?

We expect some tightening. We think that you could see basis tightening a little bit here, $0.25 to $0.50 on average, but we also think that there could be volatility around that number, maybe some periods of very firm pricing, maybe some periods if the plant is not running at full capacity where the pricing is a little bit looser. So we're prepared for both improving market dynamics, but also potentially more volatile market dynamics ahead of us.

Your next question is from Cam Bean from Scotiabank.

I was just curious if you could provide any color on where -- regionally where that $150 million of development capital was going to come out from.

I'd say probably more than 2/3 of it out of the Deep Basin and then the balance out of BC, some of it being facility-related capital.

Your next question is from Mike Dunn from Stifel.

Yes, Mike, just wondering, as we've looked at what some of the U.S. peers have done with their production cuts for gas or the cuts to their outlook I'm just curious here if we do see some really weak prices again, given your low operating cost, you wouldn't be the first to shut in production, but what sort of spot AECO price, I guess, or station 2, do you guys start to think about curtailing production and maybe the scope of what that might be? Is there a lot that would maybe go offline at $1.50, $1.40 or not really?

Well, we make money at that price. I mean, we've had an activity cut rather than just a [indiscernible] because we think that's actually better for the markets, and it's better for our free cash flow to do it that way. So we've eliminated our growth. In the past, we have shut gas in on a very short-term basis. And that related to TransCanada maintenance when they were doing the NGTL build-out that you recall. And there would be days when you had 0 price or 2 or 3 days, then we would shut in there. It's usually sundown, which is right on the BC, Alberta border. And it's the driest asset we have from a liquid content standpoint. But -- so we watch it, but we have no plans to shut in. But as you say, we'll just have to see where the price goes.

Your next question is from Chris Varcoe from Calgary Herald.

I'm wondering whether your outlook for Canadian gas markets has substantially changed at all for 2025, given what we're seeing right now in the marketplace, but also obviously the start-up of LNG exports coming out of this country next year.

Yes. No, it hasn't. We're quite bullish on what happens to our 2 local hubs AECO in Station 2 and [indiscernible] 2 Bcf a day west out of a basin that's largely in supply-demand balance. So no, we remain super constructive to be honest. But right now, in 2024, the price is not good, so we'll save those incremental growth methane molecules for that much better price we expect in 2025.

And just a follow-up. Is there any plans, I guess, or do you see yourself shifting towards producing more condensate later in the year as you're sort of moving some of that capital around?

Well, our liquids production guidance is actually up over the year. And -- but I think that will happen in all the remaining 3 quarters, not specifically timed to any particular date in the second half.

Your next question is from Ben Brown from [indiscernible]

I just have one question on the free cash flow allocation. The forecast at the current strip is $1.2 billion. And after you net out the base dividend and I guess the March special, you have -- it looks like you have around $600 million to allocate between future special dividends, which you've committed to as well as reducing debt. I'm just wondering how should we think about the split between debt reduction [indiscernible] dividend?

Yes, I can start, and we can probably run it up as a team. So maybe it's easier to think about it on a per share basis. So free cash flow per share this year is $3.35 on the February 15 strip. And then the dividend, as you mentioned, the base will be $1.20. The first special is $0.50. We could continue paying that $0.50 dividend 4 times in a row and still have headroom. And I would note that since February 15, commodity prices have actually improved somewhat. So we would see some upside to this number already, and we'll kind of see how the year progresses. On leverage, our aim long term is to get back to that $1.2 billion to $1.4 billion target but we don't necessarily need to achieve that in any one specific time period. It's just a progression we're going to be moving towards. So I would anticipate some deleveraging this year, but not necessarily as much leveraging as needed to get into the range in [ 1 annum ]. And so for balance of the year, we'll be monitoring strip pricing, which, as I mentioned, has already been improving and allocating some cash flow back to the balance sheet, but in general, continuing to return the vast majority of free cash flow back to shareholders.

Okay. That's great. That's -- I appreciate the color there. And in terms of the commitment to the special dividends, were there any thought given to doing share buybacks given where the current share price is? Or I'm just wondering, it's not -- how that factored into decision for the -- paying special dividend through the remainder of the year.

Yes, sure. I mean we always evergreen our NCIB, and we're maintaining our defensive foster for potentially using it if there's an extreme price dislocation. So it is always one of the potential uses of that matrix of free cash flow.

Okay. All right. So in that event, would we assume that maybe the change of plans on a special dividend? Or would you possibly maybe increase your leverage a bit temporarily?

Well, we're not going to use the balance sheet to pay special dividends. So.

There are no further questions at this time. Please proceed.

Thank you very much.

We'll see you next quarter.

Thank You. ladies and Gentlemen, the conference has now ended. Thank you all for joining. You may all disconnect.