Tourmaline Oil Corp.

Good day, ladies and gentlemen, and welcome to Tourmaline fourth quarter 2023 results conference call. At this time, all lines are in a listen-only mode. Following the presentation, we will conduct a question and answer session. If anyone has any difficulty hearing the conference, please press star zero for operator assistance at any time. 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 Termline'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 Termline. 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 Termline Annual Information Forum 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 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. Termally, we'll pay a special dividend of $0.50 per share on March 21, 2024, and we intend to pay special dividends in all four quarters of 2024. And we've also increased the quarterly base dividend by 7% to $0.30 per share. Year-end 2023 approved Developed Producing Reserves, or PDP, of 1.2 billion BOEs were up 39.3%. Total approved 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 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 VOEs 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 BUEs 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 534 per MCF. Mountaineer well performance in BC continues to improve with 2023 wells outperforming wells from the previous three 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 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 production has 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 503 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% for the first quarter of this year, and we have now increased the base dividend a total of 13 times 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 and $1.4 billion, which is in that 0.3 times 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 or FD&A costs were $894 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 chair and after tax a little over $90 per diluted chair. 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 ECO 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 Canadian, so that's 80% above the average 2023 ACO 5A index price, which was $2.6. and strategic hedging program allow 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 US 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 net back agreement with Trafalgar, based on $62,500 MMVTU for a seven-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 three years. In BC, we've received 252 new drilling permits since January of 2023. The 24 program, or the Q1 program, has delivered several Alberta Deep Basin paths 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, course 10 of 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 Caquatana II pad, 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 a 112-hour test period. And the two 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 a 134-hour flow test. 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 1170 barrels per day of NGLs over the first seven days of production. Importantly, we've also successfully drilled the first monobore well designed for the Glock trend, which we expect will ultimately reduce drilling costs by as much as 15% to 20%. On our continuing environmental performance improvement, or EPI, our clean tech engineering team continues to develop and implement new proprietary emission 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 six years ago, we've displaced a little over 135 million litres of diesel, which has provided an emission reduction of 87,000 plus tonnes of CO2 and importantly, saved approximately $129 million, and that includes the cost of the makeup nat gas. We continue to strive to have the lowest freshwater intensity in industry. In 22, we did at 0.11 barrels per BUE 12 months after fracturing, and that extensive water storage and recycling infrastructure that we've diligently built over the last seven or eight years could prove highly beneficial in the event of drought-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.

Thank you.

Ladies and gentlemen, we will now begin the question and answer session. Should you have a question? please press the star followed by the one on your touchtone phone. You will hear a three-tone prompt acknowledging your request. Questions will be taken in the order received. Should you wish to cancel your request, please press the star followed by the two. If you are using a speakerphone, please lift the handset before pressing any keys. Once again, that is star one should you wish to ask a question. Your first question is from Michael Harvey from RBC Capital Markets. Please ask your question.

Yeah, sure. Good morning, guys. Thanks for taking the question. Just a couple things. So on the liquids, you mentioned it was BC Montney driving that out of performance. Just wondering if you can comment on the specific sub-regions 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 looks pretty consistent with your last update in terms of the split between condensate, et cetera, but just checking in on that. And then the 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 there's a bunch of moving parts in that figure that was provided. Thanks.

Sure. On the liquids, yeah, most of the corporate outperformance is driven by the Montney, and most of that is in the North Montney, and it in part relates to a little more plug-and-perf completion style on the tighter, more liquid-rich horizons. Tech revision on the 2P of a little under 50 million BOEs. The lion's share of that related to a couple of zones of the six at Gundy underperforming what we had expected. And so it's a little under 1% of the total reserve base. And the mix, sorry, Michael, 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.

Great. Appreciate the call, Mike. Thanks. Thank you. Once again, please press star 1 should you wish to ask a question.

Your next question is from Don Texter from DFT Energy. Please ask your question.

Good morning, Mike. 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 do you think they're going to start putting gas on the line, and when do you think they'll really start exporting gas?

Yeah, well, actually, we probably don't know a lot more than you do on 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? Yeah, I think in general, we expect commissioning to kind of ramp up to the back end of the year and the plant 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 ACoC gas and Dymex gas?

We expect some tightening.

We think that you can see basis tightening a little bit here, 25 to 50 cents 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's not running at full capacity where the price is a little bit looser. So we're prepared for both improving market dynamics, but also potentially more volatile market dynamics ahead of us.

Okay. Thank you very much.

Thank you. Thank you.

Your next question is from Cam Bean from Skill Japan. Please ask your question.

Good morning, guys. Thanks for taking my question. I was just curious if you could provide any colour on regionally where that $150 million of development capital was going to come out from.

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

Awesome. Thank you very much.

Thank you. Your next question is from Mike Dunn from Stifel.

Please ask your question.

Well, thanks. Yeah, Mike, just wondering, you know, 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 in you know, given your low operating costs, you wouldn't be the first to shut in productions, but what sort of spot, ACO price, I guess, or Station 2, do you guys start to think about curtailing production? And maybe the scope of what that, you know, 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 shut-in 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 NGT build-up that you recall. And there would be days when you had zero price or two or three days, and we would shut in there. It's usually sundown, which is right on the BC-Alberta and it's the driest asset we have from a liquid content standpoint. 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.

Yeah, fair enough. Makes sense.

Thanks, Mike. That's it for me. Thanks. Thank you.

Your next question is from Chris Watto from the Calgary Herald. Please ask your question.

Hi, Mike. Thanks for taking my question. 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 startup of LNG exports coming out of this country next year.

Yeah, no, it hasn't. We're quite bullish on what happens to our two local hubs, ACO and Station 2, when you pull two BCF a day west out of a basin that's largely in supply-demand balance. So, no, we remain optimistic. 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 to 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 liquid production guidance is actually up over the year, but I think that will happen in all the remaining three quarters, not specifically timed to any particular date in the second half.

That's all for me.

Thank you. Thanks. Thank you. Your next question is from Ben Brown from Olin. Please ask your question. Oh, it might have been a Phy Lee.

Hello?

Yeah. Hi, Phy. Yeah. I saw the odd one brown, so I figured it was you.

It confused me a bit. Sorry about that. I just want to touch on the free cash flow allocation. You know, the forecast at the current script is $1.2 billion. and after you met out the base dividend and i guess the march special you'll have looks like you'll 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 this split between debt reduction and the stuff evidence if 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 15th strip. And then the dividend, as you mentioned, the base would be $1.20. The first special is $0.50. We could continue paying that $0.50 dividend four times in a row and still have headroom. And I would note that since February 15th, 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 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 deleveraging as needed to get into the range in one annum. And so for balance a 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. I really appreciate the color there. And in terms of the commitment due to the special givens, were there any thought given to doing share buybacks given where the current share price is? I'm just wondering how that factored into decision for paying special givens through the remainder of the year.

Yeah, sure. I mean, we always evergreen our NCIB and we're maintaining our defensive posture 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.

In that event, would we assume that maybe there'll be a change of plans and 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.

Okay. All right. Thank you. Yeah. Thanks. Thank you. 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.