Tourmaline Oil Corp.

Good morning, ladies and gentlemen, and welcome to Tourmaline Q3 2023 Results Conference Call. At this time, all lines are in the 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 the star zero for the operator. Please be advised that this call is being recorded on Thursday, November 2, 2023. I would now like to turn the conference over to Jamie Hurd. Please go ahead.

Thank you, operator, and welcome everyone to our discussion of Tourmaline's results as of September 30th, 2023, and for the three and nine months ended September 30th, 2023 and 2022. My name is Jamie Hurd, and I am Tourmaline's manager of capital markets. Before we get started, I refer you to their advisories on forward-looking statements contained in the news release, as well as the advisories contained in the Tourmaline annual information forum and our MD&A available on CDAR, and 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, and Brian Robinson, our Vice President of Finance and Chief Financial Officer. We will start by speaking to some of the highlights of the last quarter in our year so far. After Mike's remarks, we'll be open for questions. Mike, please go ahead.

Thanks Jamie and welcome everybody. Thanks for dialing in. We are pleased to review our third quarter results, outline our 24 plans and answer questions you may have. So firstly a few highlights. Third quarter cash flow was $878 million or $255 per diluted share. We generated free cash flow in the third quarter of $332 million or $0.96 per diluted share. And that enabled us to declare a special dividend of $1 per common share, and that was paid on November 1st. The company has distributed total dividends of $6.52 per share, inclusive of the November 1 special, since December 1st of 22, and that's an implied 9% trailing yield. Full year 23 free cash flow forecast is now $1.9 billion or so up. September 30, 2023 net debt was $880 million, which is 0.3 times Q3 23 annualized cash flow of $3.5 billion. Third quarter net earnings were $275 million or $0.80 per diluted share. And as you know, in October, we entered into an agreement to acquire all the shares of Bonavista Energy Corporation for $1.45 billion. That consisted of $725 million in terminally common shares and $725 million of cash, plus Bonavista's net debt at closing. And the closing of the transaction is still expected to occur in the second half of this month. Starting with production, our third quarter average production of $502 million 1,000 BOEs per day was at the higher end of our guidance of 495 to 505,000 BOEs per day. Third quarter was reduced by our planned plant turnarounds, which amounted to a 16,000 BOE a day impairment in the quarter, as well as our planned storage injections in California and Dawn. Our 2023 average production guidance remains at 520,000 BOEs per day. and we expect exit 23 production of over 600,000 BOEs per day, and that would include the acquired Bonavista volumes. Inclusive of the Bonavista assets on a maintenance-only capital budget, we anticipate 24 average annual production to range between 600,000 and 610,000 BOEs per day, and the formal guidance we're using in the five-year plan is 600,000 BOEs per day. We do plan to grow production from the Bonavista assets in 2025, and that'll be into an anticipated higher gas price environment. 2024 average liquids production of over 140,000 barrels per day is now forecast as the company evolves into one of the largest Canadian liquids producers. Tourmaline is Canada's largest natural gas producer with forecast production of over 2.7 BCF per day in calendar 2024. Briefly on financial results, as mentioned, third quarter cash flow was $879 million on total CapEx of $565 million. EP spending was $533 million, so a little under forecast. And we generated free cash flow of $332 million in the quarter. As of September 30th, 2023, the company from a balance sheet perspective is actually in a surplus position when you include the value of our 45.1 million shares of Topaz Energy Corp. And the continued strong free cash flow that we generated during the third quarter, as well as the forecast free cash flow for the fourth quarter of this year, allowed the company to pay the previously announced special dividend of $1 per share. And we also increased the base dividend from $1.04 to $1.12 per share on an annualized basis, and that's effective as of the December 23 quarterly base dividend payment. Looking at marketing, our average realized natural gas price for the quarter was $4.56 per MCF Canadian, and that was significantly higher than the ACO 5A benchmark price of $2.64 Canadian per MCF. In the fourth quarter of this year, we have an average of $755 million per day hedged at a weighted average fixed price of $507 per MCF Canadian. For 2024, the company has an average of $722 million per day hedged at a weighted average price of $535 per MCF Canadian, an average of $119 million per day hedged at a basis to NYMEX of minus $0.05 per MCF U.S., and we have an average of $833 million per day of unhedged volumes exposed to export markets in 24. And of that volume component, 65% is exposed to the premium export markets, which for us are the U.S. Gulf Coast, our Western U.S. hubs, JKM and Sumas. The company's exposure to Western U.S. markets will increase this month with the addition of 82 million per day of transportation capacity. With this addition and others, the company's natural gas exports will reach 1.08 BCF per day by exit of this year. We have further diversified our natural gas marketing portfolio by entering into a long-term Enrihub NetBack arrangement and that'll move approximately 60 million per day to the U.S. Gulf Coast. And that will expect, we're expecting that to commence in November of 2026. And we joined the Neaston and Venture as an industry supporter. That's an Indigenous-led project that will create a multi-product utility corridor, including NatGas, and that will connect Alberta, Saskatchewan, and Manitoba to Tidewater on Hudson's Bay. and the project ultimately involves support for containers, potash, and other prairie products, and envisions an electrified LNG facility actually on Hudson's Bay. Looking at our capital budget and financial outlook, as mentioned, third quarter CapEx was $533 million on E&P. Full year 23 EP capital spending is now anticipated to be approximately $1. $1.825 billion, and that is up from the prior $1.675 billion. That increase includes the incorporation of anticipated Bonavista-related capital expenditures post-closing this quarter. Incremental inflation of approximately 5% over forecast levels as that happened as we locked in services during the second and third quarters of this year for the second half, $23 billion. to first half 24 EP season and also we're accelerating the fracking of two pads into 23 from or fourth quarter of 23 from first quarter of 24 due to faster realized drilling times our board of directors has improved approved approved a full year 24 EP capital budget of 2.15 billion That reflects a 14 to 15 rig program and that includes 225 million associated with the Bonavista assets That 24 EP program is expected to deliver cash flow at strip pricing of 4.5 billion and free cash flow of 2.2 billion and those are both up from previous estimates and as in previous years we are strongly committed to returning the majority of free cash flow to shareholders and and we plan to continue our practice of quarterly special dividends during calendar 2024. Our updated five-year plan incorporates modest growth from the Bonavista assets commencing in 2025, as well as the deferral of the North Montney Phase II Conroy development by one year. And that deferral allows us to spread out facilities capex, evaluate potential Phase II facility electrification options, and it results in a significant increase in free cash flow, particularly in that 26 to 28 timeframe. And of note, between 2022 and 2028, Termaline anticipates organically growing the Northeast BC Montney gas condensate complex production or volumes by over 125,000 BOEs per day, and that's without the North Montney Phase II Conroy project. A brief EP update. We continue to operate all 13 drilling rigs and three to four frac spreads across our three EP complexes, and we anticipate adding one to two drilling rigs in calendar 24 to accommodate drilling on the Bonavista assets. During the fourth quarter of this year, we will bring 76 new wells on stream, and that will drive very strong Q4 average production volumes and a strong 2023 production exit level. During the third quarter, we delivered a new pacesetter well in the North Montney, 4.91 days from spud to rig release for a 4164-meter horizontal well. On the exploration front, as of the end of September, the company has made 19 new pool, new zone discoveries and drilled one uneconomic marginal oil well since we started that exploration program well over three years ago. The program has yielded 1.26 TCF of booked 2P reserves at year-end 22 and has also added an estimated 957 Tier 1 and Tier 2 drilling locations to an already very large inventory. Looking at the north deep basin, we are planning a new facility project It'll optimize production at the existing Musro and Kakwa plants that we operate, and it's expected to add 15,000 BWEs per day during 25 and 26, again, into that anticipated stronger natural gas pricing environment. We also completed the acquisition of assets from Whitehorse Resources Limited during the third quarter of 23 for $19.1 million. And this acquisition expands our land holdings and inventory adjacent to a cardium oil discovery that we made in the first quarter of this year in the Rest Haven-Cacoa area, and we provided some details on that well. And on the board front, we're very pleased to announce that Christopher Lee has been appointed to our board of directors, and he was at his first meeting yesterday. So I think that's enough. on the review of the press release, and we're more than happy to answer questions that you may have.

Thank you. And ladies and gentlemen, we will now begin the question and answer session. Should you have a question, please press the star, followed by the number one on your telephone keypad. You will hear a three-tone prompt acknowledging your request, and your questions will be polled in the order they are received. Should you wish to decline from the polling process, please press the star, followed by the number two. And if you're using a speakerphone, please keep the handset before pressing any key. One moment, please, for your first question. And your first question comes from the line of Jamie Kubik from TIBC. Your line is open.

Yeah, good morning, and thanks for taking my question. Just a question related to the Bonavista deal. Tourmaline's been relatively quiet in the past couple years on the M&A front. Can you just talk a little bit more about what the Bonavista acquisition brings to the company and maybe a little bit more on Tourmaline's appetite for acquisitions in the current environment?

Thanks. Sure. We've been tracking Bonavista and the progress of that company for well over two years as they improved their balance sheet, eliminated debt, and moved into free cash flow generating mode. And that's one of our key criteria when we complete M&A. is that the free cash flow yield from an acquisition has to be as good or better than what our organic five-year EP plan can deliver, and that was certainly the case with the Bonavista transaction. It's a significant addition to our existing deep basin complex. We see opportunities for cost reduction and production optimization, and partly because they've been really on a maintenance capital budget for several years, we see lots of opportunity for improvement and a large inventory and ability to grow the production, and we'll do it modestly, as mentioned, and we'll start that in 2025 when we think gas prices will be better than 2024, although 2024, it's just hard to call. I think with the start-up of LNG Canada and the Gulf Coast LNG expansion, I think we all expect stronger pricing in 2025. As far as further M&A, we're always looking, we always have been, but we've got very strict criteria before we want to consummate any kind of deal. And being that we've kept our geography the same with the three core complexes, we're well versed in kind of what's out there. So hopefully that helps Jamie.

Yeah, that's good. And then maybe second question from me is just, there's been a fair bit of commentary out there about the increase in service activity that could accompany the LNG Canada project coming up. Have you seen this come through in any of the recent pricing and has Tourmaline contracted services to sort of get ahead of this? Would be my second question.

More from a facility construction standpoint or just drilling and completion?

Yeah, both, I suppose, Mike.

Okay. Well, we have contracted our drilling and completion services, and, you know, indeed, you know, we're 5% higher for that next tranche of activity than what we were originally forecasting, so that's all worked into our, you know, balance of 23 and 24 capital program. Our Montney Phase 1 development, we're already working on some of the components of that, and we've assembled a piece of the infrastructure already for that. So I think we're reasonably well insulated from further facility increases.

Okay, great. That's it for me. Thank you. Thank you.

And once again, if you would like to ask a question, please press the star 1 on your telephone keypad. Your next question comes from the line of Mike Thon from Steeple. Your line is open.

Thanks. Good morning, everyone. A couple of questions for me. Firstly, on the cardium oil discovery, just wondering if you could frame what the economics might look like for those wells under development mode, maybe what well costs might look like. And I'll follow up with a second question after.

Okay, sure well it's a strong well looks like somewhere between 250 and 300,000 barrels our estimate of recoverable oil and probably 2 BCF with that That was a off a tree well pad, but we only drilled one cardium location We actually made two other new cool discoveries off the same bed so three horizontals on that pad into three different zones so you know as we move into development mode and We'll do a delineation pad in 24 and then develop in 25. You know, we expect to continually reduce the drilling and completion costs. So economics are obviously very strong with current pricing. So, you know, you're looking at IRRs north of 50% on something like that. Reserves of that nature and that deliverability and well performance. So, yeah, very strong, and the gas will be connected to our Muzzro plant, so we really have the gas solution already in place.

Great. Thanks, Mike. And then just on your options or how you're looking at how electrification might occur for your North Maunee Phase 2 project, maybe just if you could just frame for me the what the hurdles are there. I have heard that electrifying gas plants north of Peace River is a lot more challenging.

Yeah, we're looking at it. Lots of options. It's not clear yet what will happen to the grid. The other way you can electrify is generate it with natural gas and couple that with CCUS. So we're evolving all of those potential solutions along. And, you know, as we complete that evolution, we thought appropriate to move phase two by one year. But really, our plan, we focused on shareholder returns rather than, you know, very rapid growth. So we're very happy with what the five-year plan looks like and the spreading out of facility expenditures. So it's, you know, over the five years, it's a 33% increase in free cash flow that we can you know, the vast majority of which will be returned to shareholders.

Great. That's all from me, folks. Thank you.

Thank you. And your next question comes from the line of Dennis De Silva from Middlefield Group. Your line is open.

Hey, good morning, Mike. Good Q3 results. Quick question on the CapEx for 2024. Maybe give a little more insight into the increase in the plug and perp, your early days on that, and how you're maybe translating some of the anticipated improvements and well results into your production for 24 going forward?

Sure. Well, I'll sort of not answer those necessarily in the order you asked them. We don't incorporate improved production from trialing of new technology until It's trialed and we've been able to evaluate the results. So we just use existing performance curves as we build up 24 and performance over the five years. The 2024 capital budget, there's $225 million in there for the Bonavista asset. So the EP spending 24 that we put out yesterday compared to the guidance that was out there The EP spending is actually down when you incorporate Bonavista. We do fund the exploration program and what we call our environmental performance improvement initiative. So that's the diesel displacement and methane mitigation. That's funded out of free capital and gets added on to that 2.15 capital budget. So we thought we'd done a pretty good job holding it. And in fact, as I mentioned, EP spending is actually down a little bit. As far as plug-in perf and some of the more liquid-rich horizons in the Montanee, particularly in the North Montanee, we've been doing that, and we'll continue to evaluate what's the best option going forward. Our main focus is economic return. Obviously, we look at EUR and we look at well performance, but we're driven by economic return, and that's kind of the sort of guiding philosophy in that change to the five-year plan as well. We want to, you know, make as much money and be as profitable as possible, and so we're really excited about what that new plan looks like.

Great. Thanks, Mike.

Thanks, Dana.

And your next question comes from the line of Fai Lee from Woodloom Brown. Your line is open.

Great, thank you. Mike, I was just wondering about your exposure to ACO more in the 25 to 27 timeframe with LNG Canada coming on. Are you anticipating having more exposure than you currently have to the ACO pricing or something similar to, I guess?

Yeah, no, thanks, Fai.

I might let Jamie jump in on that one. Yeah, we do generally grow our exposure And we have this in the presentation on slide 23, but we're happy with a growing exposure to ACO in 25 and 26, and that's because it also coordinates with the startup of LNG Canada, which we think will be a bullish and tightening aspect of the supply and demand dynamics in the WCSB. We have been, over the last two years, adding export exposure into the West Coast. We've added, as we mentioned in the press release today, additional exposure into California. And these markets have been extremely high premium gas price markets for us in 2023. And we anticipate also them to be at a high premium in 2024. But in 25 and 26, as we bring on the phase one of Conroy, we're happy to have those exposed volumes sitting into the ACO bucket for now, because we see ACO as a tight and very competitive market for our gas with the startup of LNG Canada.

Okay, thanks. Yeah, I did see that the slide is increasing exposure. I just wasn't sure if that was going to change dramatically. as time passes.

Well, in general, the slide also incorporates the growth we have folding into the plan. We don't forecast added transportation agreements. So over time, we're always looking to augment our portfolio into premium markets. And so I think it is reasonable for you to anticipate there to be small changes to the physical nature of this plan. And of course, every year, we're looking to tactically add hedges that add value to the portfolio. So we're not a structural hedger But we do like to look out the curve and find areas in each of our markets, including our local one, where we can protect exposure, particularly often in the summers. But in general, our view is that 25 and 26 are going to be buoyant gas price markets and likely offer prices higher than they are today. So I don't think we're that aggressive on looking at locking in any of the pricing in 25, 26 at the current time.

Okay, thanks for that.

Thank you.

And there are no further questions at this time. I would like to turn it back to Jamie Hurd for further remarks.

Yeah, we thank you all for dialing in today and joining us on this conference call. We hope you have a good rest of your day. Thanks.

Thank you, presenters and ladies and gentlemen. This concludes today's conference call. Thank you for participating. You may now disconnect.