Good morning, ladies and gentlemen, and welcome to Tourmaline Q3 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 at any time during this call you require immediate assistance, please press 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 Heard. Please go ahead. Thank you, operator, and welcome everyone to our discussion of Tourmaline's results as at September thirtieth, twenty twenty-three, and for the three and nine months ended September thirtieth, twenty twenty-three and twenty twenty-two. My name is Jamie Heard, and I am Tourmaline's Manager of Capital Markets. 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 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 and 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 2024 plans, and answer questions you may have. So firstly, a few highlights. Third quarter cash flow was CAD 878 million or CAD 2.55 per diluted share. We generated free cash flow in the third quarter of CAD 332 million, or CAD 0.96 per diluted share, and that enabled us to declare a special dividend of CAD 1 per common share, and that was paid on November first. The company has distributed total dividends of CAD 6.52 per share, inclusive of the November one special, since December first of 2022, and that's an implied 9% trailing yield. Full year 2023 free cash flow forecast is now CAD 1.9 billion, so up. September 30, 2023, net debt was CAD 880 million, which is 0.3x Q3 2023 annualized cash flow of CAD 3.5 billion. Third quarter net earnings were CAD 275 million or CAD 0.80 per diluted share. As you know, in October, we entered into an agreement to acquire all the shares of Bonavista Energy Corporation for CAD 1.45 billion. That consisted of CAD 725 million in Tourmaline common shares and CAD 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 502,000 BOEs per day was at the higher end of our guidance of 495,000-505,000 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 2023 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 2024 average annual production to range between 600 and 610 thousand BOEs per day, and the formal guidance we're using in the five-year plan is 600 thousand 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 CAD 879 million on total CapEx of CAD 565 million. EP spending was CAD 533 million, so a little under forecast, and we generated free cash flow of CAD 332 million in the quarter. As of September 30, 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. 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 CAD 1 per share. And we also increased the base dividend from CAD 1.04 to CAD 1.12 per share on an annualized basis, and that's effective as of the December 2023 quarterly base dividend payment. Looking at marketing, our average realized natural gas price for the quarter was CAD 4.56 per Mcf Canadian, and that was significantly higher than the AECO 5A benchmark price of CAD 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 CAD 5.07 per Mcf Canadian. For 2024, the company has an average of 722 million per day, hedged at a weighted average price of CAD 5.35 per Mcf Canadian, an average of 119 million per day, hedged at a basis to NYMEX of -$0.05 per Mcf US. We have an average of 833 million per day of unhedged volumes exposed to export markets in 2024. 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 Henry Hub netback arrangement, and that'll move approximately 60 million per day to the U.S. Gulf Coast, and we're expecting that to commence in November 2026. We joined the NeeStaNan Venture as an industry supporter. That's an indigenous-led project that will create a multi-product utility corridor, including nat gas, and that will connect Alberta, Saskatchewan, and Manitoba to Tidewater on Hudson Bay. The project ultimately involves support for containers, potash, and other prairie products, and envisions an electrified LNG facility, actually, on Hudson Bay. Looking at our capital budget and financial outlook, as mentioned, third quarter CapEx was CAD 533 million on E&P. Full year 2023 EP capital spending is now anticipated to be approximately CAD 1.825 billion, and that is up from the prior CAD 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 2023, to first half 2024 EP season. And also we're accelerating the fracking of two pads into 2023 from or fourth quarter of 2023, from first quarter of 2024 due to faster realized drilling times. Our board of directors has approved a full-year 2024 E&P capital budget of CAD 2.15 billion. That reflects a 14-15 rig program, and that includes CAD 225 million associated with the Bonavista assets. That 2024 E&P program is expected to deliver cash flow at strip pricing of CAD 4.5 billion and free cash flow of CAD 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 we plan to continue our practice of quarterly special dividends during calendar 2024. Our updated 5-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. 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 2026-2028 timeframe. Of note, between 2022 and 2028, Tourmaline 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 3-4 frack spreads across our three EP complexes, and we anticipate adding 1-2 drilling rigs in calendar 2024 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 pace setter well in the North Montney, 4.91 days from spud to rig release for a 4,164-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 2022, 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 that will optimize production at the existing Muskeg and Kakwa plants that we operate. It's expected to add 15,000 BOEs per day during 2025 and 2026, again, into that anticipated stronger natural gas pricing environment. We also completed the acquisition of assets from Whitecap Resources Limited during the third quarter of 2023 for CAD 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 Resthaven Kakwa area. And we provided some details on that well. 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. Ladies and gentlemen, we will now begin the question and answer session. Should you have a question, please press the star followed by 1 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 2. If you're using a speakerphone, please keep the handset before pressing any keys. One moment, please, for your first question. Your first question comes from the line of Jamie Kubik from CIBC. Your line is open. Yeah, good morning, and thanks for taking my question. Just, just a question related to the Bonavista deal. Tourmaline's been relatively quiet in, in the past couple of years on the M&A front. Can you, can you just talk a little bit more about what the Bonavista acquisition brings to the company and, 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, you know, lots of opportunity for improvement and a large inventory and ability to grow the production. 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, you know, 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 2023 and 2024 capital program. Our, you know, Montney phase I development, you know, we're already working on some of the components of that, and we've assembled, you know, 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 star one on your telephone keypad. Your next question line comes from the line of Mike Dunn from Stifel. Your line is open. Thanks. Good morning, everyone. A couple questions from 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. 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 off a 3-well pad, but we only drilled one Cardium location. We actually made two other new pool discoveries off the same pad, so three horizontals on that pad into three different zones. So, you know, as we move into development mode... We'll do a delineation pad in 2024 and then develop in 2025. 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 profile. So yeah, very strong and the gas will be connected to our Muskeg 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 Montney phase II project. Maybe just... If you could just frame for me what the hurdles are there. I have heard that electrifying gas plants north of Peace River is a lot more challenging. Yeah, you know, we're looking at it... Talk to that. Lots of options. You know, it's not clear yet what'll happen to the grid. You know, the other way you can electrify is generate it with natural gas and couple that with CCUS. So we're evolving, you know, all of those potential solutions along. And, you know, as we complete that evolution, we thought appropriate to move phase II 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. That's all for me, folks. Thank you. Thank you. And your next question comes from the line of Dennis da Silva from Middlefield Group. Your line is open. Hey, good morning, Mike. Good Q3 results. Quick question on the CapEx for 2024. Can you maybe give a little more insight into the increase in, you know, the plug and perf, your early days on that, and how you're maybe translating some of the anticipated improvements in well results into your production for 2024 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, you know, build up 2024 and performance over the five years. The 2024 capital budget, there's CAD 225 million in there for the Bonavista asset. So the EP spending 2024 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 cash flow and gets added on to that, 2.15 capital budget. So, we thought we've done a pretty good job holding it, and in fact, as I mentioned, EP spending's actually down a little bit. As far as plug and perf and some of the more liquid-rich horizons in the Montney, particularly in the North Montney, we've been doing that. And, you know, we'll continue to evaluate what's, you know, the, the best option going forward. And, you know, 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, you know, 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, Dennis. And your next question comes from the line of Fai Lee from Odlum Brown. Your line is open. Great, thank you. Mike, I was just wondering about your exposure to AECO, more in the 2025-2027 time frame, with LNG Canada coming on. Are you anticipating having more exposure than you currently have to the AECO pricing or something similar to, I guess, the- 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 AECO 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. So 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 2025 and 2026, as we bring on the phase I of Conroy, we're happy to have those exposed volumes sitting into the AECO bucket for now, because we see AECO as a tight and very competitive market for our gas with the startup of LNG Canada. Okay, thanks. Yeah, I did see the slide and the increasing exposure. I just wasn't sure if that was gonna change dramatically, as time passes. Well, in general, the slide also incorporates the growth we have, you know, 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 2025 and 2026 are gonna be buoyant gas price markets and likely, you know, offer prices higher than they are today. I don't think we're that aggressive on looking at locking in any of the pricing in 2025, 2026 at the current time. Okay, great. Thanks for that. Thanks, Mike. Thank you. There are no further questions at this time. I would like to turn it back to Jamie Heard for further remarks. Yeah, we thank you all for dialing in today and joining us on this conference call, and 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.