Tourmaline Oil Corp.

Good morning, ladies and gentlemen, and welcome to the Tourmaline Q3 2024 results conference call. At this time, all lines are in listen-only mode. Following the presentation, we'll conduct a question and answer session. If at any time during this call you require immediate assistance, please press star zero for an operator. This call is being recorded on Thursday, November 7th, 2024. 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 Termaline's financial and operating results as of September 30, 2024, and for the three and nine months ending September 30, 2024 and 2023. My name is Scott Kirker, and I'm the Chief Legal Officer here at Termaline 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 Termaline 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 Robinson, our Chief Financial Officer, and Jamie Hurd, Tourmaline's Vice President of Capital Markets. We'll start with Mike speaking to some of the highlights of the last quarter and our year so far. After Mike's remarks, we will be open for questions.

Go ahead, Mike. Thanks, Scott. Morning, everybody, and we're pleased to update on a very busy and successful quarter, so a few of the highlights. Third quarter cash flow was $742 million or $209 per diluted share, and that was underpinned by average realized natural gas prices of $319 per MCF Canadian. Q3 net earnings were $355 million or $1 even per diluted share. We've declared a special dividend of $0.50 per common share to be paid on November 26th to holders of record on November 15th. And thus far this year, we've distributed dividends of $3.25 per share. That includes this special dividend, and that's going back to December 1, 2023. So an implied 5% trailing yield. During the quarter, we closed the previously announced transaction with Topaz. Energy Corp during this quarter and we received $278 million of proceeds. We closed the corporate acquisition of Crew Energy on October 1st and we're very excited about those assets. And as we outlined in the release, deep basin well productivity so far in 2024 is the best we've seen in the last five years. Looking at production, Q3 24 average production was a little over 557,000 BOEs a day. That's an 11% increase over Q3 23. And at the high end of our previously announced average production guidance for Q3 of 550 to 560,000 BOEs per day. And third quarter production was reduced by unplanned third party outages. And we quantified that as well as low gas price related frack and production startup deferrals by the company. Fourth quarter average production of between 600 and 620,000 BOEs a day is currently anticipated. Given the low pricing environment, we scheduled and have now completed an extensive turnaround of both phases of our large Gundy C60A gas plant complex. And we've also concentrated frack activity into the latter half of this quarter so that unhedged gas volumes come for exit and Q1 of 2025. We're expecting higher pricing than we have today. We expect to exit with very strong production levels of between 630,000 and 640,000 BOEs per day, and we're right on track for that. We anticipate 25 average production. We're using a range of between 635,000 and 665,000 BUEs a day at 650,000 BUEs per day at the midpoint. And that range allows for both price-related EP activity deferrals or shut-ins in the event of lower than anticipated 25 net gas prices. And conversely, if stronger prices materialize, then we can increase EP activity, and it'll all be within that range that we outlined. 25 forecast average liquids production is 162,000 barrels per day, so that's up a little bit from what we were expecting before, and we're slowly migrating our way to that 200,000 barrel per day level by the end of this decade. A little bit on the financial results. Third quarter cash flow was $742 million, as mentioned, on total capex of $591 million. EP expenditures, subset of that, $575 million. And that generated free cash flow in the quarter of $152.5 million. We had strong earnings, as mentioned, $1 per share. And that underscores the profitability of the business, even in an extremely weak natural gas pricing environment. Our exit Q3 24 net debt was $1.7 billion, and we've adjusted our long-term net debt target to $1.5 billion, and that represents between 0.3 and 0.4 times 25 net debt to cash flow ratio. And that's because of the material growth in the underlying business over the past year. In addition, as at September 30th, Our 45 million shares of Topaz have a market value of a little over $1.2 billion. On 25 capital budget planning, the board approved a full year 25 EP capital budget range to match that production range of between $2.6 and $2.85 billion. And the range provides flexibility in this current volatile and uncertain commodity price environment. We do continue to expect steadily improving natural gas prices in 2025, but should the recovery materialize in the second half of the year, we can sequence the capital program to be back half biased, and we'll always optimize annual free cash flow, and that's our top priority. We expect to drill approximately, in the mid-case, 365 wells in 2025 across all three EP complexes. and will save the incremental gas volumes for higher prices. Of note, the North Montney Phase 1 project is the only development project fully in the five-year plan, and it is still expected to add approximately 50,000 BOEs per day over the next three years. The Ground Birch, West Doe, and North Montney Phase 2 development projects will be fully integrated into the five-year plan during the course of 2025, so they're not in there now, although some of the facility spending for both Ground Birch and West Doe are in the 25 capital budget range that we quoted. On the marketing side, our average realized nat gas price was $3.19 per MCF, so that was significantly higher than the 805A benchmark of $0.70 per MCF. And we benefited, obviously, from our multi-year diversification portfolio and our hedging strategy. We expect to exit this year with total exports of 1.27 BCF per day out of the basin. And the majority of that is directed towards premium demand pull markets. For November and December of 24... We have an average of just a little over a BCF a day hedged at a weighted average fixed price of $4.01 per MCF Canadian. And in 2025, we have an average of $947 million cubic feet per day hedged at a weighted average price of $4.58 per MCF Canadian. And we have a lot of volumes that we leave open or unhedged to our stronger priced export markets. Briefly on the EP program, we drilled 76.8 net wells and completed 75.9 wells during the third quarter of 24, and we have an inventory of 38 ducts entering the fourth quarter. Currently operating 16 drilling rigs across the three core EP complexes and anticipate full year 24 EP spending of about $2.1 billion. A big highlight for us is our deep basin well productivity. So far on IP 90s in 2024, we're up 20% on GAP and 40% on condensate over the average of the previous four years, 2020 through 2023. And the performance is attributed to multiple tier one plays across several strike areas within the deep basin. So it's not the result of a series of wells in just one sub-area. It's across the board. And as at September 30th of this year, the expiration program has added a little under 1,000 Tier 1 and Tier 2 drilling locations. And due to the ongoing success of the expiration program, we do continue in 2025. We can spend up to $150 million a free cash flow on expiration, but obviously there's complete flexibility around that spending. On our EPI, or environmental performance improvement efforts, as part of our ongoing joint venture with Clean Energy Fuels, we open new CNG fueling stations for long haul trucks, both in Calgary and Grand Prairie. And the partnership expects to have seven of those stations operational by the end of 2025. And that's a continuation of our multi-year diesel displacement initiative utilizing abundant lower-emission natural gas. So this improves the environment and builds gas demand. In 2025 and 2026, in the budget, we have three new water facilities to be constructed, and that'll bring our total to nine. as we slowly migrate all operations off any fresh water in our fracking business. And we're pleased to announce that Travis Taves has been appointed to our board of directors effective yesterday. And I think that's it for going through the press release, and we're more than happy to answer questions.