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.