Vermilion Energy Inc. Common (Canada)

Good morning. My name is Cindy and I'll be your conference operator today. At this time, I would like to welcome everyone to the Vermilion Energy Q3 conference call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press star then the number one on your telephone keypad. If you would like to withdraw your question, please press star and then the number two. Thank you. Mr. Dion Hatcher, you may begin your conference.

Thank you, Sydney. Well, good morning, ladies and gentlemen. Thank you for joining us. I'm Dion Hatcher, President and CEO of Million Energy. With me today are Lars Glemster, Vice President and CFO, Darcy Kerwin, Vice President International and HSE, Randy McQuaid, Vice President North America, Kyle Preston, Vice President Investor Relations. We'll be referencing a PowerPoint presentation to discuss our Q3 2024 results. Presentation can be found on our website under Invest With Us and Events and Presentations. Please refer to our advisory and forward-looking statements at the end of the presentation, describes forward-looking information, non-GAAP measures, and oil and gas terms used today, and outlines the risk factors and assumptions relevant to this discussion. The third quarter of 2024 highlighted the strength of our diversified portfolio and the compounding impact of our share buyback program. Production during the third quarter averaged 84,173 buoys per day, including the impact from a planned turnaround in Australia and the partial shut-in of some of our Canadian gas as a result of very weak equal pricing. Production was up 7% on a per share basis year-over-year, reflecting the positive impact of modest production growth coupled with consistent share buyback. We generated $275 million of fund flows from operations during the third quarter, or $1.76 per share. This represents a 19% increase over the prior quarter, mainly due to stronger European gas prices. The Dutch benchmark, TTF, increased 14% over the prior quarter, averaging $15.52 per MCF in Q3. This compares to ACO of 69 cents per MCF. Our corporate realized gas price for the quarter was $6.57 per MCF. That is nearly 10 times higher than the equal price. Zero gas was the only commodity in our portfolio that increased quarter per quarter and year over year. Our diversification is a strategic advantage that positions us to generate more stable and higher cash flows. Due to the higher net back for our European operations, the cash flow for every BOE production we had in Europe is equivalent to adding three BOEs in Canada. We invested $121 million of E&D capital in the third quarter. Our primary focus was testing the remaining European wells drilled earlier this year, increasing production for the new gas plant on the SA-10 block in Croatia, and increasing production on the new battery at our Mike and Monty Asset in British Columbia. Our cash flow for the third quarter was $154 million, of which $59 million was returned to shareholders, including $19 million in dividends and $40 million of share buybacks. Year-to-date, we have returned $180 million, or $1.13 per share, to our shareholders. This is equivalent to 8% of our current market cap year-to-date. Our share buyback program is having a meaningful impact on our per-share metrics, as already noted with the per-share production growth. Year-to-date, we have repurchased and cancelled 8 million shares and reducing our outstanding share count to 155 million. We had also reduced net debt by $73 million to $833 million by the end of Q3. This represents a net debt to trailing fund flow ratio of 0.6 times the lowest in 15 years. Before I discuss the operational highlights, I want to briefly expand on my comment about the value of diversification. The past year was a very challenging year for North American gas producers. especially Canadian gas producers who are subject to sub-a-dollar gas price for most of the summer months. While we do have exposure to ACO, the majority of our gas wells in Western Canada are liquids-rich, which means that liquids production makes these wells more profitable. As a reminder, we also hedged 30% of our ACO exposure this year at prices much higher than what we've observed this summer. Furthermore, approximately 40% of our corporate gas production, or ACO, Over 110 million cubic feet per day is in Europe, where we have direct exposure to premium price global benchmarks. European gas has historically traded a premium to North American benchmarks. In the past few years, I've seen this premium widen. The trend continued in 2024 as European gas prices have increased over 30% year-to-date and now sells at an even wider margin of even wider premium to ACO. European gas prices remain elevated as the continent is still heavily dependent on LNG imports to meet demand, especially during the winter months. Europe continues to be our most profitable operating region and is an area where we expect to grow organically in the years ahead as we tie in some of our recent gas discoveries, while also seeking opportunities to augment this growth with strategic acquisitions. Our European gas production has increased by over 40% in the last two years, and we're excited about the potential for future organic growth in Germany, Croatia, and the Netherlands. The diversification continues to be a strategic advantage to help stabilize our cash flows with exposure to multiple commodities. In addition, our low-decline portfolio reduces the amount of capital required to hold production flat, which becomes even more important if we were entering a period of lower commodity prices. Production from our international operations averaged 30,237 views per day in Q3. This incorporates new production from our SA-10 block in Croatia and reflecting higher run times in Germany and Ireland, which was partially offset by planned maintenance downtime in Australia. Capital activity during the quarter was focused on completing and testing the remaining European wells drilled earlier this year, as well as increasing production from the new gas plant on the SA-10 block in Croatia. Subsequent to the quarter, we successfully completed drilling operations on the second deep gas exploration well in Germany. I'm very pleased to report that we discovered gas in the reservoir. We're now proceeding with completions and testing operations. This represents our third successful deep gas exploration well in Germany, including the Bergmore Z5 well we drilled in 2019. In total, we have drilled six exploration wells in Europe so far this year, all of which were successful. We're currently in the process of drilling a third deep gas exploration well in Germany to finish our 2024 European drilling campaign. This year was the largest exploration drilling campaign we have executed in Europe, and the results to date continue to validate our geological models while providing valuable information for assessing future drilling prospects. We have over 1.7 million net acres of undeveloped land in Europe and have identified numerous exploration and development drilling prospects. representing well over a decade of drilling inventory with the potential to provide meaningful organic growth. As noted in our operational update released in early September, in Germany, we successfully tested our first deep gas exploration well in the 2024 program. This well tested at a restricted rate of 17 million cubic feet per day of natural gas with a wellhead pressure over 4,600 PSI. The test rate was restricted due to limitations of testing equipment, but at this pressure reading, the deliverability would have been much higher without these limitations. Italian operations are progressing as planned, with production expected on stream in the first half of 2025. We commenced drilling on our second deep gas exploration well, as well as a 30% working interest well in August, and we successfully completed drilling operations at the end of October. As mentioned, we discovered gas within this reservoir, and we're now proceeding with completions and testing operations. Substantial to the quarter, we commence drilling on our third deep gas well and anticipate results from this well in the first half of 2025. The map on slide 5 shows a subset of the inventory we currently have identified on our over 700,000 net acres of undeveloped land in Germany. While our team continues to mature additional leads across this land base, as a reminder, some of these initial prospects are large enough if successful, to acquire a multi-well development program. In Croatia, we increased production on the SA-10 block after commissioning the gas plant in late June. Production in Q3 averaged 1,855 BUs per day and currently exceeds 2,000 BUs per day. We intend to drill additional wells in the upcoming years to keep this plant full of high-net-fact European gas. On the SA7 block, we completed testing on the third well of our four-well program, which was flow tested at 5.6 million cubic feet per day of natural gas. We're very encouraged with four-well exploration results in Croatia, which have proven out multiple producing zones and de-risk future development and exploration targets across four discrete areas. In contrast to the Germany exploration wells, the Croatia exploration wells are much shallower and are cheaper to drill. So while the rates on these wells are expected to be lower than the Germany rates, they can deliver strong returns. We're planning for future exploration drilling programs on this block, given the success of the 2024 program. Production from our North American operations averaged 53,936 buoys per day in Q3. Our primary focus during the quarter was increasing production on the new battery and tying in five Montney liquids-rich gas wells on the 921 pad on our mica acid. In the Deep Basin, we drilled and completed three wells and brought on production one man-built, liquid-rich natural gas well. The Deep Basin remains our largest producing area in Canada and continues to provide meaningful and consistent well results. In Saskatchewan, we drilled and completed and brought on production five light oil wells, while in the U.S., five non-operated light oil wells were brought on production. We continue to provide value data for evaluating the stacked oil zones in the Parkland, the Nile, the Turner, and the Mallory formations on our land. Five Montney wells on the 921 pad continued to produce at strong rates, with an average IP 90 of over 1,000 BUs per day, including 43% liquids. The total drill complete equipped tie-in cost of the 921 pad was approximately $9.6 million per well. We have significantly reduced our per-well cost over the last two years and remain on track for a normalized turret cost of $9 to $9.5 million for a two-mile well. This new battery and water infrastructure has achieved 99% run time since startup and is contributing to these cost savings. Our 9 to 21 wells were followed preferentially through our new 8 to 33 battery to maximize liquids production during this period of low gas prices. The gas stream for our BC Montney wells was also partially restricted to capacity constraints on our sales gas line from the 8 to 33 battery. We plan to de-bottle and connect this as part of our Phase 2 infrastructure expansion scheduled for 2025. Total production for our mica acid has increased since the start of the year and is currently over 13,000 BUs today due to the strong performance of the 921 pad. We expect to average approximately 14,000 BUs a day in 2025 with additional drilling and expansion of our infrastructure. In our current development plans, we expect to increase production from MICA to 28,000 Bs per day within the next few years, which will contribute significant free cash flow for the company to go forward. I will now pass it over to Lars to discuss our shareholder returns and outlook.

We continue to execute robust share buybacks during the third quarter, bringing our year-to-date share repurchases to 8 million shares, or 16 million shares since we started the program in 2022. When you combine dividends, share buybacks, and debt reduction, which are all forms of equity accretion, we have returned a total of $10 per share to shareholders over the past four years, as can be seen on the left of this slide. We have reduced our share count to approximately 155 million as of September 30th, 2024, and we continue to buy back shares in the market. As Dion mentioned in his earlier remarks, our share buyback program is having a meaningful impact on our per share metrics, as noted by our 7% year-over-year increase in production and FFO per share. The reduced share count also has an impact on the amount of dividends we pay and enhances our ability to increase the dividend per share. As you can see on this slide, we have delivered three consecutive years of dividend increases and we have the capacity to provide more dividend increases in the future. Our current annual dividend represents approximately 6% of 2024 FFO, which leaves ample flexibility to manage and even increase the dividend in a lower commodity price environment. Our production through the first nine months of 2024 has averaged 84,881 BOE a day, to 86,000 BUE a day. Due to our robust operating performance so far and our internal forecast for Q4 2024 production, which also accounts for approximately 2,000 barrel a day impact from third-party turnarounds and the partial shut-in of Canadian gas, we have narrowed the range on our 2024 production guidance to 84 to 85,000 BUE a day. The midpoint of this guidance would represent year-over-year growth of approximately 4% on a per share basis. Our 2024 capital budget of $600 to $625 million remains unchanged. With Q4 2024 representing an active capital program in the Deep Basin, Saskatchewan, and the Monteney in Canada, along with participating in several non-operated wells in the United States, and continuing with drilling and completion operations on the two deep gas exploration wells in Germany. With that, I will pass it back to Dion for his closing remarks.