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.

Thank you, Laris. Our closing is another strong quarter for Pavilion, as we delivered on our production guidance and delivered strong financial results. As noted, we benefited from our diversified portfolio that provides exposure to premium-priced European gas, which resulted in a corporate realized gas price of $6.57. This quarter, that's nearly 10 times higher than the equal benchmark. We are excited about the exploration success we've had in Europe. We look forward to getting these wells on stream and following up with additional drilling in the months and years ahead. We're equally excited about the progress we've made on our Mike and Montney project in Canada and look forward to increasing production from this asset. As Lars mentioned, we have made significant progress on our share buyback program and plan to continue buying back shares through the balance of the year. We truly believe in the compound effect of combining modest production growth with a growing base dividend and share buybacks will drive shareholder value. We remain on track to achieve our 2024 production and capital guidance and are in the process of finalizing our 2025 budget, which will target modest production growth on a similar level of capital as 2024, while maintaining a return of capital framework. We are on track to return 50% of our excess free cash flow to shareholders in 2024 through our fixed dividend and variable share buybacks, representing approximately 10% of our market cap. We expect to continue providing rateable dividend increases and repurchasing shares in future periods. We believe Vermillion is very well positioned to execute on this plan, given our robust asset base and strong balance sheet. plan to release our 25 budget later this year, and we look forward to providing future details on our capital investment and our shareholder return plans for 2025. Well, that concludes my prepared remarks, and with that, we'd like to open it up for questions.

Thank you. Ladies and gentlemen, we will now begin the question and answer session. Should you have a question, please press star, then the number one on your touchtone phone. You will hear a prompt that your hand has been raised. Should you wish to decline from the polling process, please press the star followed by the number two. If you are using speakerphone, please lift the handset before pressing any keys. One moment, please, for your first question. And your first question comes from the line of Mr. Dennis Fong of CIDT. Please go ahead.

Hi, good morning, and thanks for taking my question. I guess the first one is just focusing on Germany there. I was hoping you could talk towards a little bit of the potential impact on the positive gas discovery in that second exploration well. Is there anything, I know it's maybe early before you're into testing, but can you talk towards what you're looking for in terms of size and depending on that size, what that could mean for follow-ups?

Thanks, Dennis. I think I got most of your question there in Germany, the size and potential follow-up of this recent discovery. Yes, for that. So, yeah, the second, I'll kick it off here and pass it over to Darcy. But just, you know, high level, the thing that I wanted to note is we're quite happy with this result. You know, as a reminder, we did message this as being a lower chance success, but a larger prospect. We saw more gas in place. And so the fact that we're able to get a discovery here, again, it just confirms the great work the team is doing on the technical side. But, yeah, nice to see a well come in that we had deemed to be a lower chance success. But Darcy can maybe provide some context on the size here and what you think for timing and follow-up.

Yeah, thanks, Dion, and thanks, Dennis, for the question. So, yeah, in this whistle horse well that we just reached TD on, We encountered a pretty thick sand package there, about 75 meters of net gas bearing sands across two zones. Preliminary estimated gas in place is potentially over 100 BCF there. Just to remind you, we're 30% working interest in that well. And I think you had a follow-up question around follow-up locations on this prospect. I think there may be follow-up locations immediately adjacent to this well, but requires a bit more work on our part to understand the results from this first well and then apply them across other leads in that area.

No, great. I appreciate that context. I presume that's probably more of a 26 story than 25.

Yeah, I agree with that, Dennis. We'll do the flow testing here next, similar to what we did in Ossorhide, and then with that data, we'll be in a better position to provide an update and market here early next year.

Just again, thanks, Lars, for the context there. Obviously, seeing you guys pay down incremental leverage and kind of buy back stocks through the quarter is quite helpful. Can you kind of remind us or give us any kind of incremental clarity on how you're thinking about where that ultimate net debt level should or could get to? And then, obviously, given where your share price sits here today, how are you thinking about balancing kind of share buybacks versus debt repayment

Thanks. Thanks, Dennis. Again, I think I got most of the question there around the potential debt targets that might trigger changes to our return of capital policy and the current allocation of share buybacks. But with that, I'll pass it over to Lars.

Yeah, no, thanks for the question, Dennis. You know, we still believe that that 50-50 allocation of EFCF to return of capital and debt reduction is an appropriate balance, especially for a commodity-based business. Paying down debt, you know, we do feel is prudent fiscal management. It improves the financial flexibility, especially during period of weak commodity prices. And then also allows you to be opportunistic on potential strategic acquisitions, kind of over the peaks and the troughs of the commodity cycle. I think the other thing to sort of reflect on, too, is you think about sort of return of capital here over the last three years. We initiated the dividend in 2022. We started buying back shares in the second half of 2022. We were only at 30% of free cash flow being returned in 2023 as we wanted to achieve some of the debt targets that we're at today. And so 2024 is an interesting year to reflect on, I think, Dennis, just in the sense of We've now repurchased 8 million shares through the first nine months. That's translated to a 7 million share reduction in our share count to that 155 million level. And so early days, I guess I would say into the return of capital, but we are starting to see the benefits of it in terms of delivering some of those per share, production per share numbers that Dion quoted in his prepared remarks. So I think in short, then it's still very comfortable with the 50-50 split. And the fact that we are providing meaningful return of capital returns, both through the dividend and the share repurchases here in 2024, I think reinforces that.

No, great, great. Really appreciate that. Thanks, Dennis.

Your next question from Manohar Shah of TD Securities. Please go ahead.

Thanks, and good morning, everyone. I'll start with a question on Croatia. Looks like he just completed testing of the third of a four-well program on SA7, on the SA7 block. And just looking at the map, that's quite a way west of SA10, where you're producing roughly 2,000 BED. What should we expect in terms of run rate production if all wells on the SA7 block hit? And maybe you could just remind us of how large that block is. SA7, that is, how many drilling locations you've identified and how you're positioned from an infrastructure perspective.

Thanks, Benno, for the question. You know, it is early days on SA7, but what we're excited about is the four discoveries and the discovery of hydrocarbons in multiple zones. The image, I think, also gives an insight to, you know, this block is surrounded by known, proven hydrocarbons. production with lots of infrastructure. Early days give a run rate, but ranges would be, we're already over 2,000 bees today with the SA-10 block. With any success on SA-7, I can see us getting to 5,000. Above that, maybe potentially 7,000 to 8,000, but it's early days. It really depends as well, gas versus oil mixture. The other thing, as a reminder, we did do a partnership with an in-country company that actually owns a lot of infrastructure around us. So I think that provides good access to infrastructure that will ultimately help reduce our overall development costs. So, you know, again, you know, about 5,000 is a number that wouldn't be a big stretch from where we are today. And then as we drill more wells and get some more success, we can further refine that. As to the number of prospects, we drilled four. I know the team had identified over 20. You know what, we do this with leads and 3D seismic. So we still have a long list of additional prospects to test on this block.

Thanks, Dion.

And then the second question is on the Ural NatGas outlook, just to, since it dovetails so well into all these questions. Could we just get a refresh on what you're currently seeing on the ground in terms of fundamentals? and how that's impacting your appetite for acquisitions and some of those asset packages that are hanging out there, and then maybe also an update on how aggressive you'd like to get on Euro gas hedges through 2025. Thank you.

Thanks, Menno. Maybe I'll answer the second question first on the acquisitions. We do continue to look for, evaluate, and screen opportunities as we've It's been disclosed by another party that we do expect the assets that are onshore in Netherlands to come to the market. Our understanding is mid-next year, so that's something that we continue to monitor closely for the majors. And again, a significant block of gas onshore in Netherlands, where we're the second largest operator, as you know. With respect to macro outlook, it's been really interesting. We touched on the call how that commodity, Euro gas, is up significantly year over year. It's up quarter per quarter. Right now, we're selling into a market that is bouncing around $17 to $18 per MCF. Strip for next year, again, is bouncing around $17 to $18 CAD per MCF. 2026 is in excess of $15, so quite robust pricing. A couple of things, maybe the noteworthy is, you know, first you got weather. We'll pretend to predict the weather, but we've had two very warm winters in Europe. Who knows? Maybe this is the year we get a normal winter. From a demand side, I mean, we still think LNG is robust and can continue to grow in Europe itself. I mean, you're seeing countries that are still, like Germany, for example, where they've said no to nuclear and a third of their power still comes from coal. So it's early days in our view in the transition of needing to get off of coal. On the supply side, we are seeing risks to some of the volumes that have been coming into Europe. There is about a bead, a bead and a half of gas that comes into Europe from Russia via Ukraine. That contract is set to expire later this year, and there's been a lot of news flow on the On that outcome, I suspect, and again, there's a lot of reasons why that gas won't keep flowing, but we'll see what happens there. But that's a B and a half. That's at risk. And then even LNG, like Russia still imports about 2 BCF a day of LNG into Europe. And Europe continues from a policy point of view. to roll out new initiatives to further restrict that Russian LNG from landing in Europe. So big picture is domestic production continues to drop in Europe, and Europe has really positioned themselves to needing to outbid the world for LNG, and we're seeing that create these robust prices. Maybe on the hedging side, I'll pass it over to Lars to provide a current update.

Yeah, thanks, Dion. Menno, on the hedging side, we did get to 50% here in 2024. We're actually 50% already for 2025 on European gas itself. I think there's a scenario where you potentially get up to 60%, but probably hedging on the margin for the remainder here of 2024 for 2025. 2026, we're actually 40% hedged on European gas. You know, as Dion referenced, a strong price curve out that far. And so we've taken advantage of that. And then we've initiated a position for 2027. So the bulk of our hedging focus over the next little bit is likely more on 2026 and 2027 as opposed to 2025, just given we are 50% hedged for that period.

Yeah, thanks for the color, Lars. I'll turn it back on. Thanks, Menel.

Your next question from Amir Arif of ATB Capital. Please go ahead.

Thanks. Good morning, guys. A couple of follow-up questions there. One, just on the Germany side, given the success of the first well and the initial positive indications from the second well, can you just remind us what your surface infrastructure capacity is and whether that needs to get upgraded or increased given the exploration success you're seeing?

Just on the bigger infrastructure, I'll kick it off and then Darcy, please jump in to add more. How we can think about Germany as an area where the majors dominated for years and as they've over time allocated capital to other areas, you've seen a basin that has over time declining production and it's left with a lot of legacy infrastructure. So when you think about gas plants and basic infrastructure for gas, all that's in place. So as we look to individual wells, then you get into the nuances of getting it from that surface lease to the closest gas plant. And again, there's a lot of infrastructure in place You know, so we're happy with that. We can leverage that infrastructure and utilize it as we look to drill wells in areas that were on trend with different prospects that were produced over the decades. But maybe anything to add to that, Darcy, maybe with the first well?

Yeah, Amir, think of the first well in Austin, Idaho. We have a pipeline right now at Lease Edge to tie in. We're just working on well site facilities for that gas well. We will be somewhat restricted initially when we tie that well in. There are some seasonal restrictions there, and depending on what other wells are producing into that system, we're pretty confident that over time we can de-bottleneck any restrictions that we see, and usually without spending any significant amounts of capital. Vitzel Source ties into another part of the network. We're only two kilometers away by pipe to the nearest tie-in point there, I think there's more capacity in that area, and we do have other options to add additional capacity if we chose to do so going forward. So I'd say in summary, both these wells have access to close-by infrastructure that has capacity, may have constraints from time to time, but are usually solvable without a bunch of CAPEX.

Thanks, Darcy. The only thing I can add to that is just it really comes down to a capital allocation. We'll have a list of things that we could do to accelerate production, and that'll compete for capital with other opportunities in the portfolio. But back to you, Mayor.

Okay, that's helpful. So just from the $17 million a day test rate, though, what rate would you plan to be putting that well on in 2025 relative to that test rate of $17?

In 2025, I think we're We're thinking about about 1,000 BOEs a day, Amir, for that well in 2025 once it's on.

Okay, and then just keeping it flat or potentially increasing it in 26, it sounds like, if you have some debodling opportunities?

Yeah, keeping it flat throughout 2025 and then increasing that rate in 2026.

I appreciate that. And then just on that third exploration question, well that you are drilling now, just on that map on page five, slide five, is this prospect just south of the second exploration well? Or is this one a different exploration prospect altogether?

Terry, just to clear, you're talking about where's the location of the third well that we're currently drilling?

Exactly, relative to that second exploration well.

Yeah, just picture the map here. It's just Yeah, you're correct, just south there of where that sector is.

Okay, so does the success of the first two wells increase your probability or chance of success of what you think you'll find with the third well? Or is that in the prospect?

No, these are separate prospects that are risked separately, Amir. While the success certainly has us confident in the area, these prospects are independent and independently risked. And, you know, we don't think necessarily success on one translates over into success on the next one.

I think what I just built on Darcy's comments, I think it does, you know, kind of validates our geological models. I'm error and they're discrete prospects, but you got the same team evaluating the seismic across those prospects. So it gives us, you know, increased confidence as we go from prospect to prospect. As a reminder, the third well, we do view as a higher chance of success. and a prospect that would be bigger than the first one and maybe smaller than the second one. So it's a nice combination of a high chance of success with potential some follow-up locations as well.

I appreciate that. And then just a final question on, you've touched on the net debt number, net debt a little bit. I know it's coming down actually with every passing quarter. Is there a certain net debt level at which the 50% return on capital number increases? Or do you just slowly ratchet it? I know for 25, you're still assuming or estimating 25%. Just wondering when that number would move up beyond that.

Good question. I'll pass it over to Lars to provide some context on that.

Yeah, thanks, Amir. And, you know, as I referenced in the earlier question, very comfortable with that 50% level on the return of capital side. I think in terms of debt levels, you know, if we're in that 500 million Canadian to a billion Canadians, That's where we're extremely comfortable with this 50% return to shareholders. If you were to go sub $500 million, and as a reminder, that's the amount of debt that we have roughly turned out to 2030, and you're truly building cash on the balance sheet, that could be an impetus to increase from that 50% level. So that's maybe a way to think about debt level ranges from an absolute perspective.

Okay.

Appreciate it. That's all for me. Thanks. Okay, thanks for that.

And last question from Travis Wood of National Bank Financial. Please go ahead.

Yeah, good morning, guys. Thanks for taking the question. Wanted to circle back and discuss more around M&A, but less so in the context of what's available and more so from a risk perspective. As you think about, you know, you mentioned the large companies acreage position that you hold across the continent. How do you think about drilling those? You've had some recent success, obviously, versus going to buy production in the context of using the cash build.

Thanks, Travis, for that. I'll kick it off, and then, Laris, feel free to add. I think it comes down to capital allocation. We'll look at opportunities across our portfolio, and we think that's one of our strengths, to be able to choose whether it's an acquisition in Ireland, like what we did about a year ago, or allocating capital right now into Germany or Micah for that. We'll frame them or run them all to ground, and we'll look at it from a risk basis to say, where do we see the biggest bang for our buck, not just in the short term, but the long term. I think we do have some unique skills when it comes to these acquisitions to be able to buy from the majors and work those assets harder and add incremental value. But it'll be the decision on capital allocation and risk returns. Lars, do you want to add to that?

Yeah. Travis, as we sort of walk through some of the questions here today, I think a theme that you're starting to sense here is there's quite a bit of capital being invested in today that's going to benefit sort of that 2026, 2027 and on period, especially when you start to think about assets like Germany and Croatia. And so, you know, it actually creates a competition within the portfolio in the sense of when you're looking at an acquisition versus accelerating investment into the base portfolio. Those are the time periods that we're looking at. We're not looking at kind of the near term upfront accretion. It truly is making a better business for that longer term, which has given us conviction to drill these German wells, drill these Croatian wells, knowing that there's not sort of that wave of instant free cash flow. So that is what we look at is you can accelerate investment into the base business, which I think is getting, you know, you're getting more and more projects there that are surfacing. Do you invest it in M&A or do you invest it in your own shares in terms of buyback? So it is that longer term view in terms of where we're going to allocate capital that we evaluate. Thanks, Lars.

Okay. Yeah, that makes sense. What about as you're looking at the M&A side, what's more important? Is it picking up production or... Are you able to assess the inventory depth and contrast that against the land spread that you have? I'm just kind of find myself asking the question here this morning, given the acreage position, really what would be the point of doing M&A outside of, again, kind of adding on the inventory side?

Yeah, thanks for that, Trent.

You know, I think it's just sustainable, access-free cash flow over the long term. And I think, you know, if we think about our model, we've talked about modest production growth, resilient and growing-based dividend, and then a variable component to share buybacks and a combination of that. You know, we're going to compound the business at 9%, 10%. Try to do our best to do that consistently year over year. And then we think what's unique for the shareholders of Vermillion is the ability to augment that with with a strong acquisition that only makes the business even better longterm. And when we look back to some of the deals we've done, especially in Europe, they've been some of our best deals. Um, when we get into the nuances of what we're looking for, I, you know, I think maybe where you're going is if you got a strong organic outlook in Europe, you know, do you, are you okay buying an asset that's got, let's call it a core black asset. That's got very, very high free cash flows, but maybe not the drilling inventory. So we'll do all that work from a long range plan to look at anything that's on the market. You know, the combination pro forma in our business. Ideally, you want both, as you always do. But again, I think the good news is if you've got a strong portfolio, things need to compete for capital to get into it. And that's where we are today. And I think that's, you know, echo Lars' comments on there as well.

Yeah, that's perfect. Thanks both.

Okay, thanks, Travis.

I would like to turn the call over to Mr. Dion Hatcher.

Thanks. I'm going to turn it to Kyle and a couple.

Yeah, thanks, Dion. We actually had a few questions coming online from our shareholders, which I'll read out here and give the management team an opportunity to respond to. First one is on the Germany exploration wells. Are these geological features just localized highs, or is the Rottliegen sandstone very widespread? Do you complete these wells vertically and frack them? And what are you doing to improve the takeaway capacity? I think we might have addressed the takeaway capacity, but maybe Darcy, you can provide some color on the first part of the question.

Yeah, thanks, Kyle. That's a good question. So in Germany, there's a number of different zones that are produced and that we're chasing. We're primarily focused on that Rottliegen sandstone that you've mentioned, as well as the Zechstein carbonate. So both of those zones, the Rottliegen and the Zechstein, are regionally extensive in Germany. And that kind of regional extension moves into the Netherlands. In fact, those are the same principal geological formations that we've been successfully exploiting in the Netherlands for the 20 years or so that we've been there. So I would say they... As you suggested in your question, both of those formations are very widespread, not just in Germany, but across borders into the Netherlands as well. They're both conventional reservoirs. Those reservoirs typically have high porosity, high permeability, and therefore high deliverability. So they're typically completed conventionally with... vertical or deviated wells to reach targets and complete it without the need to frack. Yeah, I think we touched on the infrastructure piece already.

Great. Thanks, Darcy. Next question here, I think this one's probably for Lars. You appear to be buying back a lot of shares under your NCIB, but this is not being fully reflected in your share count or your share price. Can you explain why this is the case?

Yeah, no, thanks for that question. And we somewhat addressed this a little bit earlier too, but, you know, kind of what I'll remind of is, you know, the share buyback program is, this really is the first year that it's kicked into high gear in terms of starting at second half of 22, limiting ourselves for the right reasons in 2023 to 30%. And so I think, you know, Q3 here is actually a bit of an inflection quarter in the sense that we've now repurchased 8 million shares this year in the first nine months, that's half the shares that we bought over the last three years. And so you're starting to see some of these production per share metrics, for example, where absolute production growth quarter over quarter was 2%. When you translate that to a per share basis, you get to 7%. And so not only are you seeing a lot of gross share repurchases, but you're also seeing a high level of net share repurchases. And just on that front, We do have a long-term incentive plan where we do make share issuances to create alignment with the employee base and investors. That's amounted to about a million shares this year. As a reminder for investors as well, for a good chunk of our executives, their compensation is in shares as well, up to 70% of their compensation. And so there's very good alignment there in terms of we're as keen to see that share count go down as our investors. And I think we are seeing that happen here through the first nine months.

Perfect. Thanks, Lars. We did have another question on when we expect to increase the dividend return capital, but I think Lars has already addressed that in the previous response. Last question we had here, you mentioned over a decade of drilling inventory in Europe. Do you know how many of these locations have been booked in your reserve report so far?

You know, if you think about our asset base, it's a third international. And as a reminder, why do we do that? You know, we want to have top decile netbacks, a low decline business and flexibility for capital allocation, international assets. We've talked with premium pricing on European gas, as well as, you know, on the oil side, we're able to I think we've averaged five dollars a barrel higher than the Canadian beer. So it works. The declines on those assets are in around 12 percent on our international portfolio. But the downside would be, I guess, from a reserve booking point of view, when you have conventional assets, you tend to book those individual prospects. When there's a well in the structure, you improve productivity. That is different than what you see in North America, where you're typically able to book more of a fairway view. If you look back at what we've done, and we've provided some new slides in our deck on this, but Netherlands is a great example where we've been in When we entered Netherlands, we had about 13 million barrels of 2P reserves. Since that time, we've produced 30 million barrels. You look at our reserve book today, we've still got 13 million barrels. And it kind of links back to Darcy's description of some of these formations and how pervasive they are and the number of structures. And I think the expertise that we built up over almost three decades looking for these things in Europe. So the conventional nature of those plays means that you book fewer of them at day one, but over time, we've got the skill sets to add them. As to the question, I would say less than half on a risk basis when we compare our internal long-range plan to what's booked would be how I would characterize that. So, yeah, we're happy with that type of assets and excited to deploy our skill sets to it. And I think where you see it show up, we would point investors as our reserve life index We're right around 14 years reserve life index. If you go back a decade ago, we were a 14-year reserve life index. So the consistency in which we're able to manage the business is, again, how we think about it as we go forward.

So thank you and Doug for that question. Well, with that, I think that concludes our presentation.

prepared remarks and the questions. So I want to thank everyone again for participating in our Q3 results conference call. Enjoy the rest of your day.

Ladies and gentlemen, this concludes your conference call for today. We thank you for participating and ask that you please disconnect your lines.