Vermilion Energy Inc. (NYSE:VET) Q3 2024 Earnings Call Transcript

Vermilion Energy Inc. (NYSE:VET) Q3 2024 Earnings Call Transcript November 7, 2024

Operator: 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. [Operator Instructions]. Thank you. Mr. Dion Hatcher, you may begin your conference.

Dion Hatcher: Thank you, Cindy. Well, good morning, ladies and gentlemen. Thank you for joining us. I’m Dion Hatcher, President and CEO of Vermilion Energy. With me today are Lars Glemser, Vice President and CFO, Darcy Kerwin, Vice President International and HSE, Randy McQuaig, 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 BOEs per day, including the impact from a planned turnaround in Australia and a partial shut-in of some of our Canadian gas as a result of very weak AECO pricing. Production is up 7% on a per share basis year-over-year, reflecting the positive impact of modest production growth coupled with consistent share buybacks. 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 for Q3.

This compares to AECO of $0.69 per MCF. Our corporate realized gas price for the quarter was $6.57 per MCF. That is nearly 10 times higher than the AECO price. Pure [ph] gas was the only commodity in our portfolio that increased quarter-by-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 netback for 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 Mica Montney asset in British Columbia.

Free 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 canceled 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 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 were subject to sub-a-dollar gas price for most of summer months. While we do have exposure to AECO, the majority of our gas wells in Western Canada are liquids rich, which means that liquids production make these wells more profitable. As a reminder, we also hedged 30% of our AECO exposure this year at prices much higher than what we deserve this summer. Furthermore, approximately 40% of our corporate gas production, or 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, and the past few years has 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 AECO. 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 for 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-declined portfolio reduces the amount of capital required to hold production flat, which becomes even more important if we are entering a period of lower commodity prices. Production for our international operations averages 30,237 BOEs per day in Q3. This incorporates new production from our SA-10 block in Croatia, and reflecting higher runtimes in Germany and Ireland, which is 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, and we’re now proceeding with completions and testing operations. This represents our third successful deep gas exploration well in Germany, including the Burgmoor 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 today 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 of 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 4600 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. Tie-in operations are progressing as planned, with production expected on stream in the first half of 2025.

We commence 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. Subsequent 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 require 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 BOEs per day, and currently exceeds 2,000 BOEs per day. We intend to drill additional wells in the upcoming years to keep this plant full of high netback European gas. On the SA-7 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 up 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 BOEs per day in Q3. Our primary focus during the quarter was increasing production on the new battery, tying in five monthly liquid-rich gas wells on the 921 pad on our Mica asset. In the deep basin, we drilled and completed three wells and brought on production one Manville 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 Parkman, the Nile, the Turner, and the Mallory formations on our land. Five Montney wells on the 921 pad continue to produce at strong rates, with an average IP90 of over 1,000 BOEs 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 costs over the last two years and remain on track for a normalized turret cost of $9 to $9.5 million for our two-mile well. This new battery and water infrastructure has achieved 99% run times since startup and is contributing to these cost savings. Our 921 wells were followed preferentially through our new 8-33 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 8-33 battery. We plan to de-bottleneck 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 BOEs today due to the strong performance of the 921 pad. We expect to average approximately 14,000 BOEs a day in 2025 with additional drilling and expansion of our infrastructure. Our current development plans we expect to increase production from Mica to 28,000 BOEs per day within the next few years which will contribute significant free cash flow for the company going forward. I will now pass it over to Lars to discuss our shareholder returns and outlook.

Lars Glemser: Thank you, Dion. 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 appreciation 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 at 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 which is about 1% above the midpoint of our original guidance range of 82,000 to 86,000 BOE 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 BOE 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 million to $625 million remains unchanged with Q4 2024 representing an active capital program in the deep basin Saskatchewan and the Montney 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.

Dion Hatcher: Thank you Lars. On closing is another strong quarter for Vermilion as we delivered on our production guidance and deliver strong financial results. As noted we benefited from our diversified portfolio provides exposure premium price European gas which resulted in a corporate realized gas price of $6.57. This quarter that’s nearly 10 times higher than the AECO benchmark. We’re excited about the exploration success we’ve had in Europe. 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 Mica Montney project in Canada and look forward to increasing production from this asset. As Lar mentioned we have made significant progress on our share buyback program and plan to continue buying back shares through the balance of the year.

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 or in process of finalizing our 2025 budget which will target modest production growth on a similar level of capital as ’24 while maintaining a return of capital framework. We are on track to return 50% of our excess free cash from the 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.

We plan to release our 2025 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.

Operator: Thank you. Ladies and gentlemen we will now begin the question and answer session. [Operator Instructions]. And your first question comes from the line of Mr. Dennis Fong of CIBC. Please go ahead.

Q&A Session

Dennis Fong: All right. Good morning and thanks for taking my question. I guess the first one is just focusing on Germany there. I was hoping you’d talk towards a little bit of a potential impact on the discovery in that second exploration. 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-up?

Dion Hatcher: Thanks Dennis. I think I got most of your question there in Germany the size and potential follow-up with this recent discovery. Yes for that. So yes this 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. As a reminder we did message this as being a lower chance of 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 yes, nice to see a welcome in that we had deemed to be a lower chance success but Darcy can maybe provide some context on the size here what you think for timing and follow-up.

Darcy Kerwin: Yes thanks Dion and thanks Dennis for the question. So yes, in this Wisselshorst 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 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 there’s 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.

Dennis Fong: No, great. I appreciate that context. I presume that’s probably more of a ’26 story than ’25 net-net.

Dion Hatcher: Yes, I agree with that, Dennis. We’ll do the flow testing here next similar to what we did in Osterheide. And then with that data, we’ll be in a better position to provide an update in market here early next year.

Dennis Fong: Great. No, I appreciate that context. My second question is the shipping gears towards capital allocation. Just again, thanks, Lars, for the context there. Obviously, seeing you guys pay down incremental leverage and kind of buyback stocks to the decoder 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 shorter 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, understanding that you still have that 50-50 allocation policy?

Dion Hatcher: 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.

Lars Glemser: Yes, no, thanks for the question, Dennis. I think, we still believe that that 50-50 allocation of EFCF to return a capital and debt reduction is an appropriate balance, especially for a commodity-based business. Paying down debt, 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 onto 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 account 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, Dennis, 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.

Dennis Fong: No, great. Really appreciate that. I will turn it back.

Dion Hatcher: Thanks, Dennis.

Operator: Your next question is from Menno Hulshof of TD Securities. Please go ahead.

Menno Hulshof: Thanks, and good morning, everyone. I’ll start with a question on Croatia. It looks like you just completed testing of the third of a four-well program on the SA-7 block. And just looking at the map, that’s quite a way west of SA-10 where you’re producing roughly 2,000 boe/d. What should we expect in terms of run rate production if all wells on the SA-7 block hit? And maybe you could just remind us of how large that block is, SA-7 that is, how many drilling locations you’ve identified and how you’re positioned from an infrastructure perspective?

Dion Hatcher: Thanks, Menno, for the question. It is early days on SA-7, 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 this block is surrounded by known, proven production with lots of infrastructure. So early days give a run rate, but ranges would be — we’re already over 2,000 BOEs 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, 8,000, but it’s early days. 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 again, 5,000 is the 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. We do this with leads and 3D seismic. So we still have a long list of additional prospects to test on this block.

Menno Hulshof: Thanks, Dion. And then the second question is on the Euro nat gas outlook, just 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 in 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.

Dion Hatcher: Thanks, Menno. Maybe I’ll answer the second question first on the acquisitions. We do continue to look for, evaluate, and screen opportunities. It’s been disclosed by another party that we do expect the assets that are onshore in the Netherlands to come to the market. Our understanding is mid-next year, so that’s something that we continue to monitor closely. That was for the majors, and again, a significant block of gas onshore in the 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 over quarter. Right now, we’re selling into a market that is bouncing around $17 to $18 per MCF strip for next year.

Again, it’s bouncing around $17 to $18 per MCF. 2026 is in excess of $15, so quite robust pricing. A couple things, maybe the noteworthy is, 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, we still think LNG is robust and can continue to grow in Europe itself. 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. 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 B to B 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 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 two 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 is really positioning themselves to needing to outbid the world for LNG. And we’re seeing that with these robust prices. Maybe on the hedging side, I’ll pass it over to Lars to provide a current update.

Lars Glemser: Yes, 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. 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.

Menno Hulshof: Yes, thanks for the color, Lars. I’ll turn it back.

Dion Hatcher: Thanks, Menno.

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

Amir Arif: Thanks. Good morning, guys. Couple of follow-up questions there. One, just on the Germany side, given the success of the first well and then the initial positive indication 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?

Dion Hatcher: Thanks, Amir. 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 major’s dominated for years, and as they’ve over time allocated capital to other areas, you’ve seen a basin that as 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 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. 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 may anything to add to that, Darcy, maybe with the first well in the yard?

Darcy Kerwin: Yes. Amir, think of the first well in Osterheide. We have a pipeline right now at Lease Edge [ph] 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. Wisselshorst 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.

Dion Hatcher: Thanks, Darcy. The only thing I can add to that is it really comes in through 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. Back to you, Amir.

Amir Arif: That’s helpful. From the $17 million a day test rate, what rate would you plan to be putting that well on in 2025 relative to that test rate of $17 million?

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

Amir Arif: Okay. And then just keeping it flat, or potentially increasing it in 2026, it sounds like, if you have some debottleneck opportunities?

Darcy Kerwin: That’s keeping it flat throughout 2025, and then increasing that rate in 2026.

Amir Arif: I appreciate that. And then just on that third exploration well that you are drilling now, just on that map on page five, Slide 5, is this prospect just south of the second exploration well? Or is this one a different exploration prospect altogether?

Dion Hatcher: Sorry, just to clear, you’re talking about where’s the location of the third well that we’re currently drilling?

Amir Arif: Exactly, relative to that second exploration well.

Darcy Kerwin: Yes, just picture the map here. It’s just, yes, you’re correct, just south.

Amir Arif: 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 it a different kind of prospect?

Darcy Kerwin: No, these are separate prospects that are risked separately, Amir. While this success certainly has us confident in the area, these prospects are independent and independently risked, and we don’t think necessarily success on one translates over into success on the next one.

Dion Hatcher: I think what I just built on Darcy’s comments, I think it does kind of validates our geological models, Amir, and their discrete prospects, but you’ve got the same team evaluating the seismic across those prospects, so it gives us 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 potentials and follow-up locations as well.

Amir Arif: I appreciate that. And then just a final question on, you touched on the net debt number, net debt a little bit, and I know it’s coming down nicely with every passing quarter. Is there a certain net debt level at which the 50% return on capital number increases? Or are you just slowly ratcheting? I know for ’25, you’re still assuming overestimating 25%. Just wondering when that number would move up beyond that?

Dion Hatcher: Good question. I’ll pass it over to Lars to provide some context on that.

Lars Glemser: Yes, thanks, Amir. And as I referenced in the earlier question, very comfortable with that 50% level on the return to capital side. I think in terms of debt levels, if we’re in that 500 million Canadian to a billion Canadian, 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.

Amir Arif: Okay, appreciate it. Okay, that’s all for me, thanks.

Dion Hatcher: Okay, thanks for that.

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

Travis Wood: Yes, good morning, guys. Thanks for taking the question. I 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 mentioned the large acreage position that you hold across the continent. And so 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?

Dion Hatcher: Thanks Travis for that. I’ll kick it off and then Lars, feel free to add. Yes, 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 acquisition in Ireland, like what we did about a year ago, or allocating capital right now into Germany or Mica for that. So 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 bank for a 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. So, but it’ll be a decision on capital allocation and risk returns. Lars, do you want to add to that?

Lars Glemser: Yes, 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 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, 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 flows.

So, that is what we look at is you can accelerate investment into the base business, which I think is getting — 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 buybacks? So, it is that longer term view in terms of where we’re going to allocate capital that we evaluate.

Dion Hatcher: Thanks, Lars.

Travis Wood: Okay. Yes, 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?

Dion Hatcher: Yes, thanks for that, Travis. I think it’s just sustainable access free cash flow over the long term. And I think, if we think about our model, we’ve talked about modest production growth, resilient and growing based dividend, and then the variable component to share buybacks and the combination of that, 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 over a million is the ability to augment that with that with a strong acquisition that only makes the business even better long term. And when we look back to some of the deals we’ve done, especially in Europe, they’ve been some of our best deals. When we get into the nuances of what we’re looking for, I think maybe where you’re going is if you’ve got a strong organic outlook in Europe, do you — are you okay buying an asset that’s got, let’s call it a [Indiscernible] asset that’s gotten 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, the combination pro former 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 echo Lars’s comments on there as well.

Travis Wood: That’s perfect. Thanks, both.

Dion Hatcher: Okay. Thanks Travis.

Operator: There are no further questions at this time. I would like to turn the call over to Mr. Dion Hatcher.

Dion Hatcher: Thanks. I’m going to turn it to Kyle for a couple.

Kyle Preston: Yes. 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 this rotliegend sandstone very widespread? Do you complete these wells vertically and frac them? And what are you doing to improve the takeaway capacity? I think we might’ve addressed the takeaway capacity, but maybe Darcy, you can provide some color on the first part of the question.

Darcy Kerwin: Yes, thanks. 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 rotliegend sandstone that you’ve mentioned, as well as the Zechstein carbonate, so both of those zones, the rotliegend 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, 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 frac. So yes, I think we touched on the infrastructure piece already.

Kyle Preston: 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?

Lars Glemser: Yes, thanks for that question. And we somewhat addressed this a little bit earlier too, but kind of what I’ll remind of is the share buyback program. 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, 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.

Kyle Preston: 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 reports so far?

Dion Hatcher: Yes, thanks, Kyle. I can take this one. It’s a really good question. If you think about our asset base, it’s a third international. And as a reminder, why do we do that? We want to have top-desk netbacks, a low-declined business, and flexibility for capital allocation, international assets. We’ve talked about premium pricing on European gas as well as on the oil side. I think we’ve averaged $5 a barrel higher than the Canadian. So it works. The declines on those assets are in around 12% 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 Netherlands for two decades. When we entered Netherlands, we had about 13 million barrels of 2P reserves. Since that time, we produced 30 million barrels. You look at a reserve book today, we 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 yes, 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 to P, if you go back a decade ago, we were 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.

Dion Hatcher: Well, with that, I think that concludes our 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.

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