Vitesse Energy, Inc. (VTS) Q4 2023 Earnings Report, Transcript and Summary

Greetings. Welcome to the Vitesse Energy Full Year 2023 Earnings Call. [Operator Instructions] Please note this conference is being recorded. I will now turn the conference over to Ben Messier, Director, Investor Relations and Business Development. Thank you. You may begin.

Good morning and thank you for joining. Today, we will be discussing our financial and operating results for the full year of 2023, which we released yesterday after market close. You can access our earnings release and presentation in the Investor Relations section of our website. We filed our Form 10-K with the SEC yesterday. I am joined here this morning by Vitesse’s Chairman and CEO, Bob Gerrity; our President, Brian Cree; and our CFO, Jimmy Henderson. Our agenda for today’s call is as follows: Bob will provide opening remarks on the year; after Bob, Brian will give you an operations update; then Jimmy will review our 2023 financial results and 2024 guidance. After the conclusion of our prepared remarks, the executive team will be available to answer questions. Before we begin, let’s cover our Safe Harbor language. Please be advised that our remarks today, including the answers to your questions, may include forward-looking statements within the meaning of the Private Securities Litigation Reform Act. These forward-looking statements are subject to the risks and uncertainties, some of which are beyond our control that could cause actual results to be materially different from the expectations contemplated by these forward-looking statements. Those risks include, among others, matters that we have described in our earnings release and periodic filings. We disclaim any obligation to update these forward-looking statements, except as maybe required by applicable securities laws. During our conference call, we may discuss certain non-GAAP financial measures, including adjusted net income, adjusted EBITDA, net debt, net debt-to-adjusted EBITDA ratio, free cash flow in the PV-10 of our reserves. Reconciliations of these measures to the closest GAAP measures can be found in the earnings release that we issued yesterday. Now, I will turn the call over to our Chairman and CEO, Bob Gerrity.

Thanks, Ben. Good morning, everybody and thanks for participating in today’s call and thanks a lot for everybody’s support this year. ‘23 was a successful year, our first year being an independent publicly traded company. We paid a $2 per share fixed dividend. And in addition, we were able to source some highly economic acquisitions that allow us to grow our production while maintaining a conservative balance sheet. Vitesse is a long-duration asset that is high yielding, inflation protected and leveraged to technology. Looking forward to 2024, our strategy remains the same. We will continue to return capital to our shareholders. To that end, last week, our Board declared a 2024 first quarter cash dividend of $0.50 per share to be paid at the end of March. After our fixed dividend, we allocate capital using our returns based hierarchy and extensive internally created database. We are very selective with how we spend our money. Cash goes to the highest return projects. We do not have a capital budget. Rather, we allocate capital to as many projects that meet our stringent return hurdles. With that, I will turn it over to Vitesse’s President, Brian Cree. Brian?

Thanks, Bob and good morning everyone. As Bob mentioned, we increased our 2023 production to 11,889 barrels of oil equivalent per day, with fourth quarter production of 13,652 BOE per day. The production from the acquisitions announced in October ‘23 came on sooner and slightly better than we had underwritten. So far in 2024, our production was negatively impacted by the severe weather event in North Dakota in January. Despite this event and the acceleration of production into the fourth quarter of ‘23 from ‘24, we are maintaining our ‘24 production and CapEx guidance, as Jimmy will discuss shortly. As a reminder, our production and CapEx can be lumpy from quarter-to-quarter. Our oil differential in the fourth quarter was wider than it has been historically as increasing oil production from Canada was transported through Bakken regional infrastructure. We expect oil differentials to improve when the Trans Mountain pipeline comes online in Canada currently expected in the second quarter of 2024. As of year end, we had 6.7 net wells that were either drilling or in the completing phase and another 9.9 net wells that have been permitted for development by our operators. Proved reserves at December 31, 2023 were 40.6 million barrels of oil equivalent, which was 70% proved developed. These proved developed reserves increased 5% from year end 2022. Total proved reserves decreased 7% from 2022 due to our removal of proved undeveloped drilling locations from our reserve report as a result of lower rig activity in North Dakota during 2023, partially offset by the addition of reserves associated with wells drilled in ‘23 from our unproven inventory. As a non-operator, our unproven locations are often drilled even though they are not included in proved reserves under the required SEC 5-year development schedule. Total proved reserves had a PV-10 value of $682 million and decreased from 2022, primarily due to the reduction in SEC benchmark prices. SEC oil prices used for 2023 reserves decreased by $15.93 a barrel compared to 2022. SEC natural gas prices decreased by $3.72 an MMBtu. And when combined with the decrease in NGL prices reduced our realized gas price used for reserves from $7.98 an Mcf in ‘22 down to $1.71 per Mcf in 2023. To help moderate these price movements, Vitesse has oil hedges in place for all of 2024 and the first half of 2025. At the midpoint of our guidance, we have approximately 42% of our full year 2024 oil production hedged at approximately $79 per barrel and 285,000 barrels of our first half 2025 oil production hedged at above $74 per barrel. Thanks for your time. Now I’ll turn it over to our CFO, Jimmy Henderson, to review our financial highlights.

Thanks, Brian and good morning everyone. Now to a quick review of our financial results for the year and our financial status. I want to highlight a few items from the fourth quarter and for 2023. And I’ll assume that you can refer to our earnings release and 10-K, which were filed last night for any further details. Our production levels increased to 13,652 for the quarter with a 72% oil cut, bringing our annual production to 11,889 BOE per day with about 68% of that being oil. Both amounts were above our updated guidance as production came on better and faster than we expected, as Brian just mentioned. For the year, adjusted EBITDA was $157 million and adjusted net income was $53.6 million, while our GAAP net income was a loss, $19.7 million. You can see that reconciliation in our press release that we just filed last night. Cash CapEx and acquisition costs for the year was $120.5 million, which is right at the midpoint of our latest revised guidance. We funded this investment with operating cash flows and withdrawals on our credit facility and debt at the end of the year stood at $81 million, resulting in an overall leverage ratio right at 0.5x. Our elected commitments were increased in January to $210 million as we added a fifth lender to our bank syndicate. With respect to our 2024 guidance, we are reaffirming our preliminary 2024 outlook. Our expected production for 2024 ranges from 12,500 BOE to 13,500 BOE per day with the 67% to 71% oil cut. We expect our total cash CapEx to range from $90 million to $110 million during the year. And note that our oil and natural gas production as well as our CapEx can vary from quarter-to-quarter based on whether new wells come online and from other operational matters that may arise. As Brian mentioned, our production was affected by extreme winter conditions in January of ‘24. But thanks to the great work of our operators, we quickly recovered and our total year expectations now remain unchanged. The big kudos to the men and women on the ground, they are working to keep that production online. Those efforts are truly appreciated. Also I want to touch on the S3, which we filed on February 1. We filed this shelf as a bit of corporate housekeeping as we became S3 eligible after trading on the New York Stock Exchange for 1 year. It provides us maximum flexibility, if needed, to find an attractive acquisition, but it was not put in place to fund anything imminent or any planned transaction. We will – we still plan to stick with our strategy of maintaining a simple capital structure with minimal leverage and even if we consummate a large, more transformative acquisition. With that, let me turn the call over to the operator for Q&A. Thanks, everybody.

Thank you. [Operator Instructions] Our first question comes from Michael Schwartz with Jefferies. Please state your question.

Hi, Bob, Brain, Ben and Jimmy. Congrats on the strong 4Q and the successful execution of your strategy in 2023.

Thanks, Michael.

I wanted to ask about M&A opportunities you are currently seeing in the market. How does 2024 – the opportunity set in 2024 compared to 2023? Are these primarily self-sourced deals and are there larger packages out there that we’re seeing in the market?

Thanks, Michael. Just want to remind everybody that we have a very full deal team at Vitesse, including accountants, finance people, engineers, land department and management. And we spend a tremendous amount of our time, both sourcing deals, self-sourcing deals and analyzing deals. So the fact that we have not done a deal of transformative size should not be indicative of what we’re going to do in ‘24. As a public company, we are seeing a lot more deal flow bespoke deal flow than we did as a private company. But again, we are extremely picky, selective and analytics. So we do not – with the deal flow that we have from an A&D perspective, our organic drilling and our near-term bought deals, we don’t have to do a deal. So we’re looking to do that transformative deal in a very greedy fashion. So I would – I’d say that because we haven’t done a deal, it’s not because we’re not looking and not because there’s not a lot of opportunities, but again, it would – we self-source almost everything we do. And we’re happy with what we’re seeing.

That’s – that’s great to hear. And I just had one more follow-up on the same point and then a second question. So how does the Chord Enerplus deal and the consolidation that’s happening in the Bakken impact M&A opportunities there? Do you think it increases the opportunities for you guys or decreases? Just trying to get a sense of how you assess the impact.

Yes. Brian, would you handle it?

Yes, Michael, obviously, we’re always a big fan of any of the consolidation, new operators coming into the basin. And that situation specifically, Chord has done some great things with 3-miles – 3-mile opportunities. So we really look forward to that type of consolidation and the enhancement of everyone kind of using the best of all technologies. From an M&A perspective, I mean, our hope there would be that as some of that non-op may get monetized if they look to do that. We’ll be right there to try to pick any of that up.

That makes a lot of sense and great to hear. So as one more point, I wanted to ask about differentials. You mentioned TMX. And Bakken 4Q dips were quite wide and TMX has the potential to narrow that. Could you walk us through a little bit more on your outlook about where you think dips could go in the Bakken, and over kind of what time frame? And – is this kind of structural and will be sustained? Or is it a temporary change that will be mitigated and changed going forward?

Jimmy?

Sure, Michael. Yes, I think, obviously, right now, we’re impacted by the delay and the Trans Mountain expansion coming online, but a pretty large pipeline that Canadian government’s building up there, and we’ll take a lot of oil further to the west and not down into the infrastructure of the services in North Dakota. So we do think that once that pipeline comes online, which I think is still expected in the second quarter here coming up very soon, then we should see tightening of the dips that we realize in North Dakota as those volumes exit our marketing area. And I think that – you can call that a systemic change, sort of returning back to what we’ve seen in the near distant future. I think the differentials that we saw earlier in the year, 350-ish is probably what we should expect going forward once that all works its way out, and so we’re optimistic about that. Returning to fruition as we go through the remainder of the back half of ‘24.

Perfect. That’s very helpful. And thank you for your time today. Really appreciate it.

Thanks, Michael.

Our next question comes from Chris Baker with Evercore ISI. Please state your question.

Yes, guys. Good morning.

Hi, Chris.

First question, I just wanted to touch on something you mentioned in the prepared remarks around Bakken weather. Can you maybe just frame up how many days? And then maybe kind of to the extent possible, connect that to where quarter volumes could shake out? I understand the guide for the full year is unchanged, and it’s sort of a temporary impact, but just curious in terms of the trajectory near-term. Any help there?

Yes, sure. I mean I think there were a lot of articles that came out, obviously, from our standpoint as a non-operated working interest owner. We’re not out in the field, but we do get some dailies and certainly, the weather impact was 7 to 10 days up there, pretty substantial. We saw some reports where well more than 50% of production was offline. So we’ve made our estimates for that month of January, and they are significantly lower than what we saw in December. From a guidance standpoint, I think we still believe the first quarter will be in the range of the lower end of our guidance, plus or minus, which is why when we look at everything as a whole, we decided to keep our guidance the same.

That’s helpful, thanks. And then just maybe sticking on the 2024 guide, any sort of relevant operator trends? And then maybe in terms of the activity backlog, if you could connect the dots in terms of where you guys stand today versus what’s baked into the guide would be helpful, just a broader context?

Yes. We talked about what our pipeline is. And at the end of the year, our pipeline was just under 17 net wells. Typically, that pipeline is anywhere from 15 to 20 net wells at the end of any quarter, just kind of depending on where we are with our acquisitions and how many wells are still in the DUC status and whatnot. So it feels like it’s – we’re right in line kind of with our expectations over the past few years, and that feels like when we combine that, Bob mentioned the M&A activity, and that includes our near-term development acquisitions. That pipeline is still strong. From our standpoint, we look at a lot of transactions, potential transactions, a lot of deals. We bid on almost everything, but we don’t have a very high hit rate. But when we combine kind of where our pipeline is right now with what we see on the organic side, it feels like that’s kind of why we, again, continued with our guidance into 2024 unchanged.

Great. Thank you.

Thanks, Chris.

Thank you. And our next question comes from Jeff Grampp with Alliance Global Partners. Please state your question.

Hi, guys.

Hey, Jeff.

I am curious on the production numbers. Q4, you guys kind of almost jammed whole year’s worth of production increase in one quarter. And you mentioned timing and well performance being the big factors there. I’m curious to dig into that a bit more and more curious on the performance side. Is that – would you characterize that as perhaps just some inherent conservatism that you guys tend to put in your model? Or is there anything maybe tangibly different that you saw from operators that might help explain the better performance?

Jeff, this is Brian. I’ll take a first crack at that and let Bob or Jimmy weigh in also. But one of the things we really touched on when we did those acquisitions at the end of the third quarter and talked about them in the fourth quarter, was that we were looking for – this was an opportunity to bring on some wells earlier than you would normally do in our near-term development acquisition strategy. Because typically, when we do that, we’re buying more wells that are just in the process of being drilled where during that third and fourth quarter, we were able to acquire things that were coming on sooner. And the unfortunate part for the fourth quarter is just a lot of those wells came on as we had expected, maybe a little earlier than we expected. I’m not sure that the performance itself was that much better than we had underwrite it. It was underwritten – it was a little better than what we had underwritten, but it was really the timing of those wells coming on sooner, which, again, from our standpoint, it’s all about velocity of capital. We want to make sure that when we acquire things, love to see those get turned on as fast as possible. And that was kind of more of the impact in the fourth quarter. Wells just came on sooner than we had expected.

Yes. Jeff, this is Bob. It’s that whole concept of when we see a deal that really is economic, we will buy it. It’s not like we have a fixed budget every quarter. So we don’t try to smooth our production. And in the third quarter last year, we found some really nice wells. And so it’s going to be lumpy, Jeff. It’s hard to extrapolate that, but when we see them that are attractive, we get them.

Absolutely. Understood there. I appreciate that. And maybe to tie into that last point, Bob – and with respect to acquisitions and maybe more of the ground game world, I think in ‘23, you guys did about $35 million in acquisitions. And exactly as you said, I know you don’t set goals per se for capital deployed, but in the context of what you’re seeing out there in your funnel today, how would you kind of handicap or assess what ‘24 may look like relative to ‘23? Was ‘23 a gangbuster year with $35 million? Was that a slower year? How do you – how would you kind of book and activity levels as you look in your crystal ball for ‘24?

Yes, fair question. Hard to give you a quantitative answer for that. We’ve been doing this for 12 years, and I will tell you that this is the best opportunity set we’ve ever seen. So that doesn’t mean we’re going to do everything, but we’re we’ve got a lot to choose from. So this is a – it’s a healthy year. So we’ll – again, I can’t give you a number. But Brian, you got any more color on that?

Yes. The only thing that I would really say is that, look, I mean, we – our guidance is for $90 million to $110 million of CapEx in ‘24. Part of that is a carryover from the acquisition we did last year. And so I think you can kind of back into our organic, which is we always talk about being kind of in that $40 million to $50 million range, plus or minus, of the organic. And so you can kind of do the math to what we’re expecting. It’s certainly not at the $35 million level that we had last year is not what’s baked into our guidance.

Got it. That’s very helpful. Thank you, guys.

Our next question comes from Donovan Schafer with Northland Capital Markets. Please state your question.

Hey, guys. Thanks for taking the questions. So the first one I want to ask about – kind of coming back to differentials and the Trans Mountain pipeline. Of course, that’s a crude oil pipeline, and that’s what’s kind of causing the wider differentials there. And some of that’s because I think I believe it’s Canadian oil sands production that is – it’s a type of production activity that takes time to ramp up. And so they’ve kind of missed time to started ramping it up, particularly, things get rolling and then the pipeline got delayed. But one other benefit of that is, it increases the natural gas consumption because they use a lot of natural gas. They burn a lot of natural gas to generate the heat and stuff they need for that – for extracting the oil from oil sands. So I’m just curious, are you starting to see – I don’t think we’ve seen anything in the pricing, but have you seen anything indicating or showing that kind of natural gas burn uptick or increasing in the Alberta area? Any kind of earlier indications of anything positive there and if that could be – if that can rise to a level of materiality or if that’s just to, I mean, obviously, production is very much skewed towards oil, but could that become significant in any way, any early indications?

Don, this is Jamie. I’ll take a shot at that, and thank you for providing that color on TMX and how it affects North Dakota. It could set it better myself. As far as the natural gas, we’re not really baking something in to improve, we’re more impacted because of the way the gas flows from North Dakota and the stream mix with NGLs were much more impacted by market centers in the Gulf Coast. And so we’re definitely more impacted by Henry Hub and Mont Belvieu for the NGLs. So we’re continuing to model that sort of depressed scenario for our gas sales for the time being. We’d love to see more of a call on gas going north, but there’s not as much infrastructure going that way of North Dakota as there is – with the pipelines, with ONEOK, etcetera, going down to the South. But we’d love to see that change and see gas being exported from North Dakota, more so into Canada to facilitate production up there. But we are not baking that in at this point. We’ll keep you apprised if we see things change fundamentally on that.

Okay. That is helpful. And then I did – I wanted to follow-up. In the press release, you included an interesting data point, which was this 1.5 million BOEs in TDT reserves are added in this iteration of the reservoir, that were coming from wells that had not been booked at all as puds in the prior year. And as I understand, I think the idea here is you’re trying to get around like as a non-operator – like with an operator, think is that we’ll drill here, we’ll drill here and we’ll drill there and they can kind of stick to the plan and meet the SEC 5-year requirement of converting about 20% of puds in a given year. And you guys as more of a statistical game or something where you could sort of say, well, peers, we could guesstimate numbers and come up with something where we’ll hit 20% conversion rate, but that actually want you to get the exact right well locations, and you can’t do that. So this is kind of the flipside of that, right, where it’s like, okay, here’s something that will be where we picked the wrong exact locations, but we were right in the broader scheme of things and there’s those 1.5 million BOEs where it increases. So one, I guess, if I’m – I have the right idea there. And then two would be in your experience, is it kind of a consistent like this $1.5 million, is there some consistency even in rough terms from year-to-year like – so if we’re talking about a 5-year rule, my understanding is you take like the 1.5 million and then you can multiply that by 5 million to get 7.5 million BOEs. And then you kind of add that back into like the 40 – I know – I don’t want to get in trouble with SEC stuff, like I know, of course, technically, the SEC folks wouldn’t approve that. But from the standpoint of – like just trying to roughly approximate what could be more similar to how things look for an operator? Am I kind of at least like on the right track there?

So Donovan, this is Brian. You did a great job of describing the impact of the pipeline. You did just a fabulous job right there of describing what happens for a non-operative working interest owner when they’re trying to figure out what’s going to get drilled over the next 5 years. Obviously, from our standpoint, we have got a – we take all the information that we have got, permits, AFEs, information from the operators, and we try to project out what we believe will get drilled over the next 5 years. A lot of our focus because of the amount of undeveloped acreage that we own and the wide range of our working interest ownership, we have got some stuff that is 10%, 15% working interest. We have got a lot of other wells that may be far less than 1%. We are going to spend more of our time trying to figure out which wells are drilled in the higher working interest wells. And so in any given year, there is going to be a subset of properties drilled that are at lower working interest or that we just didn’t expect to get drilled. And so you nailed it, I mean you hit it exactly out of the park with your explanation there. We are doing the best we can to figure our what’s going to get drilled over 5 years. But every year, there is going to be a group of properties that are drilled, completed and turned online that we did not have in our proved reserves at the end of a given year. Now, whether that’s averages 1.5 or more or less, I think it’s in the range. I haven’t done the calculation to be able to tell you whether you use the 1.5 and you can multiply that by 5. But I would tell you is that there is no doubt that every year, there are definitely properties drilled that we did not have in our proved reserves at the end of the year.

Okay. Very helpful. And then just the last question and I will take the rest offline after this, just to DD&A expense in the quarter is a significant uptick in absolute terms. And of course, a lot of that, I would say, probably even just the majority of that comes from the increased the 24% quarter-over-quarter increase in production rate. But it does look like there is a bit of an uptick in terms of DD&A per BOE. I think it went from kind of 18s – $18 – high-$18s to kind of low-$20s. So, is that just a matter of the acquisitions, or was there anything elsewhere like the reserve on existing wells, there is maybe tightening up of reserve base or something. Yes, if you say the remaining number of barrels is reduced in some way because of a type curve adjustment or something, then you are going to have to – that will kind of accelerate that – some of that DD&A recognition. So, just curious if you can talk to you what was the driver of the increase on a per BOE basis?

Yes. Jonathan, this is Jimmy. I will give it a shot here. But I would say the increase was a combination of the acquisitions and getting the CapEx for those into the calculation. And to have a timing difference on – I think the reserves will continue to increase as we go forward on those particular wells, but we put all the CapEx in depreciable base here in the fourth quarter. In addition to the change in the reserves that you were discussing earlier, the reduction in our total proved reserves is also part of that calculation. So, will effect and we true up the – within the fourth quarter to that year-end reserve calculation. So, it’s kind of a combination of both of those equally impactful.

Yes. And I would just add. One thing you got to think about there is from the standpoint of making acquisitions, when oil and gas prices are higher like they have been the last couple of years, when you are making those acquisitions at very attractive rates of return because of what you are paying to acquire those assets at those higher oil and gas prices, you are seeing a higher depreciable base being added into your overall reserve base. So, when you take that into consideration plus the fact that we pulled off a lot of proved undeveloped reserves that we just talked about. And then the final component of that is, from our standpoint, we don’t exclude any of our capital costs, any of the cost on our balance sheet, they are not outside of that depreciable base. So, we don’t have any unproven assets on our balance sheet. Everything on our balance sheet including all the costs associated with all of our undeveloped resource is included in our depreciable base. And so the combination of all of those things can cause that DD&A rate to fluctuate.

Okay. Very helpful. I appreciate. Thank you, guys. I will take the rest of my questions offline.

Thanks Donovan.

Our next question comes from John White with ROTH Capital Partners. Please state your question.

Hi. Good morning gentlemen. My questions were on M&A and CapEx and they have all been answered. Congratulations on the strong results and good luck for 2024.

Thanks John. Thanks for your support.

[Operator Instructions] Our next question comes from Jeff Robertson with Water Tower Research. Please state your question.

Thanks. Bob, you started off the call, referring to Vitesse technology company, can you – when you think about the M&A landscape and the luminous system that Vitesse uses, can you just talk about how that – how you can leverage that in the M&A market as you may see assets move from hands where there are not – where there is not a lot of drilling to hands where there is drilling activity or could be?

Yes. Thanks a lot, Jeff, and thanks for referencing luminous our database. We take great pride in it and it develops generationally every month. So, we have over 7,500 – we have interest in over 7,500 Bakken wells. And we scrape every piece of information about those wells. So, when technology changes, in frac technology, we see it immediately. And the data team is part of our deal team. So, when we have our weekly AFE acquisition meetings, data participates and said, well, no hold on a second, Marathon in this area is completing wells in a different fashion and they are getting really good early results. So, we will lean into a situation like that. So, it’s – look, the technology here changes incrementally every month. And we just want to be a little bit ahead of that and see if we can take some informational advantage.

Are you seeing – from the data you will collect, are you seeing rates of return in general improving markedly in the Bakken, or is it just maybe operator-specific where some operators have figured out an answer in the area that they work in and they boost their returns?

Yes. So, the big trend is the three-mile laterals. And we were skeptical initially. I think I am on record of saying we just don’t know about the results yet. But we are believers in it now, and we are thrilled to have core takeover of Enerplus. How technically and operationally, they clean out the plugs from three miles away is just an amazing technological advance. So, we are big believers in the three-mile laterals. We think that those economics are kind of under-loved at this point and where – we believe that the basin will move more towards three-mile laterals. So, we see Bakken wells getting better and better pretty much every month. Just as an anecdote, XTO had a three-mile lateral that was just completed. And in their first 30 days of production, they had over 108,000 barrels of oil alone. So, again, the first well I was in, the [indiscernible] well produced 85,000 barrels in the first year. And that was a great well at the time, economically. So, it’s – we love the Bakken. We think that technologically, it will continue to improve, and we are very happy with the load of undeveloped locations we currently have.

And then just on a philosophical note, the dividend at $2 a share annually is right around a 9% yield on the current stock price. Can you just talk about how you think about the fixed dividend levels and managing the business overall as you look at acquisition opportunities and cash flow reinvestment and ultimately, the potential for a dividend increase at some point, or maybe what would be a catalyst for that?

So, we are a dividend-paying company. We have the $2 fixed dividend, and that’s a healthy dividend. I believe that, that 9% yield is very attractive. And the calculus that goes into our setting the dividend is really complex, what the price of oil is, what our debt level is, how far out in the future we can hedge, what our opportunity set is, and what our ability is to make acquisitions that are accretive. So, it’s a fixed dividend, it’s at $2, and I let you know, Jeff, we do this calculation every week. So, it’s something that we are keenly aware of and focused on, so.

Well, I know there is very few securities with exposure to oil that have a dividend that is higher than Vitesse. So, it’s not that not that the dividend rate is low right now, but I think it’s interesting for your thoughts on how you think about it overall in the context of managing the business.

So, dividend is our life, Jeff, so yes. Thanks for your questions.

Thank you. And our next question comes from Noel Parks with Tuohy Brothers. Please state your question.

Hi. Good morning. I just had a couple of questions. I was – and I apologize if you touched on this already, but could you just talk about the state of service cost inflation in the Bakken? It’s interesting over earnings season, we are hearing different things kind of in different basins. So, any thoughts there would be great.

This is Brian. I will take the first crack at that. I think our view is that from what we have seen over the course of ‘23 and now into ‘24, is costs are just moderating. I mean costs were a little higher at the beginning of 2023. I think they moderated over the course of 2023. And we haven’t really seen a lot of significant changes one way or the other. Obviously, service costs are going to be impacted the amount of drilling activity. Rig count is up just slightly in the Bakken from where it was for a good chunk of 2023. That hasn’t translated for us yet into higher service costs. I know that there have been some comments about service costs coming down. Obviously, we would love to see that. But at this point in time, we don’t really have a view on where that is. We are just continuing to watch the AFEs and the actual costs as they come in, and they seem pretty consistent over the last six months to nine months.

Great. Thanks And it’s interesting, you were talking in this quarter or in the fourth quarter about just having some wells come online sooner than expected sort of advancing. And that’s also been something that has been somewhat common with frame. I am sort of more used to things getting pushed off into the upcoming year just as companies try to be mindful of capital discipline and just watch their spending. So, I was just wondering is – for the wells that you saw that helped your volumes, were those largely just at the operators’ discretion the timing of those, or is there any other else – anything else going on there that you are aware of?

Again, it’s something that we track by operator all the time because from our modeling standpoint, when a well is spud trying to determine when it’s going to come on data first production is something that plays a key role in any of our modeling. And all operators are different. I mean we saw some wells come on in the fourth quarter from one of our favorite operators that was a spud date-to-date of first production just a little over two months. It just – we hadn’t seen that before. Still the average is, I would still say is six months, seven months, eight months from spud to data first production. Some of those wells that we acquired in the third quarter were further along and those operators, and luckily, they were very high working interest wells. And they – the operators were able to get them turned on faster even then we had expected in underwriting.

Okay. Interesting. Thanks a lot.

Thanks Noel.

Thank you, Noel.

Thank you. And there are no further questions at this time. I will hand the floor back to Bob Gerrity for closing remarks. Great. Thank you. Again, thanks for participating and for the wonderful questions. Ben Messier will be available for any follow-up calls, and you can always reach out to us and again, thank you very much for your support.

Thank you. All participants may now disconnect.