Q4 2023 Vitesse Energy Inc Earnings Call

Participants

Ben Messier; Director, IR and Business Development; Vitesse Energy Inc

Bob Gerrity; Chairman and CEO; Vitesse Energy Inc

Brian Cree; President; Vitesse Energy Inc

James Henderson; Chief Financial Officer, Executive Vice President, Director; Vitesse Energy Inc

Michael Schwartz; Analyst; Jefferies

Chris Baker; Analyst; Evercore ISI

Jeff Grampp; Analyst; Alliance Global Partners

Donovan Schafer; Analyst; Northland Capital Markets

John White; Analyst; ROTH Capital Partners

Jeff Robertson; Analyst; Water Tower Research

Noel Parks; Analyst; Tuohy Brothers

Presentation

Operator

Greetings, and 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.

Ben Messier

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'm 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, and then Jamie 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. And 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 may be 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.

Bob Gerrity

Thanks, Ben, and 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 1st year of being up independent public publicly traded company. We paid a $2 per share 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 has high yielding inflation protected and leveraged 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 $0.5 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'll turn it over to the test as President, Brian Cree. Brian?

Brian Cree

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 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 had been permitted for development by our operators proved reserves at December 31st, 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 five-year development schedule. Total proved reserves had a PV-10 value of $682 million and decreased from 2022, primarily due to the reduction in SCC benchmark prices. As you see, oil prices used for 2023, reserves decreased by $15.93 a barrel compared to 2022. As you see, natural gas prices decreased by $3.72 an MMBTU and when combined with a 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. The test 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. And now I'll turn it over to our CFO, Jimmy Henderson, to review our financial highlights.

James Henderson

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. Now 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 72% oil time, bringing our annual production to 11,089 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. Gaap net income was a loss of $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 a overall leverage ratio right at 0.5 times. 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 for 2020 for ranges from 12,500 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 $100 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. Thanks to the great work of our operators, we quickly recovered and our total year expectations now remain unchanged. Kudos to the men and women on the ground. They're working to keep that production online. Those efforts are truly appreciated.
I also want to touch on the S. three, which we filed on February first. We filed those the shelf as a bit of corporate housekeeping, as we became as three eligible after trading on the New York Stock Exchange for one year, it provides us much more 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 see we still plan to stick with our strategy of maintaining a simple capital structure with minimal leverage even if we consummate a large, more transformative acquisition.
With that, let me turn the call over to the operator for Q&A.
I think thanks, everybody.

Question and Answer Session

Operator

(Operator Instructions) Michael Schwartz, Jefferies.

Michael Schwartz

Yes, Bob, Brian, Ben and Jimmy. And on your strategy in 2023. I wanted to ask about M&A opportunities you're currently seeing in the market. How does 2024 the opportunity set in 2024 compared to 2023. Are these primarily self source deals? And are there larger packages out there that are you're seeing in the market?

Bob Gerrity

Thanks, Michael. The I just want to remind everybody that we have a very full field team at Vitesse, including accounts 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 analytic so we do not with the deal flow that we have from an A. and 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 on I would I'd say that we 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.

Michael Schwartz

That's that's great to hear. And I just had one more follow up on the same point. And the second question. So how does the court entered plus deal and the consolidation that's happening in the Bakken and 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.

Bob Gerrity

Brian, would you handle it?

Brian Cree

Yes, Michael, obviously, we're always a big fan of any of the consolidation, new new operators coming into the basin. And that situation specifically, corn has done some great things with three miles driven opportunities. So we really we really look forward to that type of consolidation and the enhancement of and everyone kind of using the best of all technologies from an M&A perspective, I mean, our hope there would be that at some of that non-op may get to monetized. If they look to do that, we'll be right there to trying to pick any of that up.

Michael Schwartz

That makes a lot of sense and not great to hear. So I'll add one more point. I wanted to ask about differentials. You mentioned TMX and buck in 4Q diffs were quite wide and TMX has the potential to narrow that. Al, could you walk us through a little bit more on your outlook about where you think this could go in the Bakken and over kind of what timeframe? And is that kind of structural and will be sustained? Or is that a temporary change that will be mitigated and change going forward?

Bob Gerrity

Jimmy Choo or Michael?

James Henderson

Yes, I think yes, obviously right now we're impacted by the delay in the Trans Mountain expansion coming online and the 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 than services 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 a tightening of the gaps that we realize in North Dakota as those volumes on exit are our marketing area, 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 three 50 ish is probably what we should expect going forward. Once that all works, its way out. So we're optimistic about that returning to come to fruition as we go through the remainder of the back half 24.

Michael Schwartz

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

Operator

Chris Baker, Evercore ISI.

Chris Baker

Yes, good morning. I guess first question, 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 first 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?

Bob Gerrity

Yes, sure. I mean, I think there were a lot of articles that came out obviously, from 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 on seven to 10 days up there pretty substantial. We saw some reports where well more than 50% of production was off-line. So we've made our estimates for a for that month of January, and there's a significantly lower 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 on, which is why when we look at everything as a whole, we decided to keep our guidance.

Chris Baker

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

Bob Gerrity

Yes, you know, we talk about what our pipeline is. And at the at the end of the year, our pipeline was was just under 17 net wells. Typically let 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 with our acquisitions and how many wells are still in the dock status and whatnot. So it feels like it's we're right, right in line kind of with our typical expectations over the past few years. And that feels like like when we combined that Bob mentioned the M&A activity and that includes our near term development acquisitions, that pipeline is still strong you know, 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, feels like, you know, that's kind of why we again continued with our with our guidance into it 2024 unchanged.

Chris Baker

Great. Thank you.

Operator

Jeff Grampp, Alliance Global Partners.

Jeff Grampp

Yes, I guess, Jeff, I'm I'm curious on the on the production numbers in Q4, you guys kind of almost and the whole a 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?

Brian Cree

You know, 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 we 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 kind of as we had expected, maybe a little earlier than we expect. And I'm not sure that the performance itself was 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, you don't love to see those get turned down as fast as possible.

Jeff Grampp

And that was kind of more of the impact in the fourth quarter? Well, it just came on sooner than we had expected.

Bob Gerrity

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

Jeff Grampp

We got it and absolutely understood there. Appreciate that. And maybe to tie into that last point, Bob, 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 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 2013, it was 23 a gangbuster year were $35 million. Was that a slower year? How do you how would you kind of bookend from activity levels as you look in your crystal ball for 24?

Bob Gerrity

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 healthy year. So we'll you know, again, I can't give you a number, but Brian, you got any more color on.

Chris Baker

Everything I would really say is as they look, I mean we are our guidance is for $90 million to $110 million of CapEx in 2014. Part of that is a carryover from the acquisition, right? 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.

Jeff Grampp

Got it. That's really helpful. Thank you, guys.

Operator

Donovan Schafer, Northland Capital Markets.

Donovan Schafer

Hey, guys. Thanks for taking the questions. So the first one I wanted to ask about kind of coming back to the differentials and the Trans Mountain pipeline. Yes, 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 is yes, it's a type of production activity that takes time to ramp up. And so they've kind of missed time that and started ramping it up to get things rolling. And then the pipeline got delayed. But and 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 the 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 indicators showing that kind of natural gas burn uptick or increasing in the Alberta area on any kind of earlier indications, anything positive there? And if that could be that 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. Could that become significant in any way and any early indications.

James Henderson

Hey, Jonathan, this is Jeremy. I'll take a shot at that and thank you for providing that color on Komag's and how it affects North Dakota. I don't think I could have said it better myself. As far as the natural gas, you know, we're not really baking something into. Certainly we're more impacted because of the way the gas flows from North Dakota and this stream mix with NGLs were much more impacted by it. Market centers are in the Gulf Coast. And so we're definitely more impacted by Henry Hub and Mount Bellevue for the NGLs. So we're continuing to model that on sort of depressed scenario for our gas sales for the time being, we'd love to see more and more of a call on gas going north, but there's not as much infrastructure going that way out of North Dakota as there is with pipelines with with One Oak, et cetera, going down to the cell. But we'd love to see that from that change and see gas being and exported from North Dakota, more so into Canada to facilitate production up there, but we are not breaking that out at this point. Keep you apprised if we see things change fundamentally on that.

Donovan Schafer

Okay. That is helpful. And then I did I wanted to follow-up in the press release and you included an interesting data point, which was this 1.5 million BOEs in TDT reserves are added and this iteration of the reserve or that were coming from wells that had not been booked at all as pubs in the prior year. And as I understand, I think the idea here is we're trying to get around Lake as a non-operator with an operator that gets a little dirt here will drill here and we'll drill there and they can kind of stick to the plan and meet the SEC five year requirement of converting about 20% of pods in a given year. And you guys it's more of a, you know, a statistical game or something where you can sort of say, well, here's we can guesstimate numbers and come up with something where we'll hit 20% conversion rate by that. That is the issue once you get the exact right well locations and you can't do that. So this is kind of the flip side of that, right? Where it's like.
Okay. Here's something that will be where we picked the wrong exact locations, but we are right in the broader scheme of things. And here's this 1.5 million BOEs or an increase. So one, I guess if I'm the right idea there. And then two would be in your experience, is it kind of a consistent like this 1.5 million? And is there some consistency even in rough terms from year to year, like So if we're talking about a five year rule, my understanding is you take like the 1.5 and then you can multiply that by five to get 7.5 million BOEs. And then you kind of add that back until like the 40 you and I know I know I don't get in trouble with SEC stuff like I know, of course, technically the SEC folks wouldn't approve of that. So 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?

Brian Cree

So Jonathan, this is Brian. You did a great job of describing the impact of the pie of the pipeline. You did just a fabulous job right there of describing what happens for a non-operated working interest owner when they're trying to figure out what's going to get drilled over the next five years. Obviously, from our standpoint, we've got we take all the information that we've got permits, AFEs information from the operators and we tried to project out what we believe will get drilled over the next five 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. And we've got we've got some stuff that is 10, 15% working interest. We've got a lot of other wells that may be far less than 1%. We're 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's going to be a subset of properties drilled that are at lower working interest so that we just didn't expect to get drilled. And so you're you nailed it. I mean you hit it exactly out of the park with your explanation there. We're doing the best we can to figure out what's going to get drilled over five years, but every year, there's 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 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 five. But what I would tell you is that there's no doubt that every year there are there are definitely properties drilled that we did not have in our in our proved reserves at the end of the year.

Donovan Schafer

Okay. Very helpful. And then just the last question and I'll take the rest offline after this is just true DD&A expense in the quarter, it was a significant uptick in absolute terms. And of course, I know a lot of that. I'd say probably even just the majority of that comes from increase the 24% quarter over quarter increase in production rate. But it does look like there was a bit of an uptick on in terms of DD&A per BOE. I think it went from end of 18, $18 high 10s to kind of low 20s. So is that just a matter of the acquisitions or was there anything else where like the reserve on existing wells there is a maybe tightening up of reserve base or something? Yes, if you if you say the remaining number of barrels is reduced in some way because of the type curve adjustment or something, then you're going to have to that will kind of accelerate that some of that DD&A recognition. So just curious if you can talk to what was the driver of the increase on a per-BOE basis?

James Henderson

Yes, David, this is Jamie. I'll give it a shot here that on the I'd say the increase was a combination of the acquisitions and in getting the arm on CapEx for those into the calculation and kind of a timing difference on the is I think the reserves will continue to increase as we go forward on those particular wells. But we put all the CapEx and as for various here in the fourth quarter, in addition to the change in the reserves that you were discussing earlier beyond the reduction in our total proved reserves is also part of that calculation. So will that factor and we true up the within the fourth quarter to that year end reserve calculation. So kind of a combination of both of those equally impactful.

Bob Gerrity

And I would just add to that 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 and when you're making those acquisitions at very attractive rates of return because of what you're 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 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 and capital costs. Any of that any of the costs on our balance sheet. They're 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 those things can cause that DD&A rate to fluctuate.

Donovan Schafer

Okay. Very helpful. I appreciate it. Thank you. Guys as interest my questions upfront, Foodstar.

Operator

John White, ROTH Capital Partners.

John White

Good morning, gentlemen. My question, my questions were on M&A and CapEx. And they've all been answered. Congratulations on the strong results and good luck for 2024.

Bob Gerrity

Thanks, John. Thanks for your support.

Operator

(Operator Instructions) Jeff Robertson, Water Tower Research.

Jeff Robertson

Thanks, Bob. We started off the call referring to invest as a technology company. Can you when you think about the M&A landscape and Illumina system that the test 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 tens where they're not where there's not a lot of drilling activity, two hands where there is drilling activity or it could be.

Bob Gerrity

Yes. Thanks a lot, Jeff, and thanks for Brett referencing the Luminous art, our database we take great pride in it and it develops, you know, generationally every month. So we have over 7,500. We have it fits 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, not a whole lot of second Marathon in this area is completing wells in a different fashion and they're getting really good early results. So we'll lean into a situation like that.
So on. So it's looked at 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.

Jeff Robertson

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've boost their returns?

Bob Gerrity

Yes. So the big trend is the three mile laterals and we were skeptical initially. I think I'm on record of saying we're just don't know about the results yet, but we're believers in it now and we're thrilled to have core takeover enter plus how technically and operationally to take a clean out. The plugs from three miles away is just an amazing technological advance. So on, we are really big believers in the three mile laterals. We think that those economics are our kind of under loved at this point and where we believe that the basin will move more towards the three mile laterals. So we see Bakken wells getting better and better pretty much every month just as an anecdote on 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, you know, again, the first?
Well, I was in the cellulose. You well produced 85,000 barrels in the 1st year, and that was a great well at the time economically. So, you know, it's we love the Bakken. We think that technologically it will continue to improve, and we're very happy with the load of undeveloped locations we currently have.

Jeff Robertson

And 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 and ultimately the potential for anything for a dividend increase at some point or maybe what would be a catalyst for that?

Bob Gerrity

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 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 abilities to make acquisitions that are accretive. So it's a fixed dividend. It's a $2, and I'll let you know, Jeff, we do this calculation every week so on it's something that we are keenly aware of and focused on.

Jeff Robertson

So well, I know there's very few securities with exposure to oil that have a dividend that is higher than a test.

Bob Gerrity

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?

Brian Cree

So it's a dividend. The dividend is our life, Jeff. So we have that. Thanks for your questions.

Jeff Robertson

Thank you.

Operator

Noel Parks, Tuohy Brothers.

Noel Parks

Hi, good morning. I just had a couple of questions. I was some and I apologize if you touched on this already, but could you just talk about the state of service cost inflation in the basket? And it's interesting over this earning season, we're hearing different things kind of a different base? And so any thoughts there would be great.

Brian Cree

It's Brian. I'll 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 as costs are just moderating. I mean, costs were 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 by 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 into higher service costs. I know that there have been some some comments about service costs coming down. Obviously, we'd love to see that. But at this point in time, we don't really have a view on where that is. We're just continuing to watch the AFEs and the actual costs as they come in and they seem pretty consistent over the last six to nine months.

Noel Parks

Great, thanks. And it's interesting talking in this quarter or in fourth quarter about just having some some wells come on line sooner than you expected sort of advancing, and that's also been something. And that has been a somewhat common refrain and sort of more used to things getting pushed off into into the on the upcoming year.
Just as companies tried to be mindful of capital discipline and just watch their spending. So I was just wondering on is for low, though, wells that you saw that that helped your volumes with those largely just at the operator's discretion, the timing of those or on or is there any other else?

Bob Gerrity

Got anything else going on there, Tom, that you're 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 our operators are different. I mean, we saw we saw some wells come on in the fourth quarter from one of our favorite operators that it was a spud date to date of first production just a little over two months is just we hadn't seen that before. You know, still the averages I would still say is six, seven, eight months from from spud to date of first production. Some of those wells that we acquired in the third quarter were further along and and those operators. And luckily, they were very high working interest wells and they the operators were able to get turned on faster even than we had expected in underwriting.

Noel Parks

It's interesting. Thanks a lot.

Operator

Thank you. And there are no further questions at this time. I'll hand the floor back to Bob Gerrity for closing remarks.

Bob Gerrity

Great. Thank you again, thanks for participating and for the wonderful questions of MSC. A will be available to us for any follow-up calls, and you can always reach out to us again, thank you very much for your support.

Operator

Thank you. A participant.