In summary, consistent with our more S&P mandate, for the last three years, we’ve been delivering financial performance, highly competitive with the most attractive investment alternatives in the market as measured by corporate returns, free cash flow generation and return of capital. I fully expect 2024 to build on this track record. Our compelling investment case is simple, a high quality multi-basin U.S. portfolio and integrated global gas business that delivers peer leading free cash flow, a unique and differentiated return of capital framework that provides our shareholders with the first call on cash flow. The output of which is clear visibility to compelling shareholder distributions across a broad range of commodity prices. Sector leading growth in first share metrics, and a multi-year track record of consistent execution and proven discipline.
And perhaps most importantly, everything we’re doing is sustainable through the commodity cycle. This is due to the quality and depth of our U.S. multi-basin portfolio where we have over a decade of high return inventory and a disciplined and multifaceted approach to portfolio renewal. It’s also due to our differentiated integrated gas business that’s now fully realizing global LNG pricing as we continue progressing all elements of the regional gas mega hub concept. Rest assured our commitment to our strategy is unwavering and is built upon our core values, resilience across the commodity cycle and our long-term track record of success. With that, we can open the line for Q&A.
Operator: Thank you. We will now begin the question-and-answer session. [Operator Instructions] Our next question comes from Arun Jayaram with JP Morgan Chase. Please proceed.
Arun Jayaram: Good morning, Lee. Lee, I wanted to start off with an M&A, obviously a significant level of industry M&A activity, including a large transaction announced in your Bakken backyard last night. I was wondering if you could provide some perspective on how should we think about M&A for MRO post the Ensign transaction, and I did want to cite a recent example of a low cost Permian producer as a low cost structure such as yourself did announce a deal to get more scale in the Permian, adding more sticks on the map and the multiple appears to rerated it on that deal. So again, just some thoughts on where the M&A landscape and what this means for MRO.
Lee Tillman: Yeah. Thank you, Arun. First of all, size and scale are important, but it’s not obviously just about getting bigger, it’s about how do we get better. So any consolidation opportunity fundamentally needs to enhance our ability to execute on the path that we’ve been on really for the last three years that I just described in my opening remarks. We have a very clear, very transparent framework for assessing M&A. That framework is unchanged, and if anything, the bar is even higher now with the successful addition of the Ensign asset that you mentioned. And just as a reminder, Arun, there really five elements of that criteria. First and foremost, of course, is accretion to financial metrics. Secondly, accretion to our cash flow driven return of capital framework.
Third, accretion to our resource or inventory life with inventory that competes for capital from day one, clear industrial logic, which to us means going into basins where we have a well-established level of execution, excellence and credibility. And then finally, of course, doing all this without any harm to our investment grade balance sheet. We know that’s a challenging criteria, but we can be discerning and we can be patient. As I mentioned, with over a decade plus of high quality inventory, we can wait for those opportunities like Ensign that ticks all the boxes and that’s what made Ensign so compelling. I mean, we integrated that asset into our operations and essentially a couple of months, Mike and his team did a fantastic job doing that.
We never missed a step and we’ve seen others stumble in that very critical integration step. So, can we be acquirer? Absolutely. Should you expect us to still apply our criteria and be a discerning and be as disciplined as we are in our organic business? Absolutely.
Arun Jayaram: Great. My follow up is on E.G., Lee. You provided a five-year outlook, which suggests relatively stable earnings profile or EBITDAX relative to your 2024 guide. I was wondering if you could talk about opportunities to extend these financial outcomes in E.G. beyond the five-year threshold. As well as I was wondering if you could address the recent decision by a super major to exit E.G. And does that open up any opportunities for you given that country exit?
Lee Tillman: Absolutely. Well, first of all, I want to be very clear, the five-year view we provided was really just a scenario that matched up with the LNG sales agreement that we just inked last year. And so you should not interpret that as a life of LNG kind of model. This was just to match up with that certainty that we now had around that five-year TTF linked LNG sales agreement. The reality is that when we look at all of the things that we have active now and E.G., whether that’s methanol volume optimization, the future — potential for Alba infill drilling and even more third-party molecules like Aseng, we already see the path to extend well past 2030. So, don’t view that five-year view as anything other than just matching up with, in fact, that five-year sales agreement that we inked on TTF.
In terms of exits, out of E.G. by super majors, clearly that’s a very unique set of circumstances where you have a concession that’s kind of at the end of its PSC term. It’s a very mature oil play there. And again, pretty much end of field life that likely is going to be taken over by the government and run by the government. So very different set of opportunities than we would look like. And again, I would just take you back, Arun, to the criteria that we just talked about and making sure that we look at any opportunity through that same lens when we’re talking about doing something inorganically. But we do believe there’s a lot of opportunity outside of that within E.G., both from an equity molecule standpoint as well as a third-party molecule standpoint.
And the good news for us is when we were able to bring the Aseng molecules to E.G. LNG, that was our first kind of third-party framework, we can now replicate that framework going forward, and that project constructed a very significant piece of infrastructure that we can now use for the future.
Arun Jayaram: Great. Thanks a lot.
Lee Tillman: Thank you.
Operator: Our next question comes from Neal Dingmann with Truist Securities. Please proceed.
Neal Dingmann: Morning. Nice update. First questions likely for Mike, on your — you mentioned — Mike, you referenced the leading operational efficiencies, which are noted. I’m just wondering, could you maybe give a little more detail? Is it largely the longer laterals or, maybe what other key drivers would you point us to that that’s really driving this remarkable upside?
Mike Henderson: Yeah. We all, Neal, I can certainly answer that. So yeah, underlying resource play capital efficiency as we noted is improving in ’24. And I highlighted a few things there in my prepared remarks, but I think it probably starts with that consistently strong peer leading well productivity. When I look at our ’24 productivity by basin compare it to ’23 and Eagle Ford, I would say ’24 is looking very comparable to what we delivered in ’23. When I look at the Bakken, I would actually say our productivity is up marginally in ’24 really on the back of — we are going to go Bakken, Myrmidon and complete a few wells there. And then the Permian, it looks pretty flat from ’23 to ’24. So I think that’s the first thing I would point to.
The second thing, as you noted was the longer laterals we mentioned in the prepared remarks, they’re up 5% at a company level. Eagle Ford, they’re up about 10% year-on-year. Even Bakken is up just notionally a couple of percentage points. And then you look at the Permian, they’re up by 10% as well. And that is a big part of that capital efficiency driver. And then the third part is we are forecasting a little bit of deflation, albeit very modest kind of low single digit numbers there.
Neal Dingmann: Makes a lot of sense. And then, my second question, Lee, maybe for you or Dane, just on capital allocation. I’m just wondering, is there anything that would cause you to move towards — more towards the variable dividends or do you believe your active buyback program continues to be most strategic? And maybe around that, I mean, how should we continue to think about per share of growth? Obviously as you keep buying the shares back, it really continues to ramp that nicely, so I’d just love to hear your comments there.
Dane Whitehead: Yeah. Hey, Neal, this is — good morning. This is Dane. I’ll take a first cut at it. So, the bottom line is expect our framework and sort of the mix of return vehicles to remain unchanged in 2024. We’ve set all along sort of variable dividend is a — it’s a third mechanism that it’s on the table, but it’s not front and center for us at this point. 40% return to shareholders is a very firm commitment. That’s our primary commitment for use of capital. Base dividend, I talked about the sustainability of that base dividend is critically important to us, so dividend increases will probably be driven by the pace of share repurchases as much as anything because that kind of keeps the post dividend break-even flat. And it’s — right now we’re peer leading in the low to mid 40s.
Share buybacks again at mid-teens free cash flow yield, super efficient vehicle. And as you noted, they drive that per share growth on a pretty significant basis. The second use of CapEx or of cash — available cash for us, and you saw us do some of it this year, is paydown debt. We paid down $500 million worth of debt last year. Our leverage levels are — we’re comfortable with, they’re like one time net at the EBITDA at strip pricing, but I’d like to get them down and we’ve stated, we’ve got $5.4 million of gross debt today. We’d like to drive that down to $4 million gross debt, which was the pre-Ensign debt level. And so we will continue to allocate some excess free cash flow in excess of the 40% return to further improving the balance sheet.
Neal Dingmann: Great details. Thank you both. Go ahead.
Lee Tillman: Yeah. Maybe I’ll just add one thing to that too. I think, the power of a consistent and meaningful share repurchase program, you really see that showing up in the growth and the per share metrics that really matter. If you just look at 2023, we took out 9% of our outstanding shares that was roughly double the next best in our peer group. And, of course, that translated into tremendous value growth on a per share basis for our shareholders. So we still believe in that. I mean, again, we kind of look through the cycle. It’s a program that we set in place and let it run we dollar average. And we think it’s very powerful. If you rewind all the way back to October of ’21 that 9% comes 27% of our shares outstanding that we’ve retired. So it’s been a very powerful program for us and we remain extremely committed. We still have $2.3 billion of outstanding authorization against the repurchase program with our Board of Directors.
Neal Dingmann: Great point, Lee. Thank you all.
Operator: Our next question comes from Matt Portillo with TPH.
Matt Portillo: Good morning, all. Two asset level questions that I wanted to run by you. I guess first in the Bakken. Looking at the early time results on Ajax looks quite encouraging from a production and productivity perspective. Just curious if you could talk about potentially your learnings on the spacing design here. And then also as you kind of look across your acreage position, how much of your Bakken acreage might be set up for three-mile development moving forward?
Mike Henderson: Yeah. I’ll answer that one, Matt. In terms of the spacing pattern there, it was in a kind of 5 by 0 spacing, so five wells in the middle Bakken and there’s no three forks opportunity down there. And as you probably know, that’s kind of down to the southwest of the Hector area where we’ve been pretty active the last couple of years. What I’d say in terms of maybe a read through probably feels a little bit early, don’t have a lot of data to share. Obviously, we’ve just brought three of the wells online, we’ve got some early production there. What I’d probably tell you this quarter may well change next quarter. So rest assured thought we’ll continue to work our land position there hard and if there are any opportunities to get more extended laterals, you could — you can expect us to be talking about those in the future.
Lee Tillman: I think one of the things I would add too, Mike, though, is that certainly — even though we’re still waiting for a little bit more longitudinal production data to declare victory. When you look at the total well cost per foot and the savings that we’ve already captured there, it’s very significant. So from an execution standpoint, we feel very good about the D&C performance. So as you said, early returns on the production side, very strong, but absolutely encouraging on the cost side, on the D&C side.
Mike Henderson: Matt, I’ll maybe provide a little bit of more color there. The first of the wells that we did execute on a TWC per foot basis, we’re looking at those be 25%, sorry, below comparable to milers. And I think you couple that with the early production, couple of thousand barrels of oil equivalent a day, 80% oil, the IPs will probably be not as stout as you might expect up in Hector, but I think you’ll get that volumes back over the long term. So as Lee pointed out, you take the well productivity with the well costs, I would like to think that that’s going to present a pretty compelling case for Ajax in the future.
Matt Portillo: Great. And then just as a follow up. Looks like the Texas, Delaware is going to be about a third of your program, give or take in 2024. I’m curious one on the development plan here, are you moving towards development, or are you still working on delineating the resource? I know that 2023 was still kind of a learning year for you. And then two, just curious how well cost have progressed in this area. I think that was also kind of initiative last year is to get more reps on wells and get the cost down in that Texas, Delaware play, given that there’s high productivity trends, but the cost side of the ledger still needed some work.
Pat Wagner: Matt, this is Pat. I’ll take the development piece and maybe I’ll let Mike take out the cost piece. Yeah. As you said this — we moved this project into our development team last year. So it’s still longer an exploration project. It is in our development program. As I think you probably know, we have 13 wells that have been online for some time, nine in the Woodford, four in the Merrimack. And they continue to perform this as we expect. Excellent productivity, high oil cut, shallow declines, and low moral ratios. We will be bringing on nine wells this year. Two of those are leasehold wells, and then there’s two multi-well pad that will be bringing on. We’ve gone to longer laterals. We have this 57,000 acre blocking position, so that gives us the ability to drill really long laterals.
The wells we’re bringing on this year will average around two miles next year, or the wells will be drilling in the future will be up to 13,000 feet. From a development standpoint, we’re still looking at four by four spacing in the Woodford and Merrimack. I think I hit it all there maybe.
Mike Henderson: Yeah. Matt, from a cost perspective, what I’d say is we’re kind of still mid program, so to speak. We’ve just completed drilling the wells, not completed them yet, so don’t have all of the data to share. What I would say is from a drilling perspective, costs are in line with kind of pre-drill expectations. What I would say, maybe the encouraging thing is as we progressed through the drilling, it seemed that the efficiencies were getting better and therefore when we do get all of the costs, and I would expect that — you would see that natural that improvement in the cost as we get — quite frankly, we just get more reps.
Lee Tillman: Yeah. One other thing I’ll just mention too, this is a little bit of a subtlety, but the fact that we brought the two asset teams, Permian and Oklahoma together, and now that’s under a single leadership structure. And this is one of the areas where we can benefit from learning because of course, Woodford Merrimack drilling and completing in Oklahoma, that’s something that we’ve already kind of cut our teeth in. So we’re bringing a lot of those learnings and expertise now into this, if you will, joint asset team. Now that we have this Texas, Delaware play, with the Woodford Merrimack, because it is challenging drilling. I mean, let’s be honest. It’s deeper, it’s hard pressure, it’s more challenging, hard rock drilling, but bringing that expertise in from Oklahoma is certainly allowing us to advance up the learning curve a bit more efficiently.
Matt Portillo: Thank you.
Operator: Our next question comes from Neil Mehta with Goldman Sachs.
Neil Mehta: Yeah. Good morning Lee and team. First question I had was just post 2024, capital efficiency this year, another very strong year. But as you think about setting the sticks for 2025 and ensuring that you’re able to sort of continue at this capital efficiency pace, just some thoughts post 2024, and can you hold 190 of oil at 2 billion the CapEx?
Lee Tillman: Yeah. Well, it feels like we’re just now releasing 2024. So jumping hit 2025 is a bit of a leap. But first of all, let me just say Neil, we feel very good about our, I’ll say, underlying well productivity. I think it’s actually pretty remarkable when you think about the fact that we operated to, of what the market uses very mature basins, and we’re still very much holding the line on productivity that is already at the top of the peer space. So I think you have to keep all of this in the proper context. And certainly as we do our longer term modeling, clearly Permian will start competing for a bit more capital, but we believe that from a productivity as well as a capital efficiency standpoint, certainly as we look out over the horizon, we see ways to continue to hold the line and certainly hold the line if not improve on some metrics.
And again, we can have a lot of tools available to us, right? I mean, there’s some of the things that Mike talk about. There’s the fundamental, well designed, longer laterals, better completions, there’s execution efficiency, stages per day. Our rate of penetration on the drilling side, we’re just talking about the Woodford hard rock drilling. There’s supply chain optimization. We continue to work on how best to integrate and manage our supply chain. And then finally, there’s just the sheer commercial leverage. You can kind of put that in the deflation/inflation bucket, but all of those things give us an opportunity to continue to work on overarching capital efficiency as we move forward in time. Even though we may be moving to different parts, different geology, we certainly see a path to continue to protect our peer leading capital efficiency that we’ve worked very hard for.
Neil Mehta: Thank you. Yeah. And it definitely is notable. The question — the follow up question is just on the natural gas outlook in the U.S. It’s obviously a tough environment as you referenced in your comments, but how is your designing your plan for 2024, and you’re thinking about which areas you want to prosecute? Are you trying to maximize the value of your net backs? Thank you.
Lee Tillman: Yeah. I think Mike was pretty clear in describing the capital program that, that our program for ’24 already reflects the reality of where natural gas pricing sits today. So not surprisingly, we’re driving capital allocation to our three kind of black oil basins, Eagle Ford, Bakken and the Permian. Thus, a combination play essentially like Oklahoma is struggling obviously to compete for capital because of where we are on the commodity cycle, right? Doesn’t mean that it won’t compete in the future, but today because of the multi-basin model, we’re able to take a hard look. I mean, I think Mike said, it’s value over volumes and even though we’re taking a little bit of a downtick on OEVs, that’s by design, we’re driven by returns and value optimization, which is making our oil program very efficient in 2024, and very much our focus given where gas pricing sits today in North America.
Neil Mehta: Thanks team.
Operator: Our next question comes from Doug Leggate with Bank of America.
Unidentified Analyst: Hey, good morning, guys. This is actually Kaleo [ph] for Doug, so I appreciate you taking the question. My first question goes to inventory depth. You guys obviously can — continue to show a very consistent capital program with the emphasis on harvesting those mature assets. So hoping that you can provide a view on how you see the resource depth evolving on each one of your four U.S. plays. And when you think about that program as you work into the future, do you ever see the Anadarko Permian carrying the load of that program? And if so, when do you see it?
Lee Tillman: Yeah. There’s a lot in there. So let me maybe try to unpack a little bit of that. First of all, maybe just let me deal with the inventory question. Our team has been very successful at replacing inventory over the last five years, and there’s several ways that we’re able to do that. One is organic enhancement, and that can include everything from cost reductions in places where we operate, extending laterals, refrac and redevelopment work like we have ongoing in places like the Eagle Ford, so that’s helpful. We do small bolt-ons and even trades. One of the reasons that we’re now having a primarily two-mile-plus program in Delaware is because of all the good work around small acquisition, small trades there to allow us to get a more contiguous kind of position there.
And then we just talked about the migration of the Delaware, I’m sorry, the Texas, Delaware play from kind of exploration into the development program. And then finally there is large scale — larger scale M&A like we do with Ensign. You’ve got these four avenues to continue to replenish and in some cycles you lean on one more than another, but typically you need to see all four of those to have a sustainable replenishment model. And that’s really what we’ve been able to prosecute over the last five years and hold that 10-plus-decade plus of inventory relatively constant over that period of time. So you should expect us to use that same playbook going forward. I mean, every year is not going to have a large scale M&A, but certainly every year we’re investing in things like organic enhancement.
We’re investing and still trying to progress some of our exploration place. So those things are just part and parcel of how we address inventory replenishment. At a basin level, we allocate capital at an enterprise level, so when we look at our inventory, we’re looking at it from a holistic standpoint. And that’s why, for instance, today you see Permian starting to compete for more capital allocation. And so, when we think through that 10-plus-year inventory, we think through it with a mindset of managing it at an enterprise level with basins coming in and out and receiving capital allocation based on the highest return and the best fit for us to continue to generate sustainable free cash flow generation.
