Good morning, and welcome to the Marathon Oil Second Quarter 2023 Earnings Conference Call. [Operator Instructions]. I would now like to turn the conference over to Guy Baber, Vice President of Investor Relations. Please go ahead..

Thank you, Danielle, and thank you as well to everyone for joining us on the call this morning. Yesterday, after the close, we issued a press release, a slide presentation and investor packet that address our second quarter 2023 results. Those documents can be found on our website at marathonoil.com.

Joining me on today's call are Lee Tillman, our Chairman, President and CEO; Dane Whitehead, Executive VP and CFO; Pat Wagner, Executive VP of Corporate Development and Strategy; and Mike Henderson, Executive VP of Operations.

As a reminder, today's call will contain forward-looking statements subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied by such statements.

I'll refer everyone to the cautionary language included in the press release and presentation materials as well as the risk factors described in our SEC filings. We'll also reference certain non-GAAP terms in today's discussion, which have been reconciled and defined in our earnings materials.

So with that, I'll turn the call over to Lee and the rest of the team who will provide prepared remarks today. After the completion of these remarks, we'll move to a question-and-answer session.

Lee?.

shareholder distributions, free cash flow generation, reinvestment rate, capital efficiency, free cash flow breakeven and production growth per share. Our business plan remains on track with operational and financial momentum improving over the second half of the year.

More specifically, our first half weighted capital spending and completion activity will drive our third quarter total company oil and oil equivalent production to at or above the high end of our annual guidance range.

With both higher production and lower CapEx over the second half of 2023, we expect continued sequential improvement to our underlying free cash flow generation across the third and fourth quarters.

And finally, to our annual production guidance ranges remain unchanged, our full year oil equivalent production is trending above the midpoint of that guidance. Looking ahead to 2024. While it's too early to share any specific guidance, rest assured that our framework for success and core priorities will remain unchanged.

Our case debate will be another year of maintenance level oil production that maximizes our sustainable free cash flow and prioritizes shareholder distributions and per share growth.

My expectation is that we will once again lead the peer group on the metrics that matter most in 2024, benefiting from any deflation that might present itself in the market, as well as from the added tailwind of a significant financial uplift in EG from our increased exposure to the global LNG market.

With that, I'll turn it over to Dane, who will provide a brief financial update..

Thank you, Lee, and good morning, everyone. As we mentioned, second quarter was a tremendous financial quarter for us as we generated $531 million of adjusted free cash flow and returned $434 million of capital back to shareholders. That's a 10% increase in shareholder distributions relative to the first quarter.

Importantly, we expect our financial delivery to improve even further over the second half of the year.

On a price normalized basis, we expect our free cash flow generation to improve across the third and fourth quarters relative to the second quarter's already meaningful level, driven by higher expected production and lower capital spending consistent with the phasing of our 2023 program.

Returning significant capital back to our shareholders remains foundational to our value proposition in the marketplace. We're focused on building a long-term track record of consistent shareholder returns through the cycle that can be measured in years, not just quarters, and the first half of 2023 represents another successful step in that journey.

Through the first 2 quarters of the year, we returned over $830 million to shareholders, representing 40% of our adjusted CFO. First half return of capital translates to a double-digit shareholder distribution yield on an annualized basis, and that's the highest in our peer group.

Over the trailing 7 quarters, we've now returned approximately $4.6 billion back to shareholders. That's almost 30% of our current market capitalization that we've returned in less than 2 years.

We repurchased $4.2 billion of our stock at attractive levels, driving a 24% reduction in our outstanding share count, contributing to pure leading growth in our per share metrics. We remain confident.

Our cash flow-driven return of capital framework is uniquely advantaged versus peers, providing investors with first call on cash flow and offering them a differentiated shareholder return profile. Our framework is sector-leading and transparent, providing clear visibility to one of the strongest shareholder distribution yields in the entire S&P 500.

For the full year, we expect to continue to deliver against our framework, returning a minimum of 40% of our top line CFO to shareholders. We're committed to the powerful combination of a competitive and sustainable base dividend and material share repurchases. More or less our base dividend unchanged this quarter.

Keep in mind that we've raised it basically last 11 quarters, and we're well positioned for another dividend raise later this year, with the increase expected to be fully funded by the share count reduction from our buyback program.

This is consistent with our focus on sustainability and our objective to maintain one of the lowest post-dividend free cash flow breakevens in the peer space. Additionally, we have ample capacity to continue buying back a significant amount of our stock with $1.8 billion of share repurchase authorization outstanding.

Our plan is to maintain our return of capital leadership and improve our already investment-grade balance sheet through gross debt reduction. We can do both, and that's exactly what we're demonstrating. We paid down $200 million of high-coupon U.S. debt so far this year and remarketed $200 million of tax in bonds at a favorable interest rate.

The strength and durability of our shareholder return and balance sheet enhancement initiatives are underpinned by the quality of our assets, our disciplined capital allocation framework, our peer-leading capital efficiency and our strong free cash flow generation.

This is proven out by our leadership position when it comes to the most important metrics for our sector.

For full year 2023, we expect to deliver the best free cash flow yield in the high-quality E&P space, the lowest reinvestment rate and among the best capital efficiency, all while maintaining the lowest enterprise free cash flow breakeven on a pre- and post-dividend basis.

With that summary, I'll turn it over to Mike to provide a brief update of our 2023 execution that's delivering the sector-leading outcomes..

Thanks, Dane. My key message today is that the priorities for our capital program remain unchanged and that we remain fully on track to deliver on our key commitments to the market, including our annual capital spending and production guidance.

Starting with our capital program, we spent just over 60% of our full year budget during the first half of the year, fully consistent with our stated business plan.

We expect third quarter capital spending to be in the $400 million to $450 million range, with a further moderation expected in the fourth quarter and are well positioned to take advantage of any deflationary tailwind in the second half of the year.

For the full year 2023, the midpoint of our annual capital guidance remains a reasonable assumption for your models. In terms of the service cost environment, first half 2023 pricing was very consistent with our expectations entering the year.

We started to see a general plateauing of cost during the second quarter and had improved access to services and equipment. The macro environment remains dynamic. We've now started to see an improved pricing trend across raw materials and most service lines in equip, consistent with a lower level of industry-wide drilling and completion activity.

We'll look to capture better pricing where we can with the balance of the year, while continuing to protect our execution excellence, where we are also seeing a number of positive trends.

To that point, year-to-date, field-level execution has been very strong and efficiency outperformance has us tracking to the higher end of our annual wealth sales guidance in the Eagle Ford, Bakken and Permian.

While this won't have a material impact on our full year 2023 capital for production, it should enhance our production momentum into 2024, where we also believe there will be more opportunity to capture deflation in the market. Turning to production.

The phasing of our capital program is driving strong production momentum into a strengthening commodity price environment. For third quarter specifically, we expect total company oil and oil equivalent production to be at or above the high end of our annual guidance range before a modest sequential decline into the fourth quarter.

For full year 2023, we've reiterated our production guidance ranges of forward trending above the midpoint of guidance on an oil equivalent basis. The combination of higher production and lower capital spending over the second half of the year is expected to drive even further improvement to our underlying free cash flow profile.

Turning briefly to our integrated gas business in EG after receiving a substantial catch-up cast distribution. During second quarter we expect the relationship between earnings and cash distributions to normalize over the second half of the year. Third quarter distributions should be somewhat evenly split between dividends and return of capital.

Looking a bit further ahead to 2024, we continue to expect to realize significant financial uplift in EG on the back of an increase in our global LNG price exposure. We're right on track with all the necessary contractual milestones. And beginning January 1, 2024, all the sourced LNG will no longer be sold at Henry Hub linkage.

It will be sold in the global LNG market. This arbitrage between Henry Hub and global LNG pricing trickled with the highly competitive market for LNG cargoes from reliable suppliers is expected to drive significant financial uplift for our company at current forward card pricing.

To take further advantage of these new commercial terms, we are actively assessing up to a 2-well infill drilling program at Alba, targeting high confidence, low execution risk, shorter cycle opportunities that should mitigate base decline and maximize equity molecules through the LNG plan under the more attractive global LNG linked pricing.

These opportunities are expected to compete with the risk-based returns generated from our U.S. resource plays, although any Alba infill capital spending is unlikely to make a significant impact on our overall 2024 capital program. Yet, it's not just about capturing near-term commercial uplift in EG.

As we've stated before and consistent with the recently executed HOA with the EG government and our partner Chevron, we're equally focused on the longer-term outlook via the gas mega hub concept.

By truly leveraging our unique world-class infrastructure in one of the most gas prone areas of West Africa, we expect to extend the life of EG LNG well into the next decade and further enhance our multiyear free cash flow capacity. The next phases of development in the same gas [indiscernible] as well as potential cross-border opportunities.

With that, I will turn it over to Lee, who will wrap up our prepared remarks..

top-tier sustainable free cash flow generation with an advantaged return of capital profile and sector-leading per share growth, all underpinned by an investment-grade balance sheet. For 2023, we're well positioned to again lead both our peer group and the S&P 500 on the metrics that matter most.

If this pure-leading financial and operational delivery is not a 1-year phenomenon. It's a continuation of a multiyear trend and sustainable. And looking ahead to 2024, I don't expect anything to change. My confidence is underpinned by our high-quality and oil-weighted U.S.

unconventional portfolio that's complemented by our unique fully integrated global LNG business in EG. To close, I want to reiterate how proud I am of the way we position our company. We are results driven, but it is also about how we deliver those results. staying true to our core values and responsibly delivering the oil and gas the world needs.

And the world needs more energy, not less. The energy transition is really an energy expansion and oil and gas is uniquely positioned to drive global economic of living we have all content to enjoy. With that, we can open the line up for Q&A..

[Operator Instructions]. The first question comes from Arun Jayaram of JPMorgan..

Lee, Dan and Mike, you mentioned how your free cash flow should inflect in the second half of this year, just given the, call it, $450 million decline in higher output in oil prices. So I wanted to get your thoughts on how you balance cash return in the second half between equity holders, debt reduction and perhaps building up the cash balance.

You've been operating around $200 million in cash for this year. So just thoughts on balancing those 3 items..

Yes. Sure, Arun. Yes, the cash return conversation is so central to the value proposition for shareholders.

I might take a little longer than you anticipated to cover this, but just to be thorough, we've really been steady executing a return of capital framework and it calls for a minimum 40% of operating cash flow in the form of either share repurchases or a base dividend.

And obviously, our track record on meeting that minimum return, it's very solid and unwavering, and we expect that to continue that going forward. We returned exactly 40% in the first half 2023 CFO to shareholders.

That's $700 million in share repurchases plus $125 million base dividend, which equated to 11% [indiscernible] distribution yield is really at the top of the class in terms of return. Now on top of that, we also paid off $200 million of 8-plus percent coupon U.S.

tax debt and kind of balancing those share repurchases and returns to investors with debt reduction is something that will be a feature for us going forward. We certainly continue to see share repurchases as the preferred return vehicle for the lion's share of our shareholder returns. Our stock is trading at a free cash flow yield in the mid-teens.

So for purchases continue to be very value accretive, a real efficient way to drive per share growth, and they're synergistic with growing our base dividend, as I referenced in my prepared comments. We have $1.8 billion of repurchase authorization outstanding. So plenty of running room there.

And the per share growth that we're driving 24% since fourth quarter of 2021 when we restarted this program, it's pretty eye-watering. So for the balance of the year, we expect us to continue to return 40% of operating cash flow and look to pay down additional debt. Now make no mistake, the 40% return to shareholders is the top priority.

The second priority will be to continue to start to pay down the term loan that we took out when we acquired the Ensign Eagle Ford asset. We have a very significant cash flow inflection that we started to free cash flow inflection that we started to realize in the second quarter, but we expect that to continue in the third and the fourth quarter.

And even on a price normalized basis, we're going to have a lot more flexibility than we've had over the past couple of quarters to serve both of those needs, shareholder return and debt reduction. With the tailwind we're seeing in commodity prices, particularly WTI right now, that's going to provide even more flexibility.

We can go bigger on share repurchases, and we can go faster on debt reduction or some more likely some combination of those. You asked about cash balance. We're operating around $200 million right now. And in the course of the month, we actually made a negative.

It need to borrow on our credit facility a little bit, waiting for the big 20th of the month check for oil receipts, which is -- that's the big time when a big way for cash flow comes into the company. that working capital that we're managing the mechanics of that.

We actually just established a commercial paper program, which is very cost effective compared to the credit facility. And so I think we're comfortable with that. Over time, we may build up cash, but I don't -- it's not a priority for us right now.

Right now, it's going to be hit to 40%, exceed it where we can and take down that term loan to get that interest expense out of the system..

That's helpful. My follow-up maybe is for Mike, is kind of maybe a 2-parter. Mike, your updated TIL guidance is about 17 TIL is higher, 230 versus 213. Does that impacting any production from from the higher TILs, that was a question from the buy side.

And then maybe I'd love to see if you could describe the positive variance in the Eagle Ford this quarter and maybe a little bit light in the Northern Delaware, a couple of those variances in 2Q..

Yes. Just looking at the wells to sales cadence, I'd probably start the capital program is very much tracking its plan. So kind of we fully expect it to execute on that. Kind of purely typical for us to be more front-end loaded. We are seeing some outperformance from an execution perspective, particularly in the drilling space.

Looking back, and I think we've got a record quarter in the second quarter from a drilling perspective. Similar story in Permian where I think year-to-date, we've had our best-ever drilling performance, similar story in the completion space. And then in Eagle Ford, again, a similar story there.

I think what's encouraging in the Eagle Ford is with the Ensign acreage since we've got in there, we're probably drilling our wells about 10% faster than what they were drilling them last year.

So when you kind of combine all of that together, it's putting a little bit of pressure on the wells to sales in the year, but I think how I think about it, that pressure is going to really translate more so in the fourth quarter. So if you think about it, we're probably pulling a few wells in from the first quarter into the fourth quarter.

So from a capital and production perspective, not going to have a big impact on 2023, but potentially could set us up well or for the run into 2024 in the first quarter there. You asked specifically about Eagle Ford well performance. Yes, I think we highlighted the 74 branch wells in Atascosa County. Those are extended laterals.

We're seeing some great performance and great early production performance out of those, and that's an area of the play that we've got some future running room. I expect that's going to be a big part of our execution portfolio in '24 and then into '25. Hopefully, that answered all the questions that you had there..

Yes. I just think one, Arun, just on Permian to, you'd asked a little bit about why we saw a little bit of a step down sequentially there. That was generally speaking to a little bit of lag in our workover program, and we are on top of a couple of large producers that went down. We had to get a workover rig on them.

And then finally, we had some midstream gas takeaway that was a little bit delayed on one of our new pads in the quarter. All that's been resolved now. So really just a question of timing, no well performance issues whatsoever..

The next question comes from Josh Silverstein of UBS..

You had some comments before on the -- some of the EG infilling opportunities there.

Can you also talk about just the product scope of some of the other field developments, the time line for investments? Are these a couple of hundred million dollar products over 3 or 4 years? Just a little bit more about the scope of the opportunity there?.

Yes. You bet, Josh. Happy to do so. Yes, just maybe stepping back, first of all, on the infill drilling program. The objective here, of course, in EG is to continue to base load, our 3.7 MTPA train. We obviously prefer to do that with equity molecules.

But to the extent [indiscernible] will also drive third-party molecules there to maximize the value proposition out of this really world-class infrastructure.

The unique feature, of course, of the Alba infill program is that we're fully aligned across the value chain, from the AlpaPSC, all the way through EG LNG, so those are extremely valuable molecules and would ultimately help us offset and mitigate some of the decline that we're seeing from the Alpha field.

And again, remember, we have aligned interest that we've got about 64% interest in the Albin unit. We've got about 56% working interest in EG LNG and, of course, are operator of both. So the beauty of the program is this is going to be a very high confidence low execution risk.

And in the world of offshore production, we would consider this about a short cycle as you can get. These are -- this would be jackup drilling over existing facilities, typically reentry, dry trees. And so again, from an offshore perspective, these are relatively straightforward opportunities.

The work we're doing now is, of course, assessing the economics, really making sure that we have good solid target locations, working with our partners to ensure there's good alignment there, but ultimately, we believe up to 2 wells in Alba can compete with those risks at a very strong risk-adjusted returns that we're generating here in the U.S.

portfolio. If we can stay on track with an FID decision in the near term, then they could have us in a position subject to rig availability to may even be able to spud late '24 in that time frame. The way the capital will phase just quite frankly, on a say, a notional couple of billion-dollar budget, it's not going to be material.

It will be phased over time. And again, across our total budget, we just don't see this to be a big needle mover for us, but very accretive opportunities for our EG asset..

Got it. That's helpful. And then obviously, there's a lot of upside to come as the contract rolls off, but we've also seen a lot of volatility in TTF and international pricing. Is there anything you guys can do to take some of that volatility out? Are there -- is there a hedging liquidity? Are there contracts you can sign.

Just anything that you can provide there, given we've seen as much volatility there as we have here..

Yes, I think we've tried to show the notional uplift that we could obtain from the change in commercial terms that will occur January 1, 2024. And the reality is, Josh, as long as there is arbitrage between Henry Hub and TTF, there's going to be financial uplift in EG.

Really, it's just going to be a matter, as you said, of where does that global LNG market price ultimately land. We've shown some sensitivities, $15, $20 and $40 TTF. And in all those cases, there's material uplift relative to what we're seeing in 2023.

The work is ongoing from a commercial standpoint from the liquefaction agreement, the lifting agreements all the way through to LNG marketing. More to come on that.

But as I think we said in our opening comments, the good news for us is we're going out into a very competitive market today where LNG cargoes, particularly Atlantic Margin sourced LNG cargoes that are advanced into Europe are going to be very much sought after. And I would just emphasize that buyers are looking for reliable suppliers.

And over the life of EG LNG, we've never missed a cargo. And so I think we're in a very good position to maybe not damp out all the volatility that you referenced, but certainly take full advantage of the market price that's available to us..

The next question comes from Scott Hanold from RBC Capital Markets..

I guess just sticking with EG since we're on that topic. Could you give us some color on how those discussions with counterparties are going and your partners? And just give us a sense, if you could, on what, I guess, counterparties are looking for in terms of duration and flexibility as well, that would be helpful..

Yes. I would just say, first of all, this is a competitive process, Scott, that we're in. And from a milestone standpoint, we're right on track in terms of the commercial milestones that we laid out. And so I want to be absolutely clear. There's no question that we'll be receiving global LNG pricing come January 1.

Right now, we're in a competitive process with multiple buyers to, again, drive that competitive tension and deliver what we think will be the most value from whoever that counterparty will ultimately be. But that's an active ongoing competitive process right now, Scott..

I mean, are you able to talk about what kind of duration you're looking for? And obviously, you talked about maybe stabilizing the Elba field.

Is that part of showing that the assets have duration for those counterparties?.

Yes. I'll go back to my comment around reliability and security of supply. So certainly, duration is an important element that is in. Of course, the terms that we're currently discussing. But until we kind of complete that competitive discussion, I don't want to get too far into some of the commercial details.

Suffice to say though, Scott, that we do believe that we'll be able to provide a very solid runway of LNG cargoes for those counterparties. And so it will be -- certainly, we're looking at a longer-term kind of contractual relationship..

Okay. And then my follow-up is a little on 2024. You gave a few tidbits, but clearly, you're sticking to the maintenance program, but with some of the potential tailwinds coming into the year that you spoke of based on your more efficient program.

I mean, at a high level, that coupled with maybe some service cost savings, can you give us a sense of how in general, you're thinking about that CapEx budget relative to the one, I guess, 195 you're targeting this year?.

Yes. Well, of course, it's a bit early to start forecasting into 2024. But let me, first of all, just share a few thoughts. The case to be for us remains a maintenance oil production level, that means we're going to be back targeting kind of that notional 10,000 barrels of oil per day. So no real surprises there.

And in fact, even at a capital allocation level, I wouldn't expect a sea change in terms of the mix amongst even our assets as we look ahead to 2024.

I do believe, and I think Mike hit upon this in the comments that market trends continue to, I think, give us an opportunity to see some downward pressure in pricing I think we're well positioned to take advantage of that in the second half of the year.

But I don't think from a materiality standpoint, those deflationary impacts are really not going to take root until 2024. Now that's all going to be subject to the market kind of staying where it is. I mean on the service side, it continues to be a supply and demand market for them as well. So do I see an encouraging trend there? Yes.

Am I going to give you a quantification of that right now. It's just a bit too early to go there..

The next question comes from Neal Dingmann of Truist Securities..

My question is on the D&C specifically, like a number of your peers continue to sort of push the limits and see the benefits of going to larger wells, such as the 3 milers and talking about the upside that they see on returns from this versus the 2 milers and 1.

I'm just wondering do you all agree with this assessment? And if so, what type of opportunities in your plays do you have for this?.

Yes, Neal, it's Mike. Yes, I definitely, definitely agree with that assessment. It's been a focus area for -- I think it started predominantly with the Permian asset. We've progressed from a lot of single mile laterals there. Team has done an incredible amount of work over the last few years.

We've actually traded close to 5,000 acres over the last couple of years. And that's allowed us to develop this inventory of 10 years plus of 2 milers there. We've now expanded that approach. We're having a look at potential opportunities in the Eagle Ford and the Bakken.

What I'd say Permian is probably still the basin that I think presents the most opportunity for us. But I mean, as we as we included in the deck, we've got some opportunities that we just brought online in Atascosa County this quarter in Eagle Ford, I expect more of that. I mentioned that earlier in the response to run.

I expect more of those types of wells coming into the portfolio next year and potentially even '25, having a look in Bakken is probably a bit more of a limited opportunity set there, but nevertheless, the team are looking at. And even Oklahoma, we're drilling 3-mile Springer well at the moment. That's being drilled under the JV that we've got there.

But if that proves successful, I could open up a few more parts as well for us and oily pads also in Oklahoma, which is always helpful. So I'd characterize it by yet, we're definitely seeing the uplift, and it's something that the teams are actively progressing..

Very good. That's great to hear. And then my second question, just on sort of the regional oil production. I know you guys don't specifically guide on in each of the regions, but there's definitely continues to be a pretty nice notably pick up in the Bakken.

And I'm just wondering, I guess, almost simultaneously, it seemed like the perm fell a little bit more than we were anticipating.

I'm just wondering for each of those, or anything to read into that? Or is it just more timing of the D&C plan?.

I think in Bakken, you're seeing the benefits, strong execution there in the second quarter. You've seen the benefits and read through into volumes. I think that would translate into the third quarter as well.

And Permian, as we mentioned, we've had 3 or 4 quarters growing volumes there, but a bit of -- seeing some outperformance there, a little bit of underperformance this quarter. But again, as we mentioned, 2 contributing factors there. We had a few prolific base wells go down that we had to work over.

And that was simply -- that was transitions from ESPs to gas lift. So just it was more of a timing thing there. We do plan for better than that at any given quarter but we just so few more wells coming out and normally there were just some tie-ins were little that weighted on the gas side for the new five well patent that was brought on.

So nothing concerning and again we contract in Q3 from the volume perspective yet no concerns there..

The next question comes from Doug Leggate of Bank of America Merrill Lynch..

Dan, I wonder if I could just pickup on the cash tax common slide deck, its obviously been a moving piece for you guys given the AMT but can you, if I look at slide 18, can you give us an idea what that free cash flow delta would look like at different decks on when you expect to transition to cash tax to full cash tax..

Yes, maybe not quantify that as specifically but let me just tell you what's happening. So we have in a non-AMT world sufficient tax attributes not to taxable U.S.

Federal Income tax taxable until late 2025, when this new rule of inflation reduction act in the AMT that came in with it impose being a 15% alternative minimum tax if you are not paying taxes if you meet certain criteria the primary criteria is your 3 year average pre-tax book income was a $1 billion or more.

In 2023, we are below that $1 billion threshold, in 2024 we expect to be above that. There was a big loss, here a pandemic loss in the current three year average number that would roll off when we get to 2024. So we expect we are going to be AMT taxable at a 15% rate starting in 2024 and we expect that should continue at that rate for about a decade.

In the background the conventional NOLs and tax attributes will be conferred to AMT credits and so we will end up sort of capping our tax rate to 15% in the U.S. for that period of time. At 15% it will only to U.S.

income, we pay a 25% rate [indiscernible] and that generates its own foreign tax credit so it won't get doubled [ph] by the AMT tax rate as well. Hopefully that you can apply that kind of math to any price outcome you are looking at and quantify it..

I know it’s a complicated issue. Dane, thanks for running through that. I guess my follow-up lead is we haven't really heard a lot about REX [ph] recently I wonder if you could just give us your updated thoughts on thinking on portfolio development and maybe sit along side how you see the M&A landscape [indiscernible]..

Yes, well let me start and then I may ask support from Pat as well. Now the portfolio development side we really look at this kind of as a multi-element approach when we talk about resource replenishment, inventory replenishment.

On one end of the spectrum you have large acquisition like the Ensign acquisition which as you say was a tremendous win for our shareholder.

I think the other avenue that we have are smaller bolt-ons and trades and I think Mike actually mentioned that some of the trade work in the Permian is giving us some access to some more extended laterals and then you have I would say our internal kind of self-help which is can be some of the redevelopment activities but also the REX program as well and so we look across all those dimensions we talk about resourced replenishment and how do we continue to build a resource base since we are an extractive industry we have to stay on top of that.

But maybe I will let Pat talk a little bit about our program particularly maybe focused on the Texas Delaware program and how that's now kind of progressed from what we would have originally called a REX program now more into developmental program..

As we said our primary project within REX has been this Texas Delaware Oil Play and we have now fully integrated that into our Permian asset team. So its no longer as REX and we talked a little bit last quarter, we brought on a four well pad this year taking down -- well that pad has performed exactly as we expected it to.

We will drill another pad in 2024 -- coming up that we will bring online in 2024. We are committed to now a developmental approach that is 4x4, four in the NERAMAC and four in the Woodford 10,000 foot lateral length that's kind of our developmental plan to be going forward.

The good news in this recent pad as well as is we are still not seeing any communication between the NERAMAC and the Woodford so we can definitely co-develop those two zones. Our real work now is to try drive our D&C cost down as low as possible.

I have got a lot of experience in Oklahoma and these two formations that we are trying to replicate here in this project so we will just continue to mature this project as part of the kind of the development portfolio now moving forward..

I was just going to say I think its -- we really are now focused on this Woodford and NERAMAC play really looking at how do we get up the learning curve to get D&C cost down as low as practical.

So it really has moved more into a development project they have to compete for capital allocation and that's exactly what we want to see is that output from the REX program is moving that stuff and to development mode. I did want to come back to your question to just around M&A though real quickly.

I think you mentioned of course the very successful Ensign acquisition, if anything I would say that actually raised the bar for us from an M&A perspective and we are not going to compromise obviously on our criteria along those lines.

We would be making sure that something is absolutely accretive from a financial metric standpoint, it would have to be accretive from our return of capital standpoint. It would have to be accretive to our overall sustainability meaning inventory kind of resourced like accretive.

They got to be industrial logic there meaning it needs to be in one of the basins where we have high executive confidence and then finally we wouldn't want to do anything that would damage the financial flexibility in the balance sheet that we worked so hard to establish.

That's a very tough filter and I will tell you today as we look into the market we just don't see anything today that really hits all of that criteria and that's what we saw in Ensign, it really did check all of the boxes and that's why I think that's been such a successful addition to our portfolio..

Pardon me with a clarification question Lee, what the Permian oil play included in your inventory, what would you say the inventory life is now in the Permian now? I will leave it there. Thank you..

We probably say based on Pat, kind of doing a nominal 4x4 spacing recognizing obviously that there is some variability across the play but its generally a continuous 55,000 acre position.

So we are thinking several 100 locations right now and we will get more specific on that as we get up that learning curve on D&C and to really integrate it into the rest of our enterprise level inventory..

The next question comes from Matt Portillo of TPH. Please go ahead..

Just a follow up around the shift in the tilt [ph] count for the year. We noticed that the Oklahoma assets are slight down shift in your expected in the JV.

I was curious if that was operationally driven or if just given the low commodity prices some of those wells are sliding in 2024 and more broadly speaking how do you think about the return profile in Oklahoma relative to the rest of the portfolio?.

This is Pat. Just a little bit on the JV in Oklahoma, that's a very targeted program and we are getting close to finishing that up. It's just really been focused around lease retention there using somebody else's capital trying to maintain our lease program. Just some other strategic advantage including keeping that active through work [ph] in there..

No, I don't think there's anything. I mean I think we guided 15 to 20 wells there earlier, Matt. I think I just think we're going to be at the whole end of the range. I don't think there's anything to read through into that..

Perfect. And then maybe just a follow-up on JVs across your asset base.

I know you have a couple at this point that are for lease retention purposes, given the strengthening crude market and what could be a better environment for gas and NGLs as we head into 2025, how is the company's aptitude or kind of appetite at the moment for incremental JVs versus retaining those inventory locations and developing those on your own going forward..

This is Pat again. I think what our approach on JVs to date is to keep them very small and targeted to achieve certain strategic objectives. We're not doing large multiyear operated programs. We're just trying to satisfy lease commitments or protect operatorship, things like that. So we'll continue to view them through that lens.

And as you see an opportunity you got people go ahead and do very small ones. Most of the inventory that we consume in these JVs is not our top-tier inventory to keep that, and we will go ahead and drill that.

But if there's lesser quality inventory that doesn't compete for capital in the current next few years, and we need to execute on it to retain a lease, then we'll bring in a JV partner to help us see that..

The next question comes from Paul Cheng of Scotiabank..

I have to apologize is that I joined late, so if my question has already been addressed, please let me know, I will look at the transcript. We -- just curious that some of your competitors is talking about the refrac and redevelopment opportunity in Eagle Ford. Have you guys do more detail and notes on that.

I assume that currently, your inventory backlog that you mentioned, say, 10 to 12 years, that's not including that -- So if we're including those that -- how big is that opportunity for you? And what kind of oil and gas price you need in order for those that to be economic? That's the first question..

Yes. Paul, let me take a first pass of this and then I'll maybe let Mike sum some details. First of all, in terms of inventory, we do not put refracs into our inventory. So when we talk about inventory life, these are primary development opportunities, new drill wells, if you will.

We've had a lot of experience in the Eagle Ford with refrac and the best and redevelopment. It continues to be an area that we pursue. But again, because we have so many primary recovery opportunities there. We usually do them when there's synergy with nearby new development, but maybe I'll let Mike just throw in is as well..

Yes, Paul. No, you hit the nail in the head there. I mean, our approach with refracs is as we're pulling together a fun development, we're looking at our primary infill -- we'll have a look at the section, and we'll determine that the team is determined then, is there a potential refrac candidate or refrac candidates in the section.

And quite frankly, those opportunities have to compete for capital on a heads-up basis with all of the other opportunities. So rest assured, we're doing refracs. They are profitable and they are competing with infill opportunities. I mean to give you a kind of idea for the scale in any given year, I think we're probably doing less.

We're probably in the 10 to 15 new fracs this year, and that's kind of how we think about it. It's not a targeted program what we will call and do a bunch of refracs exactly to Lee's point, I think we've got enough primary and sole opportunities that we just don't to do that. I think probably answered most of your questions there.

The pricing, they've got to compete on a heads-up basis the other capital that we're deploying..

Yes. The other maybe item I would point out, Paul, as well as maybe just reflecting back on the Ensign conversation that we were having -- in that acquisition, we placed no value on our refrac and redevelopment activities. We based the value really on PDP and the full route 600-plus new primary recovery kind of opportunity that existed there.

So as you recall from the acquisition, there were 700 existing wells, many of which -- most of which were completed back in time, right? And so you've got a lot of early generation completion technology out there. We haven't had a chance yet to quantify that because the primary opportunities within sign are so attractive.

They're a little bit further down a priority list, but we absolutely expect in the balance of time to continue not only in the legacy area of the herd, but also in the inside area of Eagle Ford. So look at refrac and redevelopment opportunities going forward. But again, it's just a question of prioritizing them within the capital allocation..

The second question is I want to go back into the EG commercial renegotiation on the post 2023, is it necessary for you that you have 100% of the volume under long-term contract or from a portfolio management standpoint, better off for you to reserve a fairly sizable amount on the spot market so that you can take the opportunity of the trading and maybe other tranche opportunities.

And also that I know you already have a large exposure starting next year on the international gas market, but does it make sense for you to further diversify your maybe that when we argue that is financial engineering on your U.S. natural gas exposure to also linked to the international market by signing some supply agreement that with the U.S.

Gulf to LNG operator, I know some of your peers have done?.

Paul, this is Pat. I'll take that. Maybe I'll start with your second question first on U.S. gas linkage to LNG. I mean we're always exploring ways to maximize our realizations, but we are heavily exposed in EG to the LNG market. So there's nothing in the U.S. You have to have a significant amount of gas volume to do that in the U.S.

just happen focused on that and don't see us doing that in the near future. In terms of EG, we will commit to a certain level of volumes through a long-term contract.

We will have some terms in there that I want to get into too much detail that we'll have how we handle extra volumes, but I expect that we will have capacity above that sell into the spot market. as progressed. That's -- a lot of those details are still to come, and it depends on the specific negotiations with the buyers coming..

Pat, can I just want to clarify that from a company intention, what will be the ideal mix for the EG contract, do you have a number you might say 70% lock-in on contract and 30% spot or something bigger, something smaller? Any number that you can share?.

No, I don't have any specifics to share with you. But I would think the bulk of the contract will be fixed..

Seeing that there are no further questions at this time. I would like to turn the call back over to Lee Tillman for closing remarks..

Thank you for your interest in Marathon Oil, and I'd like to close by again thanking all our dedicated employees and contractors for their commitment safely and responsibly deliver the energy the world needs now more than ever. Do not be proud of what they achieve each and every day. Thank you, and that concludes our call..

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect..