Marathon Oil - Q2 2023

Transcript

Operator (participant)

Good morning, and welcome to the Marathon Oil second quarter 2023 earnings conference call. All participants will be in a listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press Star, then one on your touchtone phone. To withdraw from the question queue, please press Star, then two. Please note, this event is being recorded. I would now like to turn the conference over to Guy Baber, Vice President of Investor Relations. Please go ahead.

Guy Baber (VP of Investor Relations)

Thank you, Danielle, 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 addressed our Q2 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. With that, I'll turn the call over to Lee, and the rest of the team will provide prepared remarks today. After the completion of these remarks, we'll move to a question-and-answer session. Lee?

Lee Tillman (Chairman, President, and CEO)

Thank you, Guy, and good morning to everyone listening to our call today. First, I want to again kick off our call by expressing my thanks to our employees and contractors for another quarter of comprehensive execution against our framework for success. We don't take such delivery for granted, and I'm especially grateful for your commitment to safety and environmental excellence, in addition to delivering on all of our operational and financial objectives. Well done on another great quarter while staying true to our core values. There are a few takeaways I want to leave you all with this morning. First, we delivered another very strong quarter on all fronts, highlighted by sequential increases to our cash flow from operations, free cash flow, and our total company oil and oil equivalent production.

We delivered around $530 million of free cash flow during the second quarter, with a significant increase from first quarter, driven by strong execution and improving production trend and a catch-up in EG cash distributions. Second key takeaway, we continue to lead our peer group in the broader S&P 500 in returning capital to our shareholders. During the second quarter, we returned $434 million to shareholders, including $372 million of share repurchases. Through the first half of 2023, we've returned over $830 million to our shareholders, representing 40% of our top-line cash flow from operations, consistent with our framework. Our differentiated cash flow-driven return of capital framework continues to prioritize our shareholders as the first call on our cash flow, not the drill bit and not inflation.

First half 2023 return of capital represents a double-digit total shareholder distribution yield on an annualized basis and the highest in our E&P peer space. Our commitment and consistency in returning significant capital is contributing to peer-leading growth in our per-share metrics. We've now reduced our outstanding share count by 24% in just the last 7 quarters. We are on track to deliver 30% year-over-year production growth per share. My third and final key takeaway this morning. Our forward outlook remains compelling and differentiated. We are on track to deliver a 2023 business plan that benchmarks at the top of our high-quality E&P peer group on the metrics that matter most: 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 ranges. 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. Finally, though 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 to beat 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 upate.

Dane Whitehead (Executive VP and CFO)

Thank you, Lee, and good morning, everyone. As Lee 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. 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. That's the highest in our peer group. Over the trailing 7 quarters, we've now returned approximately $4.6 billion back to our 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 peer-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.

While we left our base dividend unchanged this quarter, keep in mind that we've raised it 8 of the 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., USX debt so far this year, and we marketed $200 million of tax-exempt 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 these sector-leading outcomes.

Mike Henderson (EVP of Operations)

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-$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 expectation entering the year. We started to see a general plateauing of costs during the second quarter amid improved access to services and equipment. Although the macro environment remains dynamic, we've now started to see an improved pricing trend across raw materials and most service lines and equipment, consistent with a lower level of industry-wide drilling and completion activity. We'll look to capture better pricing where we can over 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 wells sales guidance in the Eagle Ford, Bakken, and Permian.

While this won't have a material impact on our full-year 2023 capital or 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, although we're 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 cash 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 first, 2024, Alba-sourced LNG will no longer be sold at a Henry Hub linkage. It will be sold into the global LNG market.

This arbitrage between Henry Hub and global LNG pricing, coupled with the highly competitive market for LNG cargoes from reliable suppliers, is expected to drive significant financial uplift for our company at current forward charge pricing. To take further advantage of these new commercial terms, we are actively assessing up to a two-well infill drilling program at Alba, targeting high confidence, low execution risk, shorter cycle opportunities that could mitigate base decline and maximize flow of equity molecules through the LNG plant 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 fully 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 multi-year free cash flow capacity. The next phases of development will include the Aseng gas cap blowdown, as well as potential cross-border opportunities. With that, I will turn it over to Lee, who will wrap up our prepared remarks.

Lee Tillman (Chairman, President, and CEO)

Thank you, Mike. For years now, I have reiterated that for our company and for our sector to attract increased investor sponsorship, we must deliver financial performance competitive with other investment alternatives in the market, as measured by corporate returns, free cash flow generation, and return of capital. More S&P, less E&P. We've delivered exactly that type of performance over the last two years, and not just competitive, but at the very top. Our one-line investment thesis is this: 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 in the metrics that matter most. This peer-leading financial and operational delivery is not a one-year phenomenon. It's a continuation of a multi-year trend. It's sustainable.

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've positioned 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. 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 progress, defend U.S. energy security, lift billions out of energy poverty, and protect the standard of living we have all come to enjoy. With that, we can open the line up for Q&A.

Operator (participant)

We will now begin the question-and-answer session. To ask a question, you may press star then one on your touchtone phone. If you are using a speakerphone, please pick up your handset before pressing the keys.

... To withdraw your question, please press Star, then two. Please limit yourself to one question and one follow-up. The first question comes from Arun Jayaram of JPMorgan. Please go ahead.

Arun Jayaram (Equity Research Analyst)

Good morning, Lee and Dane and Mike. You mentioned how your free cash flow should inflect in the second half of this year, just given the, call, $450 million decline in CapEx, higher output and oil prices. I wanted to get your thoughts on how you balance, you know, 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. Just thoughts on balancing those three items.

Dane Whitehead (Executive VP and CFO)

Yeah, sure, Arun. Thanks. 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. You know, 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 our base dividend. Obviously, our track record on meeting that minimum return is very solid, and unwavering, and we expect that to continue that going forward. We returned exactly 40% in the first half of 2023, CFO to shareholders.

That's $700 million in share repurchases, plus a $125 million base dividend, which equated to 11% annualized distribution yield, which is really at the top of the class in terms of return. On top of that, we also paid off $200 million of 8%+ coupon USX 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's trading at a free cash flow yield in the mid-teens, so repurchases 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 repurchased authorization outstanding, so plenty of running room there. And the per-share growth that we're driving, you know, 24% since fourth quarter of 2021 when we restarted this program, is pretty, pretty, eye-watering. For the balance of the year, expect us to continue to return 40% of operating cash flow and look to pay down additional debt. Make no mistake, the 40% return to shareholders is the top priority. The second priority will be 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 free cash flow inflection that we started to realize in the second quarter, but we expect that to continue in the third and fourth quarter.

Even on a price-normalized basis, we're gonna have a lot more flexibility than we've had over the past two quarters to serve both of those needs, shareholder return and debt reduction. With the tail, tailwind we're seeing in commodity prices, particularly W- WTI right now, that's gonna provide even more flexibility. We can, we can go bigger on share repurchases, or we can go faster on debt reduction, or some-- more likely, some combination of those. You asked about cash balance. You know, we're operating around $200 million right now, and in the, in the course of a month, we actually may go negative and need to borrow on our credit facility a little bit, waiting for the big twentieth-of-the-month check for oil receipts, which is the-- that's the big time when a big wave of cash flow comes into the company.

That working capital, that we're, 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 it's not a priority for us right now. Right now, it's gonna be hit the 40%, exceed it where we can, and take down that term loan to get that interest expense out of the system.

Arun Jayaram (Equity Research Analyst)

That's helpful. My follow-up maybe is for Mike, is kind of maybe a two-parter. Mike, your updated till guidance, is about 17 tills higher, 230 versus 213. Does that impacting, you know, any production from, from the higher tills? That was a question from the buy side. 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, in the Northern Delaware, a couple of those variances, in 2Q.

Mike Henderson (EVP of Operations)

Yeah, just, just looking at the, the wells to sales cadence, you know, I'd probably start, the capital program is, is very much, tracking as planned, so kind of we, we fully expected to, to execute on that. You know, kind of fairly, fairly, fairly typical for us to be more front-end loaded. You know, we are, we are seeing some outperformance from, from an execution perspective, particularly in the, the drilling space. You know, looking back, and I think we've had 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. Then, then in Eagle Ford, you know, again, a similar story there.

I think what's encouraging in Eagle Ford is with the, 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. When you kind of combine all of that together, it's putting a little bit of pressure on the, the wells to sales in the year. I think how I think about it, that, that pressure is gonna really translate more so in the fourth quarter. If you think about it, we're probably pulling a few wells in from the first quarter into the fourth quarter. You know, from a capital and production perspective, not gonna have a big impact on 2023, but potentially could set us up well for, for the run into to 2024 in the first quarter there.

You, you asked specifically about Eagle Ford's well performance. Yeah, I think, we highlighted the 74 Ranch wells in Atascosa County. Those are extended laterals. We're seeing some great performance, some great early production performance out of those. That's an area of the play that we've got some future running room. I expect that's gonna be a big part of our execution portfolio in 2024 and then into 2025. Hopefully, hopefully, that answered all the questions that you had there.

Lee Tillman (Chairman, President, and CEO)

Yeah.

Speaker 13

Thanks a lot.

Lee Tillman (Chairman, President, and CEO)

Maybe on the-- Yeah, I just think, one, Arun, just on Permian, too, you'd asked a little bit about, you know, why we saw a little bit of step down, you know, sequentially there. That was generally speaking to a little bit of, of lag in our workover program, again, on top of, you know, a couple of large producers that went down. We had to get a workover rig on them. Then finally, we, 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 though now, so really just a question of timing. No, no well performance issues whatsoever.

Speaker 13

Thanks, Lee.

Lee Tillman (Chairman, President, and CEO)

Yeah. Thank you.

Operator (participant)

The next question comes from Josh Silverstein of UBS. Please go ahead.

Josh Silverstein (Equity Research Analyst)

Yeah, thanks. Good morning, guys. Lee, 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 timeline for investments? Are these, you know, $200 million projects over 3 or 4 years? Just a little bit more about the scope of the opportunity there. Thanks.

Lee Tillman (Chairman, President, and CEO)

Yeah, you, you bet, Josh. Happy to do so. Yeah, just maybe stepping back, first of all, on the infill drilling program. You know, the objective here, of course, in EG, is to continue to base load our 3.7 MTPA train. We'd obviously prefer to do that with equity molecules, but to the extent there's owns, we'll 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 Alba PSC all the way through EG LNG. Those are extremely valuable molecules and would ultimately help us offset and mitigate some of the decline that we're seeing from the Alba field. Again, remember, we have aligned interests.

We've got about 64% interest in the Alba unit. We've got about 56% working interest in EG LNG, and of course, are operator of both. 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 as short cycle as you can get. This would be jacked up drilling over existing facilities, typically re-entry, dry trees. 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.

Ultimately, we believe, up to 2 wells in Alba can compete with those very strong risk-adjusted returns that we're generating here in the U.S. portfolio. You know, if we can stay on track, you know, with an FID decision in the near term, then, you know, that could have us in a position subject to rig availability, you know, to may even be able to spud, you know, late 2024 in that timeframe. The way the capital will phase, just quite frankly, on a, you know, say a notional couple billion dollar budget, it's not gonna be material. It'll be phased over time. 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.

Josh Silverstein (Equity Research Analyst)

Got it. That, that's helpful. Then, obviously, there's a lot of upside to come as the, the contract rolls off. We've also seen a lot of volatility in, in TTF and international pricing. Is there anything you guys can do to take some of that volatility out, or is there hedging liquidity? Are there contracts you can sign? Just anything that you can provide there, given we've seen, you know, as much volatility there as we have here. Thanks.

Lee Tillman (Chairman, President, and CEO)

Yeah. Yeah, I think we've tried to show, you know, the notional uplift that we could obtain from the change in commercial terms that will occur January 1, 2024. The reality is, Josh, as long as there is arbitrage between Henry Hub and TTF, there's going to be financial uplift at EG. Really, it's just gonna be a matter, as you said, of where does that global LNG market price ultimately land? We've shown some sensitivities, you know, $15, $20, and $40 TTF, and in all those cases, there's material uplift relative to what we're seeing in 2023. You know, the work is ongoing from a commercial standpoint, you know, from a liquefaction agreement to lifting agreements, all the way through to LNG marketing.

You know, more to come on that. 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 advantaged into Europe, are gonna be very much sought after. I would just emphasize that, you know, buyers are looking for reliable suppliers. Over the life of EG LNG, we've never missed a cargo. So I think we're in a very good position to, to maybe not damp out all the volatility that you've referenced, but certainly take full advantage of the market price that, that's available to us.

Mike Henderson (EVP of Operations)

Great. Thanks, guys.

Operator (participant)

The next question comes from Scott Hanold from RBC Capital Markets. Please go ahead.

Scott Hanold (Managing Director and Energy Research)

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

Lee Tillman (Chairman, President, and CEO)

Yeah. I would just say, you know, first of all, you know, this is a competitive process, you know, Scott, that we're in. From a milestone standpoint, we're right on track in terms of the commercial milestones that we laid out. 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. That's an active, ongoing, competitive process right now, Scott.

Scott Hanold (Managing Director and Energy Research)

Yeah. I, I mean, are you able to talk about what kind of duration you're looking for? You know, obviously, you talk about maybe stabilizing the Elba field. Is that, you know, part of showing that, you know, the assets have duration for, for those counterparties?

Lee Tillman (Chairman, President, and CEO)

Yeah. I'll go back to my comment around, you know, reliability and security of supply. Certainly, duration is an important element that is in, of course, the, the terms that we're currently discussing. Until we kind of complete that competitive discussion, I don't want to get too far into, you know, some of the, the commercial details. Suffice to say, though, Scott, that, you know, we do believe that, you know, we'll be able to provide a very solid runway of, of LNG cargoes for those counterparties. You know, certainly we're looking, you know, at a, a longer-term kind of contractual relationship.

Scott Hanold (Managing Director and Energy Research)

Okay. Then, my follow-up was, is a little on 2024. You, you gave a few tidbits, but, you know, clear you're sticking to the maintenance program. With, you know, some of the potential tailwinds coming into the year that, that you spoke of based on, your, your more efficient program. I mean, at a high level, you know, that coupled with, you know, 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, you're targeting this year?

Lee Tillman (Chairman, President, and CEO)

Yeah. Well, of course, it's a, 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 gonna be back, you know, targeting kind of that notional 190,000 barrels of oil per day, so, so no real surprises there. 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, you know, Mike hit upon this in, in the comments, that, you know, market trends continue to, you know, I think, give us an opportunity to see some downward pressure in pricing.

I think we're well positioned to, to take advantage of that in the second half of the year. I think from a materiality standpoint, those deflationary impacts are really not going to take root until, you know, 2024. That's all gonna 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. Do I see an encouraging trend there? Yes. Am I gonna give you a quantification of that right now? It's just a bit too early to go there.

Scott Hanold (Managing Director and Energy Research)

Thanks.

Operator (participant)

The next question comes from Neal Dingmann of Truist Securities. Please go ahead.

Neal Dingmann (Energy Analyst)

My question is on the DNC specifically? It seems 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, the upsides that they see, you know, on returns from this versus the 2-milers. I'm just wondering, do you all agree with this assessment? If so, what type of opportunities in your place do you have for this?

Mike Henderson (EVP of Operations)

Yeah, Neal, it's Mike. Yeah, I definitely, definitely agree with that assessment. It's, it's been a focus area. I think it started predominantly with the, with the Permian asset. You know, we've, we've progressed from, you know, a lot of single-mile laterals there. Team's 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. That's allowed us to, to develop this inventory of 10 years plus of, of 2-milers there. We've now, we've now expanded that approach. We're having a look at potential opportunities in, 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.

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, you know, more of that. I mentioned that earlier in the response to Arun. I expect more of those types of wells coming into the portfolio next year and potentially even 25. Having a look in Bakken, it's probably a bit more of a limited opportunity set there, but nevertheless, the team are looking at. Even Oklahoma, we're drilling a 3-mile Springer well at the moment. That's being drilled under the JV that we've got there. If that proves successful, that could open up a few more pads as well for us, and oily pads also in Oklahoma, which is always helpful.

You know, I'd, I'd characterize it by, yeah, we're definitely seeing the uplift, and it's something that the teams are actively progressing.

Neal Dingmann (Energy Analyst)

Very good. No, that's great to hear. Then my, my second question, just on sort of the regional oil production. I know you guys don't, you know, specifically guide on, on each of the regions, but there's definitely continues to be a pretty nice notably pickup in the Bakken. 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, is there anything to read into that, or is it just more timing of the DNC plan?

Mike Henderson (EVP of Operations)

I think in, I think in Bakken, you're, you're seeing the, the benefit, strong execution there, in the second quarter. You've seen the benefits in, in read through into volumes. I think that would translate into the third quarter as well. Permian, as, as Lee mentioned, you know, we've had 3 or 4 quarters of growing volumes there. We had a bit of out, seen some outperformance there, a little bit of underperformance this quarter. Again, as Lee 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. Just it was more of a timing thing there.

We do plan for a bit of that in any given quarter. We just saw a few more wells coming at us than normal. Then it was just some tie-ins that were a little bit late on the gas side for the new 5-well pad that we brought on there. You know, no, nothing concerning. Again, as Lee mentioned, we're back on track early in Q3 from a volumes perspective. Yeah, no, no concerns there.

Neal Dingmann (Energy Analyst)

That's great details. Thanks, Mike.

Operator (participant)

The next question comes from Doug Leggate of Bank of America. Please go ahead.

Doug Leggate (Managing Director Head of US Oil and Gas)

Thanks. Good morning, everyone. Thanks for having me on. Dan, I, I wonder if I could just pick up on the cash tax commentary on the slide deck. It's obviously been a moving part, 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?

Dane Whitehead (Executive VP and CFO)

Yeah, I may maybe not quantify it specifically, but let me just tell you what's happening. We have, in a non-AMT world, sufficient tax attributes not to be taxable, US federal income tax taxable until late 2025. When this, this new rule, the Inflation Reduction Act and the AMT that came in with it, imposed paying a 15% alternative minimum tax if you're not paying taxes, if you meet certain criteria. The primary criteria is if your 3-year average pre-taxable income was $1 billion or more. In 2023, we are not, we're below that $1 billion threshold. In 2024, we expect to be above that. You know, there was a big loss year, a pandemic loss year in, in the current 3-year average number that would roll off when we get to 2024.

We expect we're gonna be AMT taxable at a 15% rate starting in 2024, and we expect actually to continue at that rate for about a decade. In the background, the conventional NOLs and tax attributes will be converted to AMT credits, and so we'll end up sort of capping our tax rate at 15% in the U.S. for that period of time. That 15% will only apply to U.S. income. We pay a 25% rate in EG, and that generates its own foreign tax credit, so it won't get double dipped by the AMT tax rate as well. Hopefully, that, you can apply that kind of math to any price outcome you're looking at and quantify it.

Doug Leggate (Managing Director Head of US Oil and Gas)

That's, I know it's a complicated issue, Dan. Thanks for running through that. I guess my follow-up, Lee, is we haven't really heard a lot about REX recently. I wonder if you could just give us your updated thoughts on what you're thinking on portfolio development and maybe set it alongside, you know, how you see the M&A landscape for Marathon after the, you know, that terrific deal you did in Eagle Ford?

Mike Henderson (EVP of Operations)

Yeah. Yeah. Well, let, let me start. I may ask for some support from, from Pat as well. You know, on the portfolio development side, you know, we, we really look at this kinda as a multi-element approach when we talk about resource replenishment, inventory replenishment. You know, on one end of the spectrum, you have...

Lee Tillman (Chairman, President, and CEO)

... large acquisitions like the Ensign acquisition, which, as you stated, was a tremendous win for our shareholder. I think the other, you know, 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 access to more, you know, extended laterals. Then you have, I would say, our, our internal, you know, kind of self-help, which is, can be, you know, some of the redevelopment activities, but also the REX program, as well. We look across all those dimensions. We talk about resource replenishment and how do we continue to, to build the resource base. Since we are an extractive industry, we have to stay on top of that.

Maybe I'll 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 a developmental program.

Pat Wagner (EVP of Corporate Development and Strategy)

Yeah. Good morning, Doug. This is Pat. As Lee said, our primary project within REX has been this Texas-Delaware oil play. We have now fully integrated that into our Permian asset team, so it's no longer categorized as REX. We talked a little bit about it last quarter. We brought on a 4-well pad this year, doing a downspacing test. That pad has performed exactly as we expected it to. We'll drill another pad in 2024 or coming up that we'll bring online in 2024. We're committed to now a development approach that is a 4-by-4, 4 in the Meramec, 4 in the Woodford, 10,000 foot lateral length. It's kind of our development plan to beat going forward.

The good news in this recent pad as well, was we still are not seeing any communication between the Meramec and the Woodford. We can definitely co-develop those two zones. Our real work now is to try to drive our DNC cost down as low as possible. You know, I've got a lot of experience in Oklahoma in these two formations that we're trying to replicate here in this project. We'll just continue to mature this project, and it's part of the, kind of the development portfolio now moving forward.

Lee Tillman (Chairman, President, and CEO)

Yeah, I would say-

Speaker 13

Appreciate the answers, guys. Thanks. I forgot. Go on, Lee.

Lee Tillman (Chairman, President, and CEO)

Yeah. I'm sorry, Doug. I was just gonna say, you know, I think it's, you know, we're really now focused on for this Woodford Meramec play, really looking at how do we get up the learning curve to get, you know, DNC costs down as, as low as practical. You know, it really has moved more into a development project that has to compete for capital allocation, and that's exactly what we wanna see as an output from the REX program, is moving that stuff into development mode. I did wanna come back to your question, too, just around M&A, though, real quickly. I think, you know, you mentioned, of course, the very successful, you know, Ensign acquisition.

You know, if anything, Doug, I would say that actually raised the bar for us from a, from an M&A perspective, and we're, we're not gonna compromise, obviously, on our criteria along those lines. I mean, you know, we would be, you know, making sure that something is absolutely accretive from a financial metric standpoint. It would have to be accretive from a return of capital standpoint. It would have to be accretive to our overall sustainability, meaning inventory, kind of resource life accretive. There would have to be industrial logic there, meaning it needs to be in one of the basins where we have high execution confidence. Finally, we wouldn't, wouldn't wanna do anything that would damage the financial flexibility and the balance sheet that we've worked so hard to establish.

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

Speaker 13

Pardon the, the clarification question, Lee. What, what's the merit the, the Permian oil play included in your inventory, what would you say the inventory life is now in the Permian? I'll leave it there. Thank you.

Lee Tillman (Chairman, President, and CEO)

We'd probably say today, based on, you know, Pat, you know, kind of doing a nominal four-by-four spacing, recognizing obviously that there's, you know, some variability across the play, but it's generally a contiguous 55,000 acre position. We're thinking, you know, several hundred locations right now, and we'll get more specific on that as we get up that learning curve on DNC and can really integrate it in with the rest of our enterprise-level inventory.

Speaker 13

Thanks, guys.

Lee Tillman (Chairman, President, and CEO)

Appreciate it. Thank you, Doug.

Operator (participant)

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

Matthew Portillo (Managing Director and Partner)

Good morning, all. Just to follow up around the shifts in the till count for the year, we noticed that the Oklahoma assets saw a slight downshift in your expected tills under the JV. I was curious if that was operationally driven or if just given the low commodity prices, some of those wells are sliding into 2024. More broadly speaking, how do you think about the return profile in Oklahoma relative to the rest of the portfolio?

Pat Wagner (EVP of Corporate Development and Strategy)

Yeah, this is Pat. Matt, just a little bit on the, the JV in Oklahoma. That's a very targeted program, and we're getting close to finishing that up. It's just really been focused around lease retention there, using somebody else's capital to try to maintain our, our lease program. There's some other strategic advantage-- strategic advantages, including keeping an active crew working there. Of course, I don't know, Mike, you have anything else to add to that?

Lee Tillman (Chairman, President, and CEO)

No, I, I don't think there's anything. I mean, we, we keep-

Mike Henderson (EVP of Operations)

... I think we guided 15-20 wells there earlier, Matt. I think we just think we're gonna be at the low end of the, the range. I don't think there's anything to read through into that.

Matthew Portillo (Managing Director and Partner)

Perfect. Then maybe just to follow up on, 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, for gas and NGLs as we head into 2025, how's the company's aptitude or kind of appetite at the moment for incremental JVs versus retaining those inventory locations and, and developing those on your own going forward?

Pat Wagner (EVP of Corporate Development and Strategy)

This is Pat again. I think, you know, 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, multi-year operated programs. We're just trying to satisfy lease commitments or protect operatorship, things like that. We'll continue to view them through that lens, and as we see an opportunity to do that, we will, we will go ahead and do very small ones. You know, most of the inventory that we consume in these JVs is not our top-tier inventory. Keep that, and we will go ahead and drill that. 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 do that.

Matthew Portillo (Managing Director and Partner)

Thank you.

Operator (participant)

The next question comes from Paul Cheng of Scotiabank. Please go ahead.

Paul Cheng (Equity Research Analyst)

Thank you. Good morning. I have to apologize first that I joined late, so if my question already been addressed, please let me know. I will look at the transcript. Lee, just curious that, some of your competitors talking about the refrack and redevelopment opportunity in Eagle Ford. Have you guys, do a, more detailed analysis on that? I assume that currently your, inventory backlog that you mentioned, say, 10-12 years, that's not including that. So if we including those that, how big is that opportunity for you? What kind of, oil and gas price you need in order for those that to be economic? That's the first question.

Lee Tillman (Chairman, President, and CEO)

Yeah. Yeah, Paul, let me let me take a first pass at this, then I'll maybe let Mike fill in some details. You know, first of all, in terms of inventory, we do not put refracks into our inventory. When we talk about inventory life, these are primary development opportunities, new drill wells, if you will. You know, we've had a lot of experience in the Eagle Ford with refrack and redevelopment. It continues to be an area that, that we pursue. Again, because we have so many primary recovery opportunities there, we usually do them when they're synergy with nearby new development work. Maybe I'll, I'll let Mike just throw in his 2 cents as well.

Mike Henderson (EVP of Operations)

Yeah, Paul. No, you hit the nail on the head there. I mean, our, our approach with, with refracks is, you know, as we're pulling together our plan development, we're looking at our primary infill. We'll have a look at, at the section, and we'll determine then, is there a potential refrack candidate or refrack candidates in the, the section. And, you know, quite frankly, those opportunities have to compete for capital on a heads-up basis with, with all of the other opportunities. So rest assured that we're doing refracks. You know, they are, they are profitable, and they are competing with, 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 10-15 refracks this year, and that's kind of how we think about it. It's not a targeted program, where we will go and do a bunch of refracks. Exactly to Lee's point, I think we've got enough primary infill opportunities that we just don't need to do that. You know, I think we've probably answered most of your questions there. The pricing, they've got to compete on a heads-up basis with all the other capital that we're deploying.

Lee Tillman (Chairman, President, and CEO)

Yeah, the other, maybe, item I would point out, Paul, as well, is maybe just reflecting back on the Ensign conversation that we were having. You know, in that, in that acquisition, you know, we placed no value on refrack and redevelopment, activities. We based the, the value really on PDP and the whole room, you know, 600+ new primary recovery kind of, opportunities 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, you know, completion technology out there. We haven't, we haven't had a chance yet to quantify that because the primary opportunities with Ensign are so, attractive.

They're a little bit further down our priority list. We absolutely expect in the balance of time to continue, not only in the legacy area of Eagle Ford, but also in the, the Ensign area of Eagle Ford, to look at refrack and redevelopment opportunities going forward. Again, it's just a, a question of prioritizing them within the capital allocation.

Paul Cheng (Equity Research Analyst)

Thank you. The second question is want to go back into the EG commercial renegotiation on the, on the, post 2023. Lee, is it necessary for you that to 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 opportunity of the trading, maybe, maybe arbitrage opportunities. Also that, I know you already have a large exposure starting next year on the international gas market.

Does it make sense for you to further diversify your, maybe that, one may argue that it's financial engineering on your U.S. natural gas exposure to also link to the international market by signing some supplying agreement that with the U.S. Gulf Coast LNG operator, like some of your peer have done?

Pat Wagner (EVP of Corporate Development and Strategy)

Hi, 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. We are heavily exposed in EG to the global LNG market, so there's nothing imminent in the U.S. You have to have a significant amount of gas volume to do that in the U.S., and we just haven't 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, some terms in there that I don't want to get into too much detail, that will have how we handle extra volumes. I expect that we will have capacity above that sold into the spot market as we progress. That's a lot of those details are still to come. It depends on the specific negotiations we have with the buyers over the coming couple of months.

Paul Cheng (Equity Research Analyst)

Hey, 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 in mind, say 70% locked in on contract and 30% spot, or something bigger, something smaller? Any number that you can share?

Pat Wagner (EVP of Corporate Development and Strategy)

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

Paul Cheng (Equity Research Analyst)

I see. Okay, will do. Thank you.

Pat Wagner (EVP of Corporate Development and Strategy)

Thank you, Paul.

Operator (participant)

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.

Lee Tillman (Chairman, President, and CEO)

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 to safely and responsibly deliver the energy the world needs now more than ever. Could not be prouder of what they achieve each and every day. Thank you, and that concludes our call.

Operator (participant)

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