Good morning, and welcome to the MRO Third Quarter Earnings Conference Call. My name is Brandon, and I'll be your operator for today. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. [Operator Instructions] Please note this conference is being recorded.

I will now turn it over to Guy Baber, Vice President - Investor Relations. You may begin, sir..

Thanks, Brandon, and thanks as well to everyone for joining us this morning. Yesterday, after the close, we issued a press release, a slide presentation and an investor packet that address our third quarter 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; Mitch Little, Executive VP, Adviser to the CEO; and Mike Henderson, Senior VP of Operations.

As always, 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.

Today, we'll also refer to some non-GAAP financial measures, and reconciliations to the nearest corresponding GAAP measure can be found on our website. I'll refer everyone to the cautionary language included in the press release, and presentation materials as well as to the risk factors described in our SEC filings.

With that short intro, I'll turn the call over to Lee, who will provide his remarks. We'll then open the call up to your questions..

Thanks, Guy, and good morning to everyone joining us on the call. I want to start by again thanking our employees and contractors for their continued resilience and dedication as we manage through the ongoing COVID-19 pandemic. Safe, environmentally responsible operations are central to our company values and to our commitment to our stakeholders.

The safety of our people is my top priority. I am pleased to report that our year-to-date safety performance, as measured by total recordable incident rate, is the best in our company's history. I am proud of our people. They have risen to the challenge and a demanding year.

Rest assured, we will continue to manage COVID-19 risk diligently through our business continuity and emergency response plans. I also want to extend my thanks to Mitch Little, for his three decade service and leadership at our company.

This will be Mitch's last earnings call with us, which I know he is disappointed about as he plans to retire at the end of this year. Mitch has been an integral part of our team and is a driving force behind execution excellence across all aspects of our operations.

And I have every confidence that Mike Henderson will only continue to build on the standard of excellence. I have personally leaned on Mitch's wise counsel and guidance as CEO, and wish him all the best as he transitions to the next chapter in life. Thank you and best of luck to you and Sandy.

It goes without saying that the macro environment for E&P and for energy companies more broadly, remains challenging amidst this historic down-cycle. But now is not the time for panic, but rather a time for healthy companies to press their advantage and not prematurely react to what is at best a distorted and transitory market.

While global inventories have been drawing, they still remain well above historic levels. And with uncertainties characterizing both the demand and supply side of the equation, the range of potential outcomes for future commodity prices remains wide and difficult to predict.

As I often remind our teams, we can't control the macro, and we certainly can't predict the oil price. Prudent operators like ourselves won't be distracted by external forces, but will focus on the elements of our business within our control, how we allocate capital, how we manage our cost structure and how we execute.

In the face of this uncertainty, the E&P industry must remain disciplined and recognize that at least in the near term, the world simply does not need additional supply. At Marathon Oil, we have a long-standing working definition for what capital discipline looks like.

It's allocating capital with the right priorities in mind to improve corporate returns, and to generate sustainable free cash flow across a wide range of commodity prices. It's taking investor-friendly actions with that free cash flow, prioritizing debt reduction and return of cash to shareholders.

And its differentiated execution by managing our cost structure to improve our resilience and delivering peer-leading capital efficiency that underpins free cash flow breakevens among the lowest in our industry. Essentially, continuously improving all aspects of our business, while meeting our commitments to all stakeholders.

It's also leveraging the flexibility of our multi-basin portfolio and further strengthening our investment grade balance sheet to weather volatility.

Third quarter results offer strong proof points against this framework as we generated $180 million of free cash flow and made important progress on both returning capital to our shareholders and improving our balance sheet. But this is not a strategy, just a quarter or two in the making, nor is it simply going with the trend of the day.

Heading into 2020, I believe our company had uniquely established a track record of delivering on exactly this brand of capital discipline, demonstrated by multiple years of free cash flow generation, and significant return of capital back to shareholders.

More specifically, as highlighted on slide 4 of our earnings deck, across 2018 and 2019 through a disciplined development capital reinvestment rate of 77%, we generated significant free cash flow and returned 23% of our cash flow from operations or $1.4 billion back to our shareholders.

This track record of actual delivery is unique to our space, but not new to Marathon. 2020 has unquestionably been a transitional year for us and for the industry. However, we have successfully leveraged the supply/demand crisis to further optimize and enhance our business model.

Not only have we pulled the necessary levers to protect our balance sheet, liquidity and to generate free cash flow this year in a difficult environment, we have also materially improved the resilience of our business and have dramatically enhanced our ability to generate robust financial outcomes.

As we look ahead, our long-held core priorities won't change, but we recognize the environment has. Our challenge is to deliver the same or better shareholder friendly outcomes as we did in 2018 and 2019, yet in a lower and more volatile commodity price world.

Slide 5 of our earnings deck highlights how we have repositioned our company to meet this challenge. Our capital allocation priorities are clear, and we are singularly focused on what adds shareholder value while offering a combination of downside commodity price resilience, alongside outsized leverage to even modest price support.

We have used our 2021 benchmark maintenance scenario that holds oil production flat to fourth quarter 2020 as a reference point.

Note that this maintenance scenario is not reliant on any outsized advantage associated with drilled but uncompleted well drawdown is on an unhedged basis and even includes a modest level of resource play exploration spending. Based on public disclosures, this benchmark maintenance case delivers capital efficiency superior to our peers.

In a more challenging oil price environment, call it below $40 per barrel WTI; we will lean on our industry leading free cash flow breakeven. Our corporate breakeven for 2021 under our benchmark maintenance scenario is less than $35 per barrel WTI.

In fact, assuming gas price is consistent with the current forward curve, we could fund both our maintenance capital budget of about $1 billion and our base dividend at an oil price of approximately $35 per barrel. In this downside environment, our key objectives will be to fund our base dividend and protect our balance sheet.

It goes without saying that we will continue to prioritize financial returns.

In a more normalized or mid-cycle oil price environment, $40 to $50 per barrel WTI, our previously disclosed reinvestment rate framework provides clear visibility to compelling free cash flow generation for investor friendly purposes with yields that compete with the broader market.

At the middle of this range or $45 of WTI, our maintenance scenario would deliver over $600 million of free cash flow in 2021, a yield of almost 20% on our current equity value.

We would target a reinvestment rate at/or below 70%, making available 30% or more of our operating cash flow for investor friendly purposes, prioritizing our base dividend and balance sheet.

Even at the low end of this price range, more consistent with the current forward curve, our reinvestment rate would not trend above 80%, and we would generate robust free cash flow for shareholders. In a higher oil price environment, $50 per barrel or higher, our core priorities won't change.

We will maintain our focus on corporate returns and free cash flow generation. Production growth will remain an outcome, but would be capped at approximately 5%, underscoring our commitment to capital discipline, and to outsized free cash flow, in an improving commodity environment.

Our upside leverage to higher oil price is among the best in our peer group. And something we will protect, so our shareholders can participate, in the eventual up cycle. At $50 per barrel WTI, our maintenance case could deliver over $900 million of free cash flow in 2021, and a yield is approaching 30%.

In this environment, given the magnitude of potential free cash flow, balance sheet enhancement would be accelerated. And we could achieve our targeted leverage metrics in short order. We would also be well positioned for incremental return of capital to shareholders, beyond our base dividend.

In a low growth or no growth environment, capital efficiency and operating efficiency are the competitive differentiators. Our ability to deliver peer-leading free cash flow and corporate breakeven is backed, by the Eagle Ford and Bakken, which have the best capital efficiency of the U.S. shale plays.

The competitive data shown on slide, six and seven of our deck, is entirely sourced from an independent third party, Rystad Energy's Shale Well Cube Data Set. And the graphics include data for over 20,000 individual shale wells since 2018.

We highlight here a simplified, capital efficiency metric, average per well 180-day production on a 20:1 energy equivalent basis, relative to total well cost.

While not a perfect proxy for capital efficiency and financial returns, it is a sound and transparent approximation, that is easy to calculate and that can be consistently applied across basins. From slide six, the key conclusions from this independent third-party data are fully consistent, with our own bottoms-up industry analysis.

First, actual data for productivity and cost illustrates, that the Eagle Ford and Bakken are the two most capital-efficient basins in the U.S. Second, our performance is at the top of the pack, in each of these two advantage basins. And strongly exceed top quartile performance, across all other U.S. shale plays.

Slide seven shows that we are not only delivering this industry-leading capital efficiency from the historic core of the Bakken and Eagle Ford, Myrmidon and Karnes County, where we have a hard-earned and well recognized track record. But we are also delivering industry-leading results, across our broader acreage position in both of these plays.

We have talked quite a bit about organic enhancement and core extension, in recent years. These two graphics illustrate why. The top graphic highlights capital efficiency across industry since 2018 was wells grouped by operator and by county.

Effectively, this graphic shows exactly where our Bakken and Eagle Ford sub areas sit, on the industry capital efficiency stack. The key takeaway is that our core extension areas. Hector and Ajax in the Bakken, and Atascosa and Gonzales Counties in the Eagle Ford are among the best in all of industry, delivering top decile performance.

Notably, our core extension areas have outperformed, all major Permian pure-play operators, on a head-to-head basis. Importantly, virtually all of our approximate decade of forward inventory in both, the Bakken and the Eagle Ford, is concentrated in the historic and extended core areas shown on this page.

The concept that best summarizes this slide is sustainability. Our capital efficiency advantage is sustainable. It's underpinned by high-quality assets that will enable us, to continue executing against our reinvestment rate framework.

Yet while operational data points, such as 100-day cumulative production and total well costs are important, they ultimately only hold real value when they translate to tangible financial outcomes, at an enterprise level. Slide eight shows our company has a track record of delivering on the financial metrics that matter.

We aren't just committing to a forward-looking framework. Our framework is backstopped by a history of execution. At the bottom left -- the bottom left graphic on the slide shows, cumulative 2018 and 2019 free cash flow generation was the best in our peer group, equating to approximately 30% of our current market value.

And while this represented a solid financial outcome, we have significantly improved our forward free cash flow potential, thanks to significant cost reductions, and our optimized frameworks.

Assuming our 2021 benchmark maintenance case, we are positioned to generate the same absolute level of annualized free cash flow that we did in 2018 and 2019 at an oil price more than $15 per barrel lower. And at reinvestment rates, that ranged from 60% to 80% depending on your price outlook.

The slides that I've highlighted support my confidence in our company's competitive positioning and the sustainability of our organic business model. This confidence is underpinned by differentiated financial outcomes that are compelling relative to our peers, including recently announced combinations as well as relative to the broader S&P 500.

Industry consolidation is clearly topical and, overall, is a positive for the structure and long-term health of our sector. And while our focus this year has rightly been internal, we will always remain mindful of strategic opportunities in the marketplace that build upon our already outstanding financial outcomes. That is our job.

Yet, with such a strong organic outlook, our business model is not reliant on M&A for success, and any strategic action can be considered on our own time line. With scale so often quoted as the rationale for consolidation, we need to be clear that it has to be the right type of scale. We aren't looking to get bigger; we are looking to get better.

Getting bigger for the sake of getting bigger is not sufficient rationale for a combination. Any consolidation must first and foremost, deliver improved business outcomes. And we have a well-defined criteria for assessing such opportunities.

We will not budge from those criteria, and we won't force action near the bottom of a commodity cycle characterized by the elevated uncertainty associated with a crisis-driven and unprecedented global demand shock.

Any opportunity must be immediately accretive to our financial returns, must enhance our ability to generate free cash flow, must be balance sheet neutral at a minimum and must possess clear synergies and compelling industrial logic.

Any transaction would have to make us a better company, by improving our ability to sustainably deliver strong financial outcomes. And that is a very high bar with a decade of high-quality inventory in the two most capital-efficient U.S.

basins of the Eagle Ford and Bakken, complemented by the optionality of competitive opportunities in both Oklahoma and Northern Delaware. Self-help and making our organic business stronger is a benefit, whether we are going it alone or considering path to improve business performance and enhance scale via consolidation.

These are not mutually exclusive alternatives, and we can and must test all options that enhance shareholder return, but equally reject those that erode the underlying strength of our organic business model. Transitioning to slide nine, I'll briefly cover our third quarter results.

Since the beginning of the pandemic and commodity price collapse this year, our focus has been consistent, optimize our capital allocation and improve capital efficiency, reduce our cost structure and protect our investment-grade balance sheet and liquidity.

Third quarter results, including $180 million of free cash flow generation, along with the dividend reinstatement and gross debt reduction, are tangible proof points that our efforts are paying off. Briefly hitting the third quarter highlights.

Third quarter CapEx came in below our expectations on strong execution, contributing to very strong free cash flow. Further, well cost reductions were a primary driver. Our average third quarter completed well costs per lateral foot was down more than 25% relative to the 2019 average.

We expect to realize further well cost reductions in both the Eagle Ford and Bakken in future quarters. It is important to note and consistent with prior guidance, second half 2020 gross company-operated wells to sales are weighted to the fourth quarter.

Third quarter total production was near the midpoint of our implied second half guidance range, as we effectively achieved our exit rate for oil a quarter earlier than expected. Fourth quarter oil production will be relatively flat sequentially, establishing a stable baseline for 2021.

Third quarter total oil equivalent production was very strong, resulting in a 5,000 BOED increase to our full year production guidance at the midpoint. Strong base production management and improving gas capture across our asset base and in the Bakken specifically, contributed to the result. With respect to our cost structure, we drove U.S.

unit production costs down 13% versus the 2019 average, while international unit production costs achieved a record low for the segment. We reduced full year U.S. unit production expense guidance by more than 5% and international guidance by more than 8%.

We are exceeding our overall cash cost savings target for 2020 and are now forecasting $300 million of savings this year versus a prior expectation of $260 million. This strong execution across all elements of our business drove the robust $180 million of free cash flow during the quarter.

We not only expect to generate free cash flow during -- again, during fourth quarter, but we expect to be free cash flow positive for the full year. And we are putting this free cash flow to good use.

Advancing our dual objectives of returning capital to our shareholders through our base dividend reinstatement and improving our balance sheet through a $100 million gross debt reduction while cutting our 2022 maturity tower in half.

Importantly, both the fourth quarter dividend reinstatement and gross debt reduction were fully funded by actual third quarter free cash flow. With our company well positioned for sustainable free cash flow going forward, we will continue advancing both of these important objectives.

To close out my commentary, I will again take you back to our capital allocation framework summarized on slide 17 in our deck. It concisely summarizes our value proposition by using our 2021 benchmark maintenance scenario as a reference point.

Impressive downside resilience as evidenced by our low-cost structure and enterprise free cash flow breakeven, approximately $35 per barrel WTI breakeven in 2021, including our dividend, assuming gas prices consistent with the forward curve.

Clear visibility to material free cash flow in a mid-cycle price environment, over $600 million next year at $45 oil.

This represents a free cash flow yield approaching 20% with a commitment to dedicate a significant portion of operating cash flow, over 30% in a $45 barrel environment to investor-friendly initiatives, prioritizing return of capital to shareholders and balance sheet enhancement.

Significant upside leverage to even modest commodity price improvement, highlighted by over $900 million of free cash flow in a $50 per barrel environment. Though 2020 has been a stark reminder that we are price takers in a cyclical business and that we must manage our business conservatively, at some point, prices will recover.

And we believe it's important to protect our upside leverage so that investors can benefit from that leverage in the up cycle. Finally, we are well positioned to sustainably deliver on our framework, supported by industry-leading capital efficiency at both an enterprise and basin level and high confidence, high-quality forward inventory.

To close, with the backdrop of an unprecedented demand shock, our underlying business model and framework for success remain intact. And we are positioned to deliver in a more volatile and lower commodity price reality.

Our proven track record of results, combined with our reinvestment rate discipline, will enhance our transparency and resilience going forward. And our consistent focus on those elements of the business we control has delivered dramatic and lasting results.

Collectively, these actions have repositioned our company for success in the current environment, and for the uncertainty of the new normal ahead. Thank you. And I will now hand over to the operator to begin our Q&A session..

Thank you. [Operator Instructions] From JPMorgan, we have Arun Jayaram. Please go ahead..

Good morning. Lee and team. Lee, I was wondering if you could start-off and give us your perspective on the U.S. election. Obviously, we're not done yet.

Perhaps you can give us some of your thoughts on potential implications to the industry, MRO from a regulatory perspective, obviously, a lot of things, federal acreage, pipelines, you at IDCs around nuclear deal.

But I was wondering if you could start there?.

Yeah. Well, certainly, I'm not going to provide any prediction this morning, Arun. But I think we all recognized the energy policy and energy security really should be non-partisan, right? There should be full alignment on addressing the dual challenge of meeting growing energy demand and, of course, reducing the risk of climate change.

And we also know that the reality is that oil and gas is going to be an integral part of any future energy transition. And in fact, has provided a pathway for U.S. energy security. I think we have a responsibility to work collaboratively with whomever prevails.

So, at the federal state and local levels, so that we can meet that dual challenge, my view is failure on either is just not acceptable. I think the current uncertainty around federal land is a good reminder of the benefits of our multi-basin model asset diversification and capital allocation flexibility.

Certainly, we're realistic that with a Biden win, doing business on BLM land will become more difficult, and those are his words, not mine. But I just want to remind everyone as far as Marathon is concerned, we have very limited exposure to BLM land. In fact, in our core plays less than 10% of our acreage production and reserves resides on BLM land.

So overall, we don't necessarily view that element of the regulatory environment having any discernible impact on us. Clearly, we would be cognizant of the fact that under a new administration, there will be new regulations that will have to be addressed.

And I take some solace in the fact, though, to remind everyone that states like New Mexico have a vested interest in having a viable oil and gas industry. We're a significant provider of revenue and jobs for a state -- was one of the highest property rates in the U.S.

You touched upon everything there from foreign policy to tax policy, but maybe on the tax policy, perhaps maybe I'll kick that over today and just let Dane kind of share a few thoughts on how we're thinking about that..

Hey, Arun, sorry, you choked me up with your tax question. Excuse me. Yeah, I do think -- I'm not going to predict outcomes either, but it does look like Republicans are going to hold the Senate. And that should lessen the likelihood of aggressive tax policy changes.

But certainly, Vice President Biden has indicated multiple times that he wants to reduce incentives for energy, which I think we all translate to IDCs. In Marathon's case, we're not expecting to be a tax -- cash taxpayer at the federal level until late in the decade.

We've got NOLs and foreign tax credits that shield us from anything, but the highest commodity price environment, certainly, at prevailing prices or any of the ranges that Lee talked about earlier. It's going to be many, many years before we get there. IDCs, we actually kind of manage our tax strategy toggling between NOLs, tax credits and IDCs.

And frankly, we don't really lean very heavily on deducting IDCs in the current period. If that option went away altogether, I don't think it would change our trajectory at all on cash taxes..

That's very helpful.

My follow-up question, Lee, is just regarding how you're thinking about portfolio longer-term? Obviously, I think the first call on free cash flow looks to be the balance sheet, but how do you think about portfolio renewal? We do seem to be in somewhat of a buyer's market as you think about A&D low premiums and given your low-cost structure, I would think that you could be a natural consolidator, just given that -- the fact that you drill your wells much lower than industry averages, et cetera?.

Yeah. I think on the topic of portfolio renewal, I kind of take you back to the approach we've addressed before, which is first, it's really organic enhancement in our existing basins.

I think we showed very clearly how we continue to expand the economic window and enhance the capital efficiency of even our more mature basins in the Eagle Ford and the Bakken. So that's one element of it. We'll continue to assess smaller acquisitions and trades that we believe are accretive and fit within our footprint.

We always want to be open to those types of opportunities. But whether those opportunities are small, medium and large, they still have to really address that criteria that I described in my opening comments, financially accretive. They have to be generally balance sheet neutral. There has to be industrial logic and natural synergies there.

And then kind of the final element, the third element that I would highlight would be our continued commitment to our resource play exploration program. And I will just mention, as we talk about our maintenance capital kind of benchmark case into 2021. That still does include an element of resource play exploration capital as part of that plan.

So we believe that, that type of model where we keep the aperture wide open on those opportunities, but then apply a very exacting criteria that's very returns focused. That's the right approach for continuing to renew the business and grow our resource base..

Great. Thanks a lot Lee..

Thank you..

From Barclays, we have Jeanine Wai. Please go ahead..

Hi. Good morning, everyone. Thanks for taking my questions. .

Good morning, Jeanine..

Hi, Jeanine..

Good morning. I'm glad, you can hear me. It's my first day back in the office and nothing works. This is my first question. My first question is on the breakeven. And my second question is on inventory. So on the 2021 maintenance breakeven, that slightly improved in last night's update.

Can you discuss what assumptions are baked into that updated breakeven? I know you mentioned natural gas price is strengthening. But also, in particular, your well cost, they seem to be improving every quarter and you're anticipating further reduction sequentially in Q4.

So we're just trying to quantify how that breakeven could trend over the next few quarters? And then any commentary on productivity would be appreciated as well?.

Yes. No, absolutely, Jeanine. Thanks for the question. Maybe just starting with those underlying assumptions and what is really changing. First of all, just reflecting back on my comments, I want to be really clear that 2021 benchmark maintenance case, does not benefit from some outsized drawdown. It is basically on an unhedged basis.

And it does still include some modest resource play exploration spending. Now in terms of the improvement trend that you take note of, that is on the back really of us continuing to bake in actual performance in both operating efficiency and capital efficiency. So that's one element.

And then as you note, since essentially in these scenarios, we're holding WTI pricing constant, the gas price does have an impact. In our earlier maintenance cases, breakeven cases that we disclosed, we had assumed nominally a $2.50 gas price. Given the forward curve outlook, we have bumped that up to the $3.

And so when you kind of roll all that in there, in essence, this 2021 benchmark maintenance case where we're spending basically $1 billion to hold our 4Q '20 production flat. That's delivering essentially a $33 per barrel WTI breakeven. $35, if you include our dividend. If I could, I'll maybe shift, Jeanine, to your inventory question.

And -- I'm sorry, yes..

Jeanine, did you have a follow-up on inventory and a specific question there?.

Yes. So I guess we've noticed a new slide in the presentation, which are great and very helpful. You've discussed in the past of having about a decade of good inventory in the Bakken and Eagle Ford. I think you mentioned it again today. That could probably be maybe even a little bit longer given slower growth.

So can you provide any color on the criteria that you used to get to that decade of inventory number? And I think, specifically, if you have any commentary on what return threshold that you use at a certain oil price to count good inventory? And if you've got Tier 1, Tier 2 in that decade? And maybe any assumptions around spacing would be helpful too? Thank you..

Okay. There's a lot in that question. I'll try to unpack it. Maybe, first of all, let's start just going back to some of that third-party public data that we shared. When we look at the Bakken and Eagle Ford by these objective measures, they're not just among the best. I mean, they are the best from a capital efficiency standpoint.

And even as we step away from what we would consider the historic core areas, we continue to see those ranking as the best from a capital efficiency standpoint. And so, when we look at that 10 years of inventory across both the Bakken and the Eagle Ford, that is high return, high-quality inventory.

And without getting into hurdle rates and things, all of that inventory we would view. And certainly, within the price bands that we just addressed as being very accretive to our overall corporate returns. From a spacing standpoint, I mean, there are no, I would say, aggressive assumptions as it comes to spacing.

Within the Bakken and the Eagle Ford, we have very well-established spacing designs across the zones and within the various geology that exists in the plays. We tend to look at both maximizing PV, as well as returns within a given DSU, and that's really again, supporting this 10 years of inventory.

So, there's nothing in, I'd say, this analysis that is aggressive as it pertains to spacing. The other thing I would just add is that, we continue to see both on the cost and the productivity side, ways to move the needle there. From a cost standpoint, when we continue to drive down our completed well cost.

And on the completions and productivity side, we continue to optimize our designs. And if you look again at our productivity data, if you normalize for geology, we continue to see an improving trend there as well. So, all the vectors are in the right direction. So I'll just pause there, Jeanine, and see if I touched upon most of your question..

Definitely, that was very helpful. Thank you..

All right. Thanks, Jeanine.

From Truist Securities, we have Neal Dingmann. Please go ahead..

Could you speak -- you guys sounded confident in the prepared, I guess, in the press release, I should say, on your inflection point comment. And it does sound like, you're certainly trending that way.

I'm just wondering, maybe could you give some more color on just the confidence either you, from your side or data from the finance side that you have turned that corner to generating more consistent free cash flow on that inflection?.

Yes. Neal, well, certainly, when you look at third quarter performance, and bear in mind, this was on essentially a $40 WTI kind of marker pricing. When we're able to generate that level of cash flow in that type of environment, particularly as we kind of land, even a bit earlier on our exit rate expectations, I think that really tells the full story.

And so, as we continue to move throughout fourth quarter, we're still very confident that, that trend of consistently and sustainably generating free cash flow will remain in place. And that confidence is really underpinned on that enterprise breakeven that we've worked so hard to drive as low as reasonably practical.

In fact, just as a reminder, in the second half of 2020, our breakevens really for the second half of this year are in the low 30s, right? So, I just want to remind everyone of that. So, I think we're on the right trajectory. It's building on a track record that we firmly established before.

I think, we had this black swan event at the beginning of this year. We were delivering on all of those metrics that matter in '18 and '19. We had returned $1.4 billion back to our shareholders in that period.

And obviously, when you look at the delivery of free cash flow from our model, whether it's kind of our view of mid-cycle pricing at kind of $600 million of free cash flow or with even just modest pricing improvement towards $50, you can see the outsized torque that we have to the oil price with that number going up basically to $900 million..

And then, Lee, it kind of touches into my -- just my follow-up. Just it seems like the cycle times, I mean, you guys continue to improve. Can you maybe just discuss Eagle Ford and Bakken cycle times? They certainly just continue to improve.

And does that, give you the flexibility on when you're looking at this plan?.

Yes. Well, certainly, cycle time is an integral part of the overall well economics, just like well cost and productivity. And it's our ability to really minimize that time for when we start on the well, until we actually start making money.

And so, maybe I'll just kick over to Mike and just let him talk about, we continue to see improving trends in both the Eagle Ford and Bakken on those points..

Yes. I'll just build on that a little bit, Neal. I think we've touched on some of this during his comments. There's probably three or four areas that we're particularly focused on, and we're seeing the benefits. I think, in the well design area as well as the cycle times. Our emphasis on maximizing volume as well as returns I think is helping.

The – another big area, and this came out in the deck was just execution efficiency. I think our teams have a relentless focus on just driving further improvements there. The third area I'd probably highlight would be supply chain optimization. We have modeled should cost models. So we have a good understanding of how much things should cost.

And we really use that to drive our sourcing strategies. And then the third – or sorry, the fourth element would just be commercial leverage. And really, that comes in the form of inflation. What I would say is the first three are more structural in nature, and that's where our teams spend most of our time..

Very good. Thanks, Lee, thanks, Mike..

Thanks, Neal.

From Scotiabank, we have Paul Cheng. Please go ahead..

Thank you. Good morning..

Good morning, Paul..

Two questions. One is short and one maybe is maybe twofold. The short one is that with the number of wells you're coming on stream, coming in the fourth quarter. One would have thought your production should be up somewhat from the third quarter level in oil. And you are flat according to your guidance.

Is it that just simply a timing of those well coming on stream or is there any other reasons? The second question is that one of your competitor argue in the merger announcement that size does matter in terms of the attractiveness to investor and think that if you are below a certain size, probably less than $10 billion that the investor will just ignore it and not even on the water screen.

I'm just curious that whether you agree with that assessment? And also that whether – how you take that into consideration and the Board, looking at any M&A opportunity? And that when we're looking at M&A, is what type of ideal merger partner that from your standpoint, from a basin, is it that they will be offering a lot of synergy in the existing basin or diversification? Yes, a benefit? Thank you..

Okay, Paul, I'm going to – I'll start trying to tick through those, but thanks for the question. First of all, maybe I hope on the short answer question. For the number of wells on stream in the fourth quarter, those – we do have a higher well count. In fact, we have about double the wells to sales between third quarter to fourth quarter.

But those are arriving relatively late in the quarter, and therefore, you don't necessarily see the full impact of those barrels coming online in fourth quarter. And even though, obviously, we talk about our business on a quarterly basis, we're managing our business through the quarters and looking ahead to – already to 2021 as well.

On your second question, just around speculation around what generates investor relevance. First of all, I'll maybe just start off by saying the sector must certainly mature. And part of that maturity will probably be consolidation that ensures assets get in the hands of the most efficient and financially-healthy operators.

Having done all the repositioning that we've done for our company, significant and sustainable free cash flow, shareholder-friendly actions, a track record dating back to 2018, we certainly believe we're one of those operators.

At the end of the day, profitable and sustainable E&P companies that deliver on the financial metrics that matter are going to attract investors irrespective of size. I mean, size, obviously, is an element.

But if you have a profitable company that generates strong free cash flow across a lower and more volatile price deck and that takes investor-friendly actions, my perspective is that's an investable thesis.

I mean, our belief is that an E&P company should be judged on its financial outcomes and profitability, scale alone does not secure financial performance. And I'll just maybe just leave it there, Paul..

Thank you..

From Goldman Sachs, we have Brian Singer. Please go ahead..

Thank you. Good morning..

Good morning, Brian..

My first question is with regards to a return of capital and leave it to the analyst community right upon your re-initiation of a dividend to ask about incremental return of capital, but I guess we'll go there anyway.

Can you just talk philosophically about your framework? You're very clear about the reinvestment rates, the prioritization of the base dividend and the balance sheet enhancement, getting down to 1 to 1.5 times leverage, where does incremental return of capital fit into that? Does leverage need to get down to one to 1.5 times before the base dividend or any other return of capital can go up, or is there some middle ground?.

Well, I think – and I'll kick over to Dane, just a second here to maybe build on your question, Brian. But the reality is that, I think what we demonstrated in the last quarter is we can do both. We can walk in to go, meaning that we can we can address our balance sheet as well as be focused on return of cash to shareholder.

Beyond the base dividend, I think, clearly, we're going to have to see achievement of some of our balance sheet goals, which we view as kind of midterm goals. But maybe I'll kick over to Dane just let him talk a little bit about the prioritization of free cash flow, which, by the way, is a great problem to have..

one, to cut that $1 billion 2022 maturity in half; and two, to accomplish a starter step toward deleveraging, and we accomplish both of those goals. So that 2022 maturity is very manageable. We de-levered by $100 million.

I would say, first call on cash near-term will be incremental deleveraging, and we've got lots of levers in our future maturity towers to do that. We don't have to wait to maturity dates to take care of it as we just demonstrated and in a modestly improving commodity price environment.

I think that opens up the aperture for doing both, doing more return of capital to shareholders, while we de-lever.

So I think that the fact that, we're positioned as such a strong free cash flow generator gives us a lot of optionality there, and we'll exercise that optionality but very near term, it will be balance sheet first, and then we'll keep an eye out for returning capital to shareholders..

Great. Great. Thank you. And then my follow-up is to continue on the M&A thread here. And you were pretty clear about the criteria that needs to make the company better and not just fully for scale, but I wondered if you could characterize the market today and whether those opportunities exist or whether, in your mind, it's just more theoretical.

And then if you look across your portfolio, you highlighted the inventory that you have in the Bakken and the Eagle Ford.

In particular, is it – is there more or a better opportunity to pursue incremental scale there versus to try to bring up the Permian or Oklahoma to maybe compete from a size or scale perspective relative to the Bakken and Eagle Ford?.

Yeah. Yeah, I think, Brian, just to maybe reiterate our stance, because it is, obviously, I think, the topic de jure. We have confidence in our organic model. But it's not at the exclusion of strategic options that could enhance our financial outcomes. And part of the path to get there may in fact be scale.

And as you stated, to that end, we do have a very well-defined criteria. I wouldn't say, it's purely theoretical, what I would say is it's very exacting because we are already generating such strong and compelling financial outcomes.

When you look at our breakevens, when you look at the capital efficiency of our portfolio, when you look at the free cash flow yields that we can generate at today's pricing as well as even with modest price support, we have to be very confident that any strategic option that we were to pursue would, in fact, be additive to delivering against those financial outcomes.

In terms of specific preference to basins, although that today, Bakken and Eagle Ford are certainly receiving the lion's share of capital allocation. And again, I'll take you back to that capital efficiency chart. That's what's driving that. We're going to the highest return, most capital efficient elements of our portfolio.

We are also governing that investment by this reinvestment rate criteria. And so there are very competitive opportunities that reside in both Northern Delaware and Oklahoma. And we clearly see those competing for capital as we move forward in time.

Would we, obviously, look in our more mature basins of the Eagle Ford and Bakken given our operations excellence in those basins? Well, certainly, we would. But we would not limit the aperture to just those two basins.

I mean, to really to meet that criteria, I think right now, you do have to keep that aperture wide open and – but still rigorously test against it, because we certainly don't want to take action that would, again, erode the strength of what is already a compelling organic business model..

Great. Thank you..

Thank you, Brian..

From Wells Fargo, we have Nitin Kumar. Please go ahead..

Hi, good morning Lee and team. Thanks for taking my question..

Good morning..

Maybe I want to start with M&A. One thing I noticed was in the Oklahoma, you have managed to keep your production relatively flat with almost six months of no real activity or new activity.

Just kind of curious, what's driving that? Is there some base management or something that we should be thinking about?.

Yeah. Excellent observation and question. And the way I would think about Oklahoma is, first of all, as we wrapped up the drilling and completion program in Oklahoma, we had some very successful wells that came out of that program. In addition to that, clearly, Oklahoma did see some shut-ins during the peak of the crisis.

And so as we brought some of those wells back online, we did, in fact, see some elements of flush production. But I think overall, there is a more moderate decline that exists and much of the Oklahoma portfolio, just due to the nature of those reservoirs. And so yes, Oklahoma has been a great successor.

And I also want to just shout out to that team is despite having de minimis D&C activity, their focus on uptime, reliability and that type of performance has just been outstanding. And our most profitable barrels are the ones that we've already invested in.

And so you see that, that team taking it to a whole new level and really being focused on keeping those existing barrels online and ensuring that everything from gas lift optimization to keeping our surface facilities up and running. So I think that's what you're seeing in that decline curve in Oklahoma..

Excellent. And then, I guess, the other question, which has been asked, but I'll ask it a little bit differently, I guess. You exit the year with a few more completions. And, obviously, this has been a challenging year. One of the things you focused on in the past has been ratability of your spending and activity.

How soon do you think you get back to that in 2021, or maybe is it later?.

Yeah. I think you probably need to differentiate activity perhaps between when wells to sales come online. Actually, our activity is very ratable in many respects in the third and fourth quarter, meaning that we have two frac crews essentially running basically, six drilling rigs running.

What you're seeing is, obviously, as wells come online from pad drilling, they do tend to come on in batches. If we have a pad that has exceptionally long laterals, it will take a bit longer to get it online. And so I think what you're seeing is some natural variability in the activity.

I think probably the best way to look at it would be to look through third and fourth quarter and put those two together and look across the average of that half year, and that really delivers what is, I think, a more indicative ratable capital spend, recognizing there is going to be variability on when wells are delivered.

I mean, again, we don't -- we're not tailoring those wells to hit at certain points in a quarter. I mean, we're driving that those six rigs and those two frac crews to maximize efficiency. And, of course, the wells comes to sales as they come to sales..

Great. Thank you for your answers..

And from Bank of America, we have Doug Leggate. Please go ahead..

Thanks. Good morning Lee. Good morning everyone..

Good morning Doug..

Lee, hope you're doing well. I admire the continued disclosure on the free cash flow, which is obviously what everyone's focused on. My question is longevity.

What are you thinking today when you look at -- when you talk about $1 billion of sustaining capital, what's the longevity of the portfolio without REx at this point? And I guess, if you could share also, maybe it's a second question, if you could share also what proportion of that cash flow, free cash flow currently is coming from EG? I'll leave it there.

Thanks..

Yes. I'll -- maybe I'll take the first part on longevity, and maybe I'll kick over to Mitch to talk a little bit about EG performance and its contribution.

Clearly, Doug, for us, we believe very strongly in the three elements of resource enhancement that I talked about earlier, organic enhancement within basin, in addition to smaller trades and acquisitions and then, of course, the REx program that you mentioned. All of those are embedded in our forward outlook.

We don't view that as an either/or proposition. We want to ensure that even within our benchmark maintenance case that we're continuing to reinvest in elevating in-basin performance, in-basin resource as well as continuing to support REx and have the financial flexibility that if there is a market-based opportunity that we can act on that.

Strictly to the longevity, let's just kind of set all that to the side and even zero that out. We have high confidence, as you have seen in some of the presentation material, that the Eagle Ford and the Bakken are superior to really any of the U.S. shale plays.

And we have a 10-year inventory life in both of those basins that we believe can drive the business to generate consistent outcomes to 2021. In other words, we don't see a falloff in that performance as we move forward in time because we're going to obviously continue to work on cost efficiency on productivity gains, et cetera.

So, we see that model as being consistent and really being complemented then by the more competitive opportunities that we still have access to in Oklahoma and Northern Delaware, particularly as we see strengthening in secondary product pricing, particularly gas and NGLs. So, we are very confident in the longevity of free cash flow delivery.

And we're also equally confident that we can continue to progress our, I'll call it, resource enhancement work as part of our reinvestment rate framework.

Maybe I'll just kick over to Mitch for just a minute to share a few thoughts on EG and kind of the -- not only the path today's contribution of EG, but kind of what that future contribution may look like..

Good morning. Consistent with how we've talked about EG for a number of years and quarters, it certainly a strong asset for us and has historically generated meaningful free cash flow. This year, like the rest of our business, EG is certainly not immune to the price pressure that's occurred.

However, as we move in through the third quarter and into the back half of the year now, we have seen modest price recovery across the board. We've got a Henry Hub index contract at the LNG facility. Methanol prices have certainly improved significantly. And so we would expect to return to meaningful dividends in the fourth quarter from that business.

Having said that, I think, more broadly, your question, our U.S. business generates significant free cash flow as well. And particularly from the Bakken and Eagle Ford assets, where they have a track record of doing that for some time. So, with respect to EG going forward, I would expect 2020 to be a bit of an outlier on the low side.

It's an asset that doesn't require a lot of continuous investment. We've got the Alen backfill project, that's proceeding on schedule coming on in the first half of next year, seeing this price recovery, modest price recovery, certainly relative to Q2.

And we continue to progress and pursue additional regional gas opportunities, where we've got this really world-class infrastructure that's uniquely positioned with TCFs of discovered and undeveloped gas around us in the region and are at various levels of maturity with a number of interested parties in trying to enhance and pursue those opportunities further..

Guys, I wanted just to clarify, I'm looking at slide 8, the 2021 guidance on the free cash flow. I'm just trying to get a handle as to what proportion of that free cash flow is coming from EG. That was really the question I was asking..

Yeah. I mean, we can -- we can get more into that when we actually put forward a physical business plan and talk a little bit more explicitly about the sources of our free cash flow. But the reality is, as Mitch pointed out, a big proportion of that is coming from the U.S. resource plays.

And that's really -- and if you look at the fact that we had, obviously, some maintenance, et cetera, at EG earlier this year. So there have been some impacts to that. And then, coupled with the price dislocation that Mitch referenced, its contribution has been pretty -- in a relative sense, has been relatively small this year.

As we move more into more constructive gas pricing, certainly, we would expect EG to perhaps come back more equivalent to historic levels that we have seen in that asset. If you rewind back to 2019, EG was throwing off considerable free cash flow.

But for us, there's a -- obviously, this is where the diversity of the portfolio really comes into play, because we have that diversity, not only across basin, but also across the various commodity types. And in this case, EG may have been penalized for gas early in the year, but it could step up as we move into 2021.

So, I would just say more to come as we move from kind of talking about a benchmark case to the physical business plan..

Thanks a lot. That.

Okay. Thanks, Doug..

Thank you. We'll now turn it back to Lee Tillman for closing remarks..

I wanted to end by recognize our employees and contractors have been so resilient, during these challenging times, never losing sight of our core values. Thank you for your interest in Marathon Oil and that concludes our call..

Thank you. Ladies and gentlemen, this concludes today's conference. Thank you for joining. You may now disconnect..