Welcome to the Marathon Oil Q4 Earnings Call. My name is Vanessa, and I will be your operator for today's call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. [Operator Instructions]. Please note that this conference is being recorded.

I will now turn the call over to Guy Baber, Vice President of Investor Relations. Sir, you may begin..

Thank you, Vanessa, and thanks to everyone for joining us this morning on the call. Yesterday, after the close, we issued a press release, a slide presentation and investor packet that address our fourth quarter and our full year results as well as our 2021 capital budget. Those documents can be found on our website at marathonoil.com.

Joining me on today's call, as always, 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, Senior VP of Operations.

Today's call will contain forward-looking statements subject to risks and uncertainties that could cause actual results differ materially from those expressed or implied by such statements. I 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, I'll turn the call over to Lee, who will provide his opening remarks. We'll also hear from Dane, Pat and Mike today before we get to our question-and-answer session.

Lee?.

corporate returns and free cash flow, returning capital to our investors, strengthening our balance sheet and ESG excellence. Additionally, we will stay focused on executing on our transparent framework for capital allocation.

More specifically, we will continue to optimize our cost structure and reduce our corporate free cash flow breakeven, further improving our downside resilience and enabling us to generate free cash flow across the widest possible range of commodity prices.

We will stick to our disciplined reinvestment rate capital allocation framework to provide clear visibility to free cash flow generation and the use of a meaningful percentage of our operating cash flow for investor-friendly purposes, prioritizing balance sheet enhancement and return of capital to shareholders.

As a reminder, assuming $45 per barrel WTI or higher, our reinvestment rate will be 70% or less, and we will make at least 30% of our cash flow from operations available for investor-friendly purposes. Finally, if commodity prices surprise to the upside, we will remain disciplined and won't chase growth.

Even if the recent commodity price strength persist, we will not raise our capital spending. Our $1 billion maintenance capital budget will remain our budget. With higher pricing, we will simply generate even more free cash flow.

We will accelerate our balance sheet improvement and the realization of our targeted leverage metrics, and we will evaluate incremental return of capital to our investors beyond our base dividend and a minimum $500 million gross debt reduction target for 2021.

With this brief overview of our capital allocation framework, I will now turn it over to Mike Henderson, who will walk us through the highlights of our 2021 capital program..

Thanks, Lee. As Lee mentioned, our 2021 $1 billion maintenance capital program is fairly consistent with our capital allocation framework, prioritizing the financial and operational results that matter most.

A few of the highlights, as summarized on Page 6 of our earnings deck, our $1 billion maintenance program is expected to deliver $1 billion of free cash flow at $50 WTI with a reinvestment rate of just 50%.

You'll note this is an improvement of about $100 million relative to the maintenance scenario, free cash flow outlook we provided last quarter at the same price deck due to a combination of further capital efficiency improvements and ongoing cash cost reductions.

Our 2021 corporate free cash flow breakeven is comfortably below $35 WTI, underscoring the resilience of our program. We are targeting $500 million of gross debt reduction this year, consistent with our objective to continue improving our balance sheet.

We will drive further GHG emissions intensity improvement, targeting a 30% reduction relative to our 2019 baseline. And we expect to deliver flat total company oil production relative to fourth quarter 2020 exit rate.

Regarding the operational details, approximately 90% of our capital will be dedicated to the Bakken and Eagle Ford, the industry's most capital-efficient basins. We will operate around 5 to 6 rigs and will average about 2 frackers for the year. Additionally, I'd like to address 2 other topics of interest regarding our 2021 outlook.

First, last week was obviously a challenging one from a weather perspective, equally impacting all of our primary basins. Each of our asset teams has demonstrated an ability to respond successfully to significant weather events, be it hurricane, floods or extreme winter weather.

However, the broad nature of this extreme winter storm tested all of our asset teams simultaneously. I would like to recognize all of the efforts of our field teams across the U.S. who have gone above and beyond over the past week, getting much needed volumes back into the market in an effective and safe manner.

Like many operators, our volumes have been impacted by the extreme freeze. We therefore expect first quarter company oil production to be down slightly relative to the fourth quarter. However, these challenges are fully reflected in our annual production guidance, and we have no concerns about delivering on our full year commitment.

Second, while I have highlighted the free cash flow potential of our program at $50 WTI, clearly, the current forward curve is much stronger than that. As we mentioned, should stronger prices hold, we will maintain our discipline and prioritize our free cash flow generation.

Assuming just $55 WTI, a price that's still below the current strip, we would expect our free cash flow generation in 2021 to increase to over $1.3 billion with a reinvestment rate below 45%. With that, I will turnover to Dane Whitehead, who will cover our ongoing efforts to continue optimizing our cost structure..

a 25% reduction to CEO and Board of Director compensation; 10% to 20% compensation reduction for other corporate officers; a further employee and contractor workforce reduction to better align our organizational capacity with our expected future activity levels; and a reduction to aviation, real estate, projects and various other costs.

While our first quarter 2021 earnings will include an uptick in our reported G&A, largely reflecting onetime costs associated with the recently implemented workforce reduction, we expect to realize the majority of projected cost savings across both G&A and production expense categories by the end of this year on a run rate basis.

Ultimately, we're driving toward a cumulative production costs and G&A cost reduction of approximately 30% relative to 2019 and 40% relative to 2018. I'll now turn it over to Pat to cover our newly disclosed 5-Year Benchmark Maintenance case.

Pat?.

Thanks, Dane. Slide 8 of our covers the highlights of our new disclosure around a 5-Year Benchmark Maintenance Capital Scenario. First, I want to be clear that this is not 5-year guidance, nor is it a 5-year business plan.

Rather, this is simply a benchmark scenario designed to hold our fourth quarter 2020 total company oil production flat through 2025. It is supported by a bottoms-up, well-by-well execution model. It should be evident that our '21 capital program is among the most capital efficient of any E&P company.

$1 billion of all-in capital to deliver $1 billion of free cash flow at $50 WTI, with a 50% reinvestment rate and over 170,000 barrels of oil per day of production is impressive by any measure.

The intent of this 5-Year Benchmark Maintenance Scenario is to showcase the sustainability of our capital efficiency advantage and outsized free cash flow potential over a longer-time horizon that is still underpinned by defensible execution assumptions. But one might argue for an even longer-term scenario.

Such forecast ultimately lack the line of sight of a bottoms-up execution model and the accountability that a 5-year scenario provides. So even though we consume well below half of our high-quality inventory in this maintenance scenario, we felt the 5-year view is the most relevant and credible.

The financial outcomes of our maintenance scenario are clearly compelling. Assuming flat $50 per barrel WTI, we can deliver approximately $5 billion of free cash flow over the next 5 years with an average reinvestment rate of around 50%.

Our corporate free cash flow breakeven remains below $35 per barrel WTI throughout the period, evidence of the strength of our capital efficiency and high-quality inventory.

To hold our fourth quarter 2020 total company oil production flat over the 5-year period, we would spend between $1 billion and $1.1 billion annually of all-in maintenance capital.

Importantly, this all-in capital spending estimate fully contemplates our previously disclosed greenhouse intensity reduction initiatives, including approximately $100 million of cumulative funding for the 5-year period.

Finally, it's worth noting that our 5-Year Benchmark Maintenance Scenario includes capital allocation across our multi-basin portfolio.

While we leaned heavily on the Bakken and Eagle Ford in 2020 and will do so again in 2021, under this scenario, we begin to introduce a measured and disciplined level of activity back into the Permian and Oklahoma beginning in 2022.

The Permian and Oklahoma comprise between 20% and 30% of resource play capital each year from 2022 to 2025 in this scenario. Both assets are expected to deliver accretive corporate returns and contribute to corporate free cash flow from a high-graded opportunity set.

Now I'll turn it back to Lee, who will wrap up by highlighting our ESG excellence initiatives..

$1 billion of free cash flow for $1 billion of capital at $50 WTI, significant free cash flow upside if commodity price outperformance persist, at least $500 million of gross debt reduction to continue improving our balance sheet and further reductions to our GHG emissions intensity.

We have already taken specific action this year to continue our multiyear cost reduction track record. More specifically, the company has taken additional action in 2021 to achieve an approximate 30% reduction to its combined production and general and administrative costs relative to 2019.

The company expects to realize the majority of these savings on a run-rate basis by the end of 2021. We have disclosed a 5-Year Benchmark Maintenance Scenario that underscores the sustainability of the peer-leading capital efficiency and free cash flow we are already delivering.

At flat $50 WTI, we could deliver $5 billion of free cash flow through 2025. And last, but certainly not the least, we have taken a leadership position in driving reductions and design changes in executive compensation and GHG emissions intensity reduction initiatives our sector needs to pursue more broadly.

Our industry was in transition well before the global pandemic, and our company was among the first to recognize the need to move to a business model that prioritizes returns and sustainable free cash flow as opposed to growth.

In this more disciplined model, capital and operating efficiency are paramount and, in fact, represent our competitive differentiators. We must deliver financial outcomes and ESG excellence that are competitive not only with our direct E&P peers, but with the broader market as well.

With that, I will turn it over to the operator to begin our Q&A session..

[Operator Instructions] We have our first question from Jeanine Wai with Barclays..

Our first question is on just the buyback, variable dividends, current capital subject.

On the amount of free cash flow set aside for investor-friendly purposes, is getting to the top end of your 1 times to 1.5 times leverage target, is that put enough such that you'll start allocating some free cash flow towards buyback or variable dividend? I know some of it depends on your cash balances that you're targeting as a minimum.

Some of it's been on the macro.

But is that 1.5 times enough?.

Yes. There's quite a bit in there, Jeanine. Let me go ahead and take a cut at it. This is Dane. We tried to be really clear about our intentions around the balance sheet and other return of capital to shareholders. There's sort of a gross debt discussion and a net debt discussion in there, so let me talk about those first.

As Lee and Mike noted, we have a ‘21 -- 2021 target of $500 million gross debt reduction. I would consider that a minimum. But that's our near-term goal and probably happened early in the year. So that's gross debt reduction. And in my view, that's kind of the most durable structural form of deleveraging.

It also carries the added benefits of reducing cash, interest costs and derisking future maturities. We've done about $2 billion worth of that over the past few years, and it's helped our cash cost structure mildly. And we'll continue to do that.

We've also, as you referenced, been clear that we're looking to reduce our net debt-to-EBITDA number, commonly used leverage term to a 1 times to 1.5 times range. And the math we think about there is to get to 1.5 times in, say, a $50 mid-cycle oil market, that's a reduction of net debt by about $1.3 billion.

So with commodity prices where we are today, we're probably going to get to that point much more quickly than we had anticipated coming into the year. But we certainly are focused on getting there.

And as we -- as net debt comes down, and you can do that just by accumulating cash on the balance sheet, we'll probably go ahead and take out further gross debt, but also look in tandem to look at other ways to return cash to shareholders.

We have a good, pretty strong track record of doing these things in parallel, both paying down debt and returning cash to shareholders. And we know that's very important to people.

We happen to be in an environment where we are going to be generating quite a bit of cash when commodity prices hold, and we're going to pay close attention to our options there..

My second question, maybe shifting gears is just on the 5-year maintenance scenario and just general capital efficiency. So I guess in terms of general capital efficiency by operating areas and how you kind of see that evolving over time.

You mentioned in the slides and in your prepared remarks, the 5-year maintenance scenario has 20% to 30% CapEx for the Permian and Oklahoma. And the total CapEx is $1 billion to $1.5 billion versus the 2021 plan only has 10% in those areas, and it's $1 billion in CapEx.

So I guess my question is, is the $100 range on the 5-year scenario, is that related to folding in the Permian and Oklahoma and that reflects kind of lower capital efficiency in those areas because there hasn't been a ton of activity in those areas recently.

And so what's kind of driving the Permian and Oklahoma retiring more CapEx, both this year and is it purely returns related? Or are there kind of other factors such as wanting to maintain operational facility in all of your leases?.

Jeanine, this is Lee. I think the simple answer to your question is it's returns driven. And maybe it's worth just kind of restating a few of the things I pointed out in my opening comments. When we talk about this 5-year benchmark case, it really is all about demonstrating sustainability.

And as we continue to develop both the Eagle Ford and Bakken, obviously, that's the focus this year. We see this opportunity to blend in a high-graded opportunity set from both Oklahoma and Permian while also offsetting things like base decline in Equatorial Guinea.

But even across that 5-year period, I want to point out that we're still only consuming less than half of our high-return inventory. And all this is supported, as was described, by a very much a bottoms-up, well-by-well execution model that's very defensible. So the short answer to your question is it's allocating capital on a returns basis.

And via the high-graded opportunities in both the Permian and Oklahoma, we believe those can be very accretive across the 5-year plan..

We have our next question from Arun Jayaram with JPMorgan..

Lee, I wanted to ask you a little bit more around the 5-Year Benchmark Maintenance Scenario. $5 billion of free cash flow at $50. On a post-dividend basis, it would be $4.5 billion.

So beyond some of the debt reduction targets that Dane just mentioned, how do you balance returning cash to shareholders versus a portfolio renewal?.

Yes. I think it's -- as Dane mentioned, in this type of price environment, it's really not an either/or solution any longer. I think with the current prices, we can clearly accelerate the attainment of our desired debt metrics, both net debt as well as gross debt.

And I think can somewhat contemporaneously with that, I think we can continue to drive capital back to our shareholders. We will continue to be opportunistic in the market as well as internally on our organic enhancement opportunities to continue to add to and enhance our resource base. And that's really just part of the equation.

And that will include everything from continued investment in our REx program to say smaller bolt-on opportunities that might present themselves as well as organic enhancement like some of the redevelopment activities that we have going on in the Eagle Ford currently.

So we feel very confident that we can address all those uses of cash, particularly as we look at the current pricing environment that we're facing..

Got you.

And I don't know if Mike could maybe shed some light on some of those opportunities in the Eagle Ford?.

Yes. Sure..

Yes, yes. Arun, good morning. I think as we mentioned in the deck, we've got potential for several hundred new locations there. We're undertaking a section-by-section review. We're thinking about the Upper Eagle Ford and the Lower Eagle Ford as one flow unit.

We are going to be targeting some of the older vintage completions and sections with lower recoveries. We have already undertaken a number of tests over the past 2 or 3 years. The results were very encouraging. We do have further tests planned for this year. So I'd anticipate a bit of an update later on in the year..

Okay. And Lee, my follow-up is just on EG. It looks like the Chevron, not Noble LN project, achieved first gas in 2021.

Can you talk about the implications of that towards your free cash flow, your financials and just talk about the longer-term free cash flow outlook that you provided in the deck in EG?.

Yes. Yes, Arun, yes, you're right, we did successfully start up the third-party LN project. So we're very pleased with that. That just started up kind of the middle of February.

We tried to provide a little bit more transparency and disclosure on both equity income in EG and what that really looks like, particularly over 2021, but also kind of a 5-year view of equity plus the income from our PSC as well and more of a free cash flow mindset.

And when you look at that on kind of a $50, $3 Henry Hub basis, it accounts for roughly a couple hundred million of combined free cash flow when you look at it relative to that Benchmark Maintenance Scenario, so just about 1/5, if you will, of the annual kind of impact on free cash flow. So just trying to provide a little bit more transparency.

Clearly, LN specifically, we haven't broken that out just because of the terms of the agreement are obviously private. But clearly there, we're getting the benefit of both tolling as well as profit sharing on those molecules..

We have our next question from Neal Dingmann with Truist Securities..

Lee, for you and the team, I'm just wondering, I think on the slide -- looking at Slide 6, where you talk about the 60, 80 Bakken wells, 100, 130 Eagle Ford, could you all talk about how you're looking at not only maybe total locations in each kind of on a go forward? Obviously, you have a more conservative plan which certainly helps.

But I'm just wondering also, you've got the -- when I look at the core areas of Hector and Ajax and the Bakken and Atascosa and Gonzales and Eagle Ford, how you think about total location? It seems to me you still have just kind of running room there.

So just wondering any color you could add either total or in those core areas?.

Yes. Neal, I think broadly, the way I would think about the Eagle Ford and the Bakken is that we have a decade or more of very capital-efficient, high-return inventory. And that's at a relatively conservative price deck, kind of consistent with more of a mid-cycle view of the world. So say, $45, $2.50 gas.

So you're correct, that's a pretty conservative view. I mean that's an inventory that clearly we're leaning on this year. That inventory will be complementary to some of the work that we have out 2022 plus in Oklahoma and Permian as we start exploiting what is a very high-graded opportunity set in those 2 basins of well.

And collectively, we feel very confident in that kind of 10-year-plus high-return inventory across the portfolio at relatively conservative benchmark WTI prices..

And then just one quick follow-on.

If you talk any thoughts or expectations for the Texas, Delaware oil play either this year or into next year?.

Neal, this is Pat. I'll take that one. Our objective this year is to continue progressing that play. I may remind you that we brought on 6 wells across the play over the last year plus. And the wells have delivered 180-day productivity that exceeds industry average Wolfcamp and Bone Spring performance.

In aggregate, that program has met our expectations and improved the viability of the Woodford and Meramec across the position. Our objective has been to prove out that productivity and the reservoir characteristics.

And we've seen exactly what we hope to see, which was strong productivity, high oil cut, shallow decline, the oil ratios, which are much lower than the rest of the Delaware.

As far as '21 goes, we plan to bring on a 3-well pad this year, targeting both the Woodford and Meramec to kind of do a spacing test, and we'll see how that works out for us through the year..

Our next question is from Scott Hanold with RBC Capital Markets..

Could you give me a little bit of color on -- I know you've got the structure where you're going to remain disciplined this year. But obviously, it looks like we could be moving into a higher oil price scenario. And I know your prior outlook had discussed a 5% limit on growth.

But when you think about that upside case, could you talk about like how you would progress into that? And then what would the relative capital allocation to, say, the Eagle Ford and Bakken in that scenario versus your maintenance baseline?.

Yes. Scott, I think the keyword for us is going to be disciplined. We're obviously going to look at fundamentals of supply and demand, the price outlook. There is absolutely a limiter to what we would even consider in a growth context.

And again, I'll go back and say, let's not confuse the 5-year benchmark case with a business plan or in terms offsetting an expectation. It was really a demonstration of sustainability within the portfolio. But I think you should expect us to lean heavily on the same framework that we have really since 2018.

If we see that upside potential, we'll look to support our base dividend first. We'll look to accelerate the improvement in our balance sheet and our debt reduction. Then we're going to look at incremental means to get capital back to shareholders.

And then at that point, depending upon where market fundamentals sit, you can have a discussion about whether or not growth into the market really makes sense.

Clearly, as we sit here today and what I believe is still a well-supplied market, even though we're seeing more consistent drawdowns now, we've got like I said a very nascent recovery in demand that's occurring, I still believe that a disciplined approach is going to win the day.

And certainly, from a financial outcome standpoint and making sure that we are competitive with alternative investment opportunities within the S&P 500. We have to continue to drive, I believe, outsized free cash flow in order to, if you will, offset the implicit risk and volatility that exists in our sector..

And Lee, if I could ask you this, over the last couple of quarters, it seemed like there was at least a higher level of interest in larger scale corporate deals, given where valuations were the quarter or two.

Can you sort of give us an update on where your thought process is with that? And also, there's been at least a couple of decent-sized transactions in the Williston Basin.

And is that something you all looked at? And are there other opportunities like that still out there?.

Yes. I think just maybe addressing maybe some of the asset level deals that have occurred, I think overall, consolidation is healthy and certainly improves.

I think the competitive structure of our industry, it really gets the assets in the hands of the most efficient operators, which should ultimately result in more disciplined behavior, which I think raises all boats in the industry. Many of these deals have been very bespoke, very specific deals. I don't intend to comment on any of them specifically.

But certainly, given our size and presence across all 4 of the key basins, we're well aware of the deals or the transactions that are available in the marketplace. We're going to apply a very well-defined criteria for any consolidation, whether it's small, medium or large, and we're not going to budge off that criteria.

It's going to have to be something that is accretive to our financial returns, accretive to free cash flow. It certainly can do no harm to our balance sheet, and it's going to need to be something that has clear synergies and industrial logic and then also, ultimately, adds to our longer-term sustainability.

So we look at all those opportunities in the market. We have access to all those. But we are going to apply a very disciplined lens to look at all those opportunities regardless of the size..

Our next question is from Phillips Johnston with Capital One..

Maybe another follow-up on the 5-year maintenance scenario.

Just wanted to get a sense for what your next 12-month oil PDP decline rate is assumed to be entering this year? And how would you expect that natural decline rate to change over the 5-year period?.

Yes. I think, first of all, I would just say that within not only this year's business plan for 2021, but also our longer-term 5-year benchmark case, base decline is fully contemplated in all those. I mean I think -- I just want to be really clear that U.S.

shale decline rates aren't mutually exclusive with delivering strong financial outcomes and sustainable free cash flow, particularly when you have high-quality, very capital-efficient assets. So I would just say it's in there.

We do expect that those portfolio declines will moderate as we see a shift in mix where we have more of that base production and less of, say, that year 1 and year 2 decline that typically represents those wells that you're bringing on-stream. So there will be a moderation to that decline over time.

But again, all of that is fully baked in to not only our '21 plan, but the 5-year benchmark case as well..

Yes. Okay. Makes sense. And then in terms of the quarterly cadence of both production and CapEx in '21, I noticed you guys are guiding to about 33 wells to be turned in line in the Eagle Ford and Bakken in the first quarter, which is a little bit less than 20% of your full year plan of about 185 wells in those 2 areas.

I assume that's also contributing to the slightly down oil volumes in the first quarter versus the fourth quarter.

But for the rest of the year, would you expect sort of mild ratable growth from that first quarter low to sort of achieve the 172 full year average? Or is there some lumpiness there? And then just on the CapEx side, would you expect first quarter to be a little bit lower than the rest of the year due to that lower [TIL] count for Q1?.

Yes. You did point out that we are a little bit probably down in -- potentially in the first quarter. There -- it's really just a question of timing. Generally speaking, we're going to be quite ratable across the year. There's a little bit of a pause in the Bakken as we recognize the winter weather impacts there.

So that's not a time where we want to concentrate necessarily our completion activity. And so that -- you're seeing that effect. But from a CapEx as well as a wells to sales standpoint, it is going to be generally ratable. On the volume side, as Mike mentioned in the opening remarks, we do expect to see some impact from the winter weather.

But from a wealth to sales standpoint, that's not a driver of first quarter volumes. We had strong carry in performance, and we still expect to kind of be in that low end of our annual guidance range even with the winter weather conditions that persisted across our play. So notionally, yes, in first quarter, notionally, in that kind of 170 range.

And as Mike already stated, that winter impact is already fully baked into our full year guidance range..

We have our next question from Scott Gruber with Citigroup..

Thinking about your activity trend in the second half of last year, I believe you're largely focused on some of your best inventory. Obviously, the right thing to do when oil prices are low. Thinking about the Bakken and your program here, 60 to 80 [TILs] in '21.

What's the split between Marathon and Hector and Ajax and some color on when a greater mix of Hector and Ajax wells start to layer back in this year?.

Hey, Scott, it's Mike here. We're -- the split in '21 between Hector and Ajax is about 60% -- sorry, 60% Myrmidon and 40% in Hector. No plans for anything in Ajax this year. And then obviously, looking beyond '21, I would notionally expect Hector to play a more significant part as we progress in the out years..

Got you. And I have a question about the 5-year study as well, especially given the rigor behind the study. Really thinking about capital efficiency, which, as I think about, it's really the intersection of well productivity, the operational efficiency and how fast you drill and complete the wells, and then trends in D&C service rates.

How did you think about each of these items when you work through the study over the next 5 years? How did you guys incorporate the assumptions around well productivity trends, around operational efficiency and around the service rate trend over the 5 years?.

Hey, Scott, it's Mike here again. It's probably a lot in there, and you might need to help me out here as I get through this.

As we think about cost specifically, well costs, we are assuming some level of savings over that 5 year, albeit I think Pat mentioned, we are -- we did look at it from a risk bottoms-up perspective and maybe putting those cost savings into a little bit of perspective.

If you take the Eagle Ford and Bakken, for example, our pacesetter wells, so wells that we already have in the ground, we drilled and completed those wells for less than what we're assuming in the 5-year maintenance case. So on the capital side, we are assuming some improvement, but nothing that we haven't delivered on already.

From an inflation perspective, I think you may have asked that, we are assuming some modest inflation in that 5-year plan, which I think is reasonable. And then from a well productivity perspective, what I would say is well productivity over the 5-year period is pretty comparable to what we're seeing in 2020 and 2021.

Is there anything that I missed on the list?.

No, it's just something that we've thought about over time and it sounds like the operational efficiency improvement can offset the service rate inflation? Is that kind of broadly how you guys thought about it?.

I think that's a fair way to think about it..

Okay. Great. Yes, it's a complex question, so I'm just curious on how you guys talk through it. Appreciate the color..

Our next question is from Paul Cheng with Scotiabank..

A couple of questions. Actually, the first one is related to cost. One of your competitors have mentioned, they have seen some cost inflation in some small area in the Permian service. Just curious that have you guys seen cost inflation sort of spiking up in any part of your operation? That's the first question.

Secondly, that when we're looking at -- I don't know if I missed it.

Have you mentioned what is the winter impact in your first quarter and whether that you are fully returned to the normal operation at this point?.

Hey, Paul, it's Mike here again. I'll answer your second question first. I think Lee just touched on the Q1 winter impact. We anticipated it is obviously impacting it. I think the number that we're looking at is somewhere around 169, 170 for the quarter.

But then obviously, getting back up for the full year, still looking at that -- the guidance range that we've included in the deck. And then you had a question on....

Mike, actually, I know that you gave a guidance for the production in the first quarter.

Do you have a number you can share what is the actual impact from the winter storm? Is it down, say, 10,000 barrels per day, 20,000 barrel per day for you? Is there any number you can share?.

Hey, Paul, I would just say, no, we're still kind of in recovery mode in terms of getting the wells back online. And we would anticipate clearly having that period of downtime, but we'd also anticipate having an element of some plus production as we bring wells back online as well.

And so it's -- we're going to have to wait until we can kind of net most of those things out. So we're trying to provide you kind of our best view of that right now. So we don't have specific actuals because we haven't fully recovered all of our wells to see exactly how they will perform post shut-in..

And Paul, I'll take a run at your first question here. You were asking about inflation. What I'd say there, if we look at it from a macro perspective, capital activity has not returned to a level that we would expect to drive a substantial uptick in current costs. And it's capital activity that drives inflation.

So what I'd say there, so long as there's discipline in the E&P space, inflation feels very manageable. Specifically to Marathon, we do have our frac crews and 50% of our rig fleet secured through the middle of this year. We are seeing some inflationary pressure in the casing and shipping space.

But that's really due to non-E&P demand on raw material and [mill space], which we project that flatten out in the year. So I'd probably characterize it as we're seeing some mild inflation. But if there's discipline within the industry, we think that inflation is manageable..

And thank you. That is all the time we have for questions today. I will now turn the call over to CEO, Lee Tillman, for closing remarks..

Well, thank you for your interest in Marathon Oil. And I'd like to close by, again, thanking all of our dedicated employees and contractors for their commitment and their perseverance in these most challenging times. That concludes our call..

And thank you. Ladies and gentlemen, this concludes our conference. Thank you for participating. You may now disconnect..