馬拉松石油 (MRO) 2018 Q4 法說會逐字稿

Good morning, and welcome to the MRO Fourth Quarter 2018 Earnings Conference Call. My name is Brandon, and I'll be your operator for today. (Operator Instructions)

Please note this conference is being recorded, and I will now turn it over to Guy Baber. You may begin, sir.

Thank you, Brandon, and thanks all of you listening in today. Yesterday, after the close, we issued a press release and slide presentation that address our 2019 capital budget as well as our full year 2018 and fourth quarter 2018 results. Those documents as well as our quarterly investor packet 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; Mitch Little, Executive VP of Operations; and Pat Wagner, Executive VP of Corporate Development and Strategy.

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. 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. With that, I'll turn the call over to Lee, who'll provide his opening remarks before we open the call up for Q&A.

Thanks, Guy, and thank you to everyone joining us this morning. I'd like to take a little time upfront to share some thoughts on both our 2018 full year financial and operating results as well as our 2019 capital program. We don't believe it's a mystery as to what investors are looking for. It's pretty straightforward. Investors are looking for companies that have the right portfolio of assets; that have the right strategy, putting returns first, generating sustainable free cash flow and sharing that cash flow with investors; that have a strong balance sheet to weather potential volatility; and that have the capability to execute on their commitments consistently. We believe we screen well on these criteria, and our differentiated performance in 2018 stands as our proof point.

For our company, differentiated execution led the way in 2018 and underpins our confidence in 2019 delivery. Capital discipline has been the buzzword in the E&P industry throughout most of 2018 and certainly as we enter 2019. At Marathon, we have a very clear working definition of capital discipline, and it has been our touchstone as we have successfully transitioned to our differentiated multi-basin U.S. resource play model. It is our framework for success.

It begins by ensuring every dollar spent advances our returns at the enterprise level, while also delivering on a well-defined set of core strategic objectives. It means prioritizing sustainable free cash flow generation at conservative prices over growth for growth's sake. We have been very clear that production growth is simply an outcome of our disciplined capital allocation process, and given our commitment to returns and cash flow, we emphasize high-value oil growth to drive both high margins and capital efficiency. And with sustainable free cash flow, capital discipline for us is also a commitment to return capital back to shareholders through both our peer-competitive dividends and thoughtful share repurchases. Share repurchases will be tested to ensure alignment with our returns-first orientation and must be supported by sustainable free cash flow generation, not asset sale proceeds. And finally, capital discipline is about differentiated execution that continuously drives improvement in capital efficiency and enhances the economic value of our resource base.

For many, our definition of capital discipline remains aspirational, a goal that is always just over the horizon. At Marathon, it is a reality. It is how we run our business, and you need to only look at the many proof points from 2018. We set a $2.3 billion development capital budget at the beginning of 2018 and never wavered, ending the year as one of the very few E&Ps that never increased their capital spending budget. We didn't add activity as oil prices outperformed our plan, we stuck to our conviction when industry discipline broke down, and we successfully managed through an inflationary environment during the first half of the year through harnessing the benefits of our multi-basin portfolio.

Our capital budget is not a suggestion, it is a commitment. We got more for every single dollar of capital that we invested, we significantly outperformed on our key corporate financial metrics, cash return on invested capital and cash flow per debt-adjusted share. We meaningfully beat our initial oil production growth guidance through impressive capital efficiency gains across our portfolio, and we had great success in organically improving the quality of our inventory base through core extension efforts, especially in the Eagle Ford and Bakken. And when oil outperformed our $50 WTI planning basis, we prioritized free cash flow generation instead of activity acceleration and delivered $865 million of post-dividend organic-free cash flow, translating to an organic free cash flow yield of almost 7%. This free cash flow yield is well above the average for the broader market, let alone our E&P peer group.

And finally, we returned a significant amount of cash back to our shareholders. In addition to our peer-competitive $170 million annual dividend, we bought back $700 million in stock, funded entirely by organic free cash flow. In total, we returned over 25% of our operating cash flow back to shareholders, and we did all of this while further strengthening our balance sheet by increasing cash and cash equivalents by $900 million to end the year with $1.5 billion in the bank, maintaining a net debt-to-EBITDAX ratio among the lowest in our peer group. Our foundation for delivery has never been stronger.

As we turn our focus to 2019 and beyond, rest assured that our framework for success remains the same. Our 2-year outlook provides visibility on the metrics that matter most. It prioritizes returns, free cash flow and return of capital to shareholders. Production growth is an outcome, and we recognize production alone does not equate to profitability. It all starts with sustainable organic free cash flow in both 2019 and 2020 above $45 WTI. So $50 WTI remains our planning basis and a commodity price at which we generate meaningful free cash flow. Continuing to drive our enterprise breakeven point lower is essential in a commodity business.

Our forward outlook continues our multiyear rate of change improvement in our key enterprise performance metrics, cash return on invested capital and cash flow per debt-adjusted share, both of which were added to our executive compensation scorecard last year. Our focus on the powerful combination of dramatic portfolio transformation and the resulting concentrated allocation of capital to our highest-margin assets is driving this rate of change.

At $50 flat WTI and $60 flat WTI forward pricing, we will drive a 20% and 30% compound annual growth, respectively, to our cash return on invested capital over the 2017 to 2020 timeframe. Comparing 2017 directly to 2019, our underlying CROIC almost doubles on normalized pricing. That is the power of our portfolio transformation and focused capital allocation. Our 2-year view will generate sustainable free cash flow, and we won't need outsized oil prices to do it. More specifically, we will be organic free cash flow positive above $45 WTI in both 2019 and 2020 with significant leverage to even modest price support. At $50 flat WTI, we are forecasting cumulative 2019 to 2020 organic free cash flow generation of over $750 million. At $60 flat WTI, our cumulative organic free cash flow generation rises to over $2.2 billion or over 17% of our current market capitalization. Importantly, while our 2019 free cash flow is robust, our outlook only improves into 2020.

The takeaways from this 2-year view are compelling and highlight the following, our discipline, just as we proved in 2018, should oil prices outperform our planning basis, we will prioritize our ability to deliver free cash flow instead of chasing growth; our significant upside leverage to even modest oil price support; our sustainability as free cash flow momentum builds over this forecast period; and our compelling free cash flow yield relative to not only the E&P sector but to the broader market as well. And with this sustainability comes a commitment to continue to prioritize returning capital back to our shareholders, building upon our success on this front in 2018. And to underscore our commitment, we have introduced a new return of capital metric to our executive compensation scorecard, joining last year's addition of cash return and cash flow per debt-adjusted share.

Crucially, we will continue to fund incremental shareholder return through organic free cash flow generation, not through unsustainable means. Further, we will remain driven by returns. At our current market valuation, the disciplined repurchase of our own stock represents a good use of our capital offering very competitive returns.

Differentiated execution remains at the heart of our framework and ensures that we deliver on our commitments, drive capital efficiency improvements across our multi-basin portfolio and continue to enhance our resource base. And though our extensive portfolio transformation has yielded a high-quality and high-return resource base that obviates the need for any large-scale M&A, we have a comprehensive multipronged approach to continue to enhance it. First, we are organically upgrading the returns and productivity of our existing inventory through technical innovation, efficiency and cost reduction. We have had great success on this front, both the Eagle Ford and Bakken in 2018, extending the core of our inventory position, enhancing the productivity and returns of much of our remaining inventory in those plays. Not only does this elevate the value of these basins, it also has the net effect of extending our inventory life as we need fewer wells to deliver the same output.

Thus far, our efforts have primarily been focused on uplifting the quality of our existing inventory. Those efforts will continue, and we expect to drive further quality improvement going forward. However, our teams are equally leveraging our learnings and workflows to increase the quantity of our inventory. While all of the initiatives we are pursuing will not prove successful, and some will take more than 1 year to prove out, our teams are working hard on an organic opportunity set that represents hundreds of potential new gross company-operated locations in the Eagle Ford and Bakken alone in addition to opportunities across our full portfolio. These initiatives include acreage extension tests, the application of enhanced completions in new areas and optimized spacing trials.

Second, we continue to improve our resource base through small, accretive bolt-ons, lease sales and trades around our existing positions. We have had great success on this front in the Northern Delaware, where we've successfully increased our gross operated location count by around 20% since play entry.

Third, we continue to progress our resource play leasing and exploration program, or REx, the objective of which is to prove up additional resource with a focus on full cycle returns through low entry cost. We acquired approximately 260,000 net acres in the emerging Louisiana Austin Chalk at less than $850 per acre and are pursuing other opportunities, all more than funded in 2018 by disposition proceeds received earlier in the year.

Transitioning to the specifics of our 2019 program, I would first emphasize that the finer details of our plan are fully consistent with the core strategic objectives I have already outlined. Our $2.6 billion total capital budget is down from 2018 and is comprised of approximately $2.4 billion of development capital and $200 million of resource play leasing and exploration capital. And just to reiterate, our planning basis is $50 WTI but with organic free cash flow above $45 WTI post dividend. We anticipate total company oil production growth of 10% this year, powered by 12% oil growth in the U.S. on flat wells to sales. High-value oil growth will exceed BOE growth, consistent with our returns-first capital allocation framework.

Over 95% of our development capital is dedicated to our high-margin U.S. resource plays, with about 60% going to the Eagle Ford and Bakken and the remaining 40% going to Oklahoma and the Northern Delaware, generally consistent with our spending mix last year. In the Eagle Ford, we will continue to deliver compelling returns, meaningful free cash flow and industry-leading capital efficiency. We grew oil production by 7% in 2018 on fewer gross operated wells to sales. Our wells to sales are set to fall by another 10% in 2019 as we fully leverage the step change in well productivity improvements.

In the Bakken, with about 90% of our activity concentrated in Myrmidon and core Hector, we will deliver robust returns, free cash flow and oil growth while building upon the strong momentum we have established around our successful core extension tests and recent capital efficiency improvements. In Oklahoma, we will continue progressing infill development in the overpressured STACK Meramec and SCOOP Woodford, targeting competitive returns and predictable performance while also progressing secondary target delineation. In the Northern Delaware, we will strategically pace our investment with a keen focus on bottom line returns and protecting our leasehold. 2019 activity will be concentrated on the upper Wolfcamp in Malaga along with delineation of our acreage position across the attractive Red Hills area. Finally, REx spend is down materially and reflects a more ratable forward spending profile, supporting the progression of both Louisiana Austin Chalk as well as other emerging opportunities, all with a focus on full-cycle returns.

As I close out my comments, I would like to thank all of our dedicated employees and contractors who made 2018 a year of such differentiated execution for our company. Our future has never been brighter since becoming an independent E&P. And powered by our multi-basin portfolio and financial strength, we will build on our momentum for 2018 to continue executing on our framework for success, driving corporate returns higher, generating sustainable free cash flow, returning capital back to shareholders and delivering differentiated execution.

Thank you all for listening. And with that, I'll hand it back to the operator to begin the Q&A.

(Operator Instructions) And from JP Morgan, we have Arun Jayaram.

Good morning. Lee, I wanted to ask you about Slide 5 in the deck where you go through the organic free cash flow generation, $750 million at $50 oil for '19 and '20. That obviously is before REx spending. But how should investors think about the potential of Marathon to return some of this excess free cash flow back to shareholders? And again, I'm just thinking about the REx spending in terms of how you think about cash return.

Yes. Absolutely, Arun. Well, I think through our track record in 2018, we certainly showed that we could strike a balance between, obviously, funding the very important work of REx but also returning significant cash flow back to shareholders. I mean, as you look at the 2018 numbers, we were able to -- of the $865 million of organic free cash flow that we generated post dividend, we returned $700 million of that back in the form of share repurchase. So our view is that our track record speaks for itself. We want to always keep flexibility in our programs. But we are very committed to prioritizing the return of cash to shareholders, hence our strong focus on sustainable free cash flow generation at very conservative oil pricing.

Great. My second question relates to the Bakken, where, obviously, you've benefited from strong well productivity gains. I wanted to know, Lee, if you could maybe give us a little bit more details on the pretty meaningful reduction in completed well costs. And do you think that this level of completed well costs, is this a sustainable number on a go-forward basis? And again, this is on slide 13 in your deck.

Yes, absolutely. I'll maybe make a few comments and turn over to Mitch to get into the specifics. But when we initially came out with the highly successful test in the Ajax area, we did not address specifically the completed well cost that those were delivered for. And of course, as we disclosed our fourth quarter results, we gave not only the productivity from those wells but also the completed well costs, which averaged around $5 million. And I think it's that powerful combination -- and I think it reflects the fact that our team in the Bakken is not just working the productivity side of the equation but is also working the capital reduction side of the equation as well. And maybe with that, I'll let Mitch talk a little bit about some of the specifics around how they're doing that.

Sure. Arun, I think what's probably at the core of all of this and what's interesting to think about is discipline is not only important to our investors, but it's very impactful in creating the right behaviors on innovation across the company. And so when we attack capital efficiency, it's not just from the well productivity side, it's also from the denominator side, which is on cost. And we gave some good color throughout across all the basins on improvement and completion efficiency. We're seeing market improvement in drilling efficiency as measured by feet per day, but it goes beyond that into design simplification, partnering with the right contractors who have the same efficiency drive that we do, expanding of our vertical integration and self-sourcing of materials, optimization of the full treatment schedule. I mean, it's almost on every front. And so we have a number of wells -- we highlighted before Ajax wells, we have a number of wells that we've delivered for that same CWC. There are some variation by area. We would still characterize our Bakken CWCs today between $5 and $6 million, but we have a number across all areas in the $5 million range, and we're continuing to keep that focus on capital efficiency.

From Bank of America, we have Doug Leggate.

Good morning everybody and Lee, another tremendous quarter, so, congratulations. I wonder if I could just follow up on the last question with a quick question, I guess, around the structure of the southern -- the Bakken area, Ajax and Hector specifically. Is there a structural reason for those costs being lower? I'm thinking depth or rock quality or stimulation -- stimulated rock volume. I'm just kind of curious as to, are you treating those wells any differently because of different porosity and permeability or shallower depths? Just trying to understand how you can deliver such tremendous results with such low cost.

Yes. Sure, Doug. There are some minor differences across the area. And as we've talked about on many quarters in the past, we do have a very detailed and structured workflow that helps us tailor our completions to specific areas. That being said, there's not a lot of variability in what we're actually pumping across from Myrmidon down to Ajax and Hector. There is, I would call it, more modest variability. And as I mentioned in response to the previous question, we've delivered CWCs at that well cost in the Myrmidon area as well. So this is just a matter of continuously fine-tuning and focusing on all elements of capital efficiency. So the teams are fully charged up to continue to drive that benefit further. As we put on our slides, we were 24% down in completed well cost 4Q '18 compared to 4Q '17. That's a mix of wells across that entire position. So there's not a lot of variability. I would call it really modest variability from north to south across our position.

I would also add that a lot of the self-help that Mitch outlined around commercial structure, self-sourcing, that applies across the full position. That's not unique to a given area. So that tends to, if you will, lift all boats in terms of capital efficiency.

So just one -- probably a clarification real quick, Lee, if you don't mind. Mitch, what's the lateral length on these wells on average?

Average is just under 10,000 feet.

My follow-up just a real quick one, Lee, for you probably is, the free cash flow generation of your portfolio is clearly tremendous. I'm just wondering if you could give us some idea where the bias is between international and domestic, and I'll leave it there.

Yes. Well, I mean right now, both sides of the portfolio are obviously contributing to that free cash flow performance, Doug. As obviously as the U.S. basins grow in prominence, and we've talked about this quite a bit that the percent of our production mix sourced from the U.S. is growing over time. We still have very strong, though, contribution from our Integrated Gas asset in E.G. as well. But the Bakken, the Eagle Ford are very strong free cash flow generators as well. So really, multiple assets are contributing to that free cash flow positive performance in the out years.

And from BMO Capital Markets, we have Phillip Jungwirth.

Thanks, good morning. Going back to Slide 5, I mean you guys sent -- certainly sent a strong message on free cash flow over the next 2 years. And I'm sure you don't want to get pinned down on multiyear guidance but was just hoping to get a little color around activity assumptions underpinning the 2020 free cash flow outlook? And is this more maintenance level spend or can you deliver growth rate consistent with 2019 while still generating this amount of free cash?

Yes. I mean, again, we don't want to get out and talking specifics in the out-year 2020, Phil. But I what I would tell you is that the activity levels that you would see out across that time period probably reflect very modest changes in activity. These are not large step-change increases in any type of capital allocation out in 2020 to achieve this. Yes, and in fact, I would just add that the momentum in 2020 is such that we're actually enjoying more capital efficiency in 2020 than we do in 2019.

Okay. Great. And then I think I heard this right in the prepared remarks, but there seemed to be a change in messaging around adding locations in the Eagle Ford and Bakken versus just upgrading the quality. And was hoping you could expand upon some of the initiatives mentioned, and then the order of magnitude we should be thinking about in terms of years of inventory for each play.

Yes, I'll make a few comments and maybe let Mitch jump in with a few basin-specific things. But I think, first, you start with just the remarkable success that was demonstrated in the Bakken and the Eagle Ford. And even though, we spent a lot of time talking about quality uplift and improving the economic performance as we extended the core, we all recognized that the net effect of that was to actually increase inventory life. So it's -- you're essentially extending inventory life but doing it in a very capital-efficient manner. One of the best examples I could talk about would be the performance that we saw in the Ajax completions relative to the last time that we drilled and completed wells there. We saw a 3x uplift in productivity. So 1 well doing the work of 3. And so that's the type of multiplier effect that we saw not only in places like Hector and Ajax, but certainly even as we extended the core in Atascosa County in the Eagle Ford. I think it's a subtle shift in thinking, and I think it's a natural step for us to transition into continuing that quality work but also looking at ways to add physical sticks as well. And that's where a lot of the effort in 2019 will be focused is on that. And as I mentioned in my remarks, we see an opportunity set even just restricting it to Bakken and the Eagle Ford, that we're talking of hundreds of potential wells that could be added. And again, not all of those efforts might be successful. Some of those may take multiple years to actually prove. But we still see running room in terms of additional sticks. And I don't know, Mitch, if you want to add anything about some of the things that we're actually testing there.

Yes. Phil, I think Lee covered it pretty well. The things that I would add, as we've been on this journey improving the quality of our inventory, we've also been integrating state-of-the-art tools and workflows, and I think I talked about them on the last call where we're using some advanced seismic processing techniques and coupling that with a true 3D fracture modeling tool that integrates with reservoir simulation, which is to our -- best of our knowledge, only 1 or 2 of our peers have that same technical -- technology capability. So we're taking the learnings from all that we've done over the last couple of years, applying it then to optimize spacing tests, alternative development schemes, extending these enhanced completions out into further areas. We've had great success in uplifting the quality across most of Atascosa or all of Atascosa, in Eagle Ford down into Hector, a good-looking test in Ajax as well in the Bakken, but there are other areas further away from the traditional core that we'll continue pushing into. And as Lee said, we have identified just in those 2 assets hundreds of locations that we have the potential to add. And while I agree with Lee, our base expectation isn't necessarily all of them will work. I'm pretty optimistic based on our track record over the last couple of years.

From Simmons Energy, we have Ryan Todd.

Maybe a follow-up on the free cash flow generation and the use of cash questions from earlier. You've been pretty consistent in terms of returning cash to shareholders via the buyback so far. How should we -- should we think about that as generally the standard going forward? Or how do you think about the balance between buyback and eventual growth of the dividend?

Yes. I would say, today, our preferred vehicle remains share repurchase, and we believe that generates a strong return based on the valuation. But the pace and timing of that share repurchase is going to be governed by sustainable free cash flow. The same discipline you see in all elements of our business, you should expect to see in the way we approach share repurchases. And I think we demonstrated that quite clearly as we calibrated even last year's share repurchase program very closely to our visibility on sustainable free cash flow. I think for us, I think the fact that we have also incorporated that into our executive compensation structure is also quite notable. When we look with the comp committee each year at executive compensation, we really strive to improve in really 2 dimensions. The first of those dimensions is aligning executive comp with the strategic intent of the company. The second of those is aligning executive comp with the shareholder experience. In other words, if the shareholder wins, obviously, management should win. And I think in that context, we have continued to move forward. Last year, we incorporated cash returns as well as cash flow per debt-adjusted share. When you look at our stated strategic intent, those 2 made very good sense, and now we're integrating a third and complementary item which is looking at a return of cash, which for us will be a metric that looks at the combination of dividend and share repurchase relative to the amount of sustainable free cash flow that we're generating. And so we think that's very critically important to incent the correct behaviors within the leadership team to drive our strategic intent.

That's helpful, Lee. And maybe one follow-up on the -- in the Permian, what is -- what's driven the 20% increase in operated locations in the Delaware basin up to this point? And maybe, can you update us on your latest thoughts in terms of spacing and full section development?

Yes, I'll maybe take the first one and then let the spacing question flow over to Mitch. We've stated all along that we like the scale that we have in the Northern Delaware, but we would like to strengthen the contiguous nature of our operated position there. And we've been very content with working singles and doubles through small bolt-on acquisitions. The New Mexico lease sale was another example. We participated there with about $100 million of capital put to work there. And also looking at trades with other operators in the area. And again, all of those are being done with a mindset of being very surgical, very targeted with an intent of increasing our working interest, providing more exposure to extended lateral optionality as well as converting non-operated to operated positions. And so it's not simply adding acreage, it's being very specific and very selective about how and where we add that acreage. And so it's a combination really of all 3 of those factors, Ryan, that have resulted in that 20% uplift since we actually entered the play with the 2 large acquisitions. Maybe on the second question around spacing, maybe I'll let Mitch chime in on that one.

Absolutely. I think Lee made a couple of remarks on the focus of the near-term program in the Permian, and that's probably a good place to start, where about 2/3 of our activity will be targeting the upper Wolfcamp, which is seeing the most testing in the area and certainly, where we've had the majority of our activity since entry and is moving more towards the development mode. And we're typically testing in and around the base case assumptions that we put out in the releases when we made the acquisitions, testing above that in some cases but largely in line with the base case that we've put out there. The rest of the program is around the delineation efforts that are important for us across the position to optimize the longer-term development plan there. So we're testing different spacing alternatives there. The one that we highlighted in the materials was this lower Wolfcamp test, which was a test at 8 wells per section. If you refer back to our base case in the release, our base case was 3 wells per section. Our upside case was 6, and we've tested 8 here. We're pretty encouraged by the early-time performance. But the focus will remain for the near term on the upper Wolfcamp and then strategic delineation tests and spacing tests across the position to help us further optimize the long-term development plan.

From Goldman Sachs, we have Brian Singer.

A couple follow-ups with regards to some of the earlier questions. The first is on the management compensation metric on return of capital. Can you just talk a little bit more about how that's going to be adjudicated by the board specifically if it's on an absolute basis relative to the free cash flow point you made before or whether it's relative to peers? And how operating free cash flow would be a driver relative to free cash flow coming in from asset sales or use of balance sheet?

Yes. Happy to do so, Brian. It's -- obviously, this element is in the part -- portion of our scorecard that we call strategic objectives. In the case of this specific metric, it is going to be really measured as we look at both the delivery to that shareholder through dividends and share repurchases and looking at that in the context of the actual organic cash flow that we're generating. The board recognizes that we need flexibility within that. But that will be the measuring stick that they will use to assess how we are achieving against that metric. There today, we don't really -- because again of pricing and other things, we have not set a hard target there. And hence one of the reasons it sits in the strategic objectives because we don't want to lose that flexibility. But I think featuring it there sets the expectation that we continue the trend that I think we established very clearly in 2018, and I think the alignment with our strategic intent is pretty clear. But it would not be -- it would be measured internally, not relative to others.

Great. And then a couple of small follow-ups with regards to the delineation effort in the Eagle Ford and in the Northern Delaware. In the Eagle Ford, do you expect this year that your delineation efforts would net add more resource and/or inventory relative to what would come down as a result of drilling this year? And then in the Delaware, what is the timing of clarity that you would expect from the delineation efforts in the lower Wolfcamp?

So, if I start with your Eagle Ford question, I think it's important to recognize that the potential is hundreds of locations. We have dedicated funds and are advancing trials of those different concepts that I talked about. We'll be implementing or executing on those this year. In most cases, we'll want to see longer-term performance, and we'll want to see multiple trials to confirm the full magnitude of the change. So it's hard to put a fixed timescale on that. But I think our teams recognize hundreds of locations across those 2 most mature assets. We'll continue to focus on maintaining longevity in those assets and enhancing longevity where we can. On the Permian, as you're well aware, this is the most dense resource basin in the U.S. with multiple benches, up to 10 or 11 benches in some areas. And each of those intervals is going to advance at a slightly different scale, I would say. So again, it would be a different point in time for different intervals within that. Our focus remains on the upper Wolfcamp with about 2/3 of the program, but we'll be getting meaningful tests across multiple secondary objectives this year and then integrate that in and be able to reflect on how prominent that's going to fit into the 2020 and beyond program.

From Heikkinen Energy, we have David Heikkinen.

Thanks for the clarity on you board process. One question I have, though, is what factors did you review and actually not add over the last couple of years? Or how did you decide on these factors?

Yes. I think, David, we explore with the compensation committee every year, looking at various metrics across our quantitative and strategic scorecard. We believe that in our business that multiple financial metrics are required to really determine the health of the business. So when you look at our scorecard today, not only are you going to find cash return, cash flow per debt-adjusted share and now return of cash, but you're also going to find F&D cost, you're going to find unit margin. You're also going to find unit cash cost. So when you look collectively at our scorecard, we have almost 70% of our scorecard is embedded in financial metrics, the metrics that we think align best with our strategic intent. There are numerous financial metrics that we'd considered. There's, of course, a bunch of different ways to slice and dice cash return. We have looked at a lot of those. We landed on this one as one that we felt was something that could be calculated externally with ease and compared. And so we look at all those factors when we select the metrics because we are trying not only to reflect the strategic intent of the business but provide metrics that are transparent externally, as well and meaningful external as well.

That's helpful. The -- and just one perspective going to the North American Prospect Expo, the deal market was described as a clogged drain and definitely seems to be a buyer's market. Are returns for acquisitions getting any closer to the returns that you see for buybacks or for probably one appreciated development economics? But how do you think about the market and kind of the weakness in it on the buyer's side?

Yes. As we look at our core areas where our teams are generating such high levels of differentiated execution and capital efficiency, to the extent that there are small bolt-on opportunities there that offer high-quality inventory, not necessarily PDP production, we're always going to take a look at those. In terms of the returns those can generate, for high-quality assets, those are generally not your distressed assets. And typically, there has to be at least some synergy or incremental value that you bring to bear to make those competitive within the overall portfolio. We're not looking to invest in inventory necessarily that's 10 or 15 years out in time. It needs to be competitive today with the current portfolio, and that's a very high bar. And I think if we have 1 struggle, it's just that we do have a very high-quality, high-return inventory base. And so it takes a very unique and high-quality bolt-on to really compete for capital. And but again, with our financial flexibility, with our demonstrated performance in these basins, if we see those opportunities that fit within our existing footprint, we're going to take a hard look at that.

Is the characterization of a clogged drain or a buyer's market, how you the see things as well? Just curious.

I think that anytime you see a significant pricing volatility, and certainly volatility within a relatively low range, I think that creates some disconnect between buyers and sellers. I think that's just a natural thing that occurs. So yes, I would assume that probably some deals are not moving forward because of that.

From Citi, we have Bob Morris.

Thank you, and good morning everyone. Just on the -- little bit on the Permian inventory and how do you look to expand there. Obviously, you mentioned you've increased your gross operated inventory by 20% since entering the Permian. But given your prior comments at this stage, how do you view the opportunity to continue to add to that inventory by all the means that you previously described? Is there another 20% increase potential there in the inventory? Or have you pretty much exhausted all the easy things or low-hanging fruit in expanding that inventory in the Permian?

I don't think we would call any of them easy. Particularly, when you talk about trades and things like that, I think those are tough, right, because you have to have 2 parties come to kind of a value proposition, and that's always tough. I think there is still a tremendous amount of running room left in places like Northern Delaware as the operators continue to find win-win situations where they can swap out acreage to the benefit of both. I think that's -- now, is it going to happen in very large chunks? Probably not. It's going to be again the singles and the doubles. But if you're consistent with that, and you work that over time just as we've shown, you can make a meaningful impact on your inventory. So without quantifying it, I absolutely feel that there is more running room there, whether it be greenfield lease sales either state or federal from the small acquisition standpoint and certainly, on the trade standpoint, I think all 3 of those are still fully in play.

Okay, great. And then my second question, Mitch, just looking at the 3R SCOOP Woodford infill that you disclosed here this quarter, you had a pretty good rate on those 8 wells. Are all 8 wells targeting a single zone in the Woodford? And as a result, you had a prior well there so there were 7 infill. Did you see any parent-child impact or degradation on those infill wells that you drilled there?

Sure. We do have a pretty uniform landing zone in that area. And so in answering your first question, they are lined up pretty consistently in the vertical plane. It's awful early days there to look at any parent-child impacts. What I would say is, we're very pleased with the results, both in terms of the returns that they're generating and in terms of the predictability that you see as we plotted against our most recent Woodford infill down in SCOOP. And so we'll need a little bit more time to answer the second question but certainly, impressed with what we're seeing, and as you can tell, kind of still in the late stages of clean up on those wells also. So we'll come back to you on that a little bit later.

Sure. Those are good results. I'm just wondering how much of that increase down there in the Woodford might be amenable to 8 wells per section and how you view that in your inventory?

Yes. I think we're -- I think the way I would, kind of, summarize it, Bob, is that we're very encouraged by the performance and the predictability that we're generating in the SCOOP Woodford, whether you look at the Lightner pad that we previously talked about, which was a 4-well, but an 8-well per section equivalent as well. I think that's what we really challenged that team with was ensuring that we are generating competitive returns and also creating predictable platform down in the SCOOP Woodford that really to us feels more like development drilling than certainly delineation drilling.

That's great. Congrats on the nice results this quarter, gentlemen.

From Barclays, we have Jeanine Wai.

Hi good morning everyone. Following up on Doug's earlier question on free cash flow by asset, in terms of advancing the U.S. resource plays from appraisal to development, you have that nice Slide 8. And it looks like the Delaware and Oklahoma, they aren't free cash flow generative yet this year like the Bakken and the Eagle Ford. Just wondering if I have that right? And if I do have that right, when do you anticipate that these 2 assets will turn the corner in free cash flow? Or what oil price do you think they would be at least cash flow neutral this year?

Yes. I think as -- one of the beauties, I think, of the multi-basin model, Jeanine, is that we do have assets that span the full development cycle. And that allows us, as we do our multi-basin optimization, to flex those assets as we need between growth and free cash flow generation or some combination of both. There is little doubt that Bakken and Eagle Ford across the range of pricing sensitivities that we've addressed in this pack are free cash flow positive and generating very strong free cash flow. Oklahoma, although, we still show that as an early development asset, as we -- as you kind of hear the conversation today, there's little doubt that SCOOP Woodford and overpressured STACK Meramec are starting to move more towards the green area of this chart. And to the extent that, that becomes more the preponderant of the well mix there, then Oklahoma will clearly start moving toward being at a minimum self-funding and ultimately, cash flow generation as well. Northern Delaware is a little bit further removed from that. I mean, we're still in the very early days there. We're really in preparatory mode. We're still --the only basin where we still have some leasehold obligations let -- yet to complete. The team is definitely on the right trajectory. You're going to see very strong growth there but on a relatively small base and it's going to be a question of letting the economies of scale catch up there in the Permian, and we plan to get it to free cash flow positive as soon as we can. But again, I would just stress that for us, it's looking collectively across the portfolio because this is the advantage of the multi-basin model. We can achieve what we need to achieve strategically in a place like Northern Delaware while also relying on our strong capital-efficient assets like the Bakken and the Eagle Ford to deliver that free cash flow, which then puts us in the position to be talking about breakeven enterprise numbers of down around $45 a barrel.

Okay, great. That's really helpful. I guess just sticking to that same slide, but switching to growth, oil growth. We noticed that 2 out of your 4 U.S. resource plays are growing oil, and we suspect that the Eagle Ford has the potential to outperform and will probably grow oil this year, given how good results are. So essentially, you have 3 out of 4 of your U.S. resource plays growing. Exception is Oklahoma, which you just talked about, you're spending about 20% of your CapEx there, and I think you probably just answered this question. But can you just talk about longer term, maybe how you're thinking about Oklahoma in your portfolio? You're spending money there in the area that's not growing, at least not growing now, but you said it's an early development. It's not free cash flow positive, and you definitely have other opportunities in your portfolio and whereas before if anybody thought that you didn't have enough inventory and that's why you needed this fourth area. Now you're talking about having hundreds of extra locations in your other assets. So just wondering kind of maybe longer, medium term how you're thinking about it?

Yes. I think that as we look at capital allocation, all 4 of our basins are competing strongly on an economic return basis. So I mean, when you start at the top of the house with an objective of driving enterprise returns, your whole portfolio has to be contributing to that. And we feel that Oklahoma is in a unique position in the sense that it's such a large and diverse acreage position. We're going to have elements of Oklahoma moving into that full-field development mode like SCOOP Woodford, like overpressured STACK Meramec, a bit ahead of some of the secondary zones. And we are fine with that. But there's no doubt in our mind that we have a strong inventory that if needed within our multi-basin model Oklahoma can be part of that growth equation. It's just as we optimize today, we're not having to pull upon Oklahoma in that manner.

From SunTrust, we have Neal Dingmann.

Lee, could you or Mitch speak to the upcoming drilling cadence, potentially, you see here this year and going to the next for the Delaware position? And again why I'm asking, as you sort of bolt on, obviously, the southern acreage maybe been a bit more prolific. I'm just curious how your sort of near-term plans to incorporate through this year through that deposition?

Sure, Neal. We talked about the intentional focus of our Northern Delaware program being strategically pacing development while accomplishing some of our delineation objectives. And so we would expect pretty ratable and pretty flat activity across the Northern Delaware throughout 2019 and at a level that's more or less on par with 2018.

Okay. Very good. And then one follow-up if I could. Just you guys -- and the SCOOP STACK, especially down looking at your SCOOP program, you continue to have just excellent after excellent well particularly not just on the rate but the GOR. Could you maybe speak to your GOR expectations particularly down in the SCOOP? Are they sort of on point of now what you're expecting down there? I mean, they certainly appear to be better than what some others have -- maybe have been showing. So any comments you could have down there on your SCOOP program.

Yes, Neal, I think would just say broadly, with all of these plays, there is some sort of compositional gradient across the structure. And so as we move around the Woodford, we will see some variability but we've seen pretty good consistency localized with the results that we've published recently. But there will certainly be some variability over time or over the geography and geology there.

I think importantly though for us, Neal, it's that we want to be predictable on that variability. I mean, we want to know as we go into these pads, the deliverability, what they're going to look like, what the spacing needs to be, et cetera, and that's why we are certainly focusing the '19 program into areas like the SCOOP Woodford and the overpressured STACK Meramec because we feel that the team now has a workflow to deliver, not only great results and great returns, but do them in a predictable fashion. I mean, we may see different spacing. We may see different completion designs. We may see some variability in GOR, but we are seeing that, knowing that, going into the development.

From Wells Fargo, we have Nitin Kumar.

Just in terms of Slide 5, one variable I wanted to understand was what are the service cost inflation assumptions you're baking in? And what are you seeing on the spot market right now?

Yes. Just in general, on service cost, particularly as we look ahead to this year, I'd say, in aggregate, as we look across all service lines, we're flat to a little bit of deflation in 2019. That's kind of where we stand, and that's pretty consistent with the trends that we saw at the end of last year and certainly what we've seen at the beginning of this year, particularly as you think about, more or less, an inflationary assumption that matches up with that $50 flat view, that's going to be a relatively flat kind of assumption on inflation as well that complements that.

And what about the $60 case? Is there any inflation baked into $2.2 billion?

Yes. Well, certainly as the dependency there is really one more of activity levels not only for us but our across in the industry. And certainly as we move more into a $60 world, we would expect an uptick in demand for services, et cetera. We still believe that we have self-help activities that will, generally speaking, help us offset that. So I think within this $50 to $60 band, we feel pretty comfortable that we understand that inflation is going to be at relatively low level. And that in the case of the $60, maybe net of some self-help activities that we have to implement ourselves.

And the other question I just had, I think you guys have done a great job of laying out some of the initiatives to organically add resource. But a company the size of Marathon, your CapEx is still focused on, what I would term, your legacy assets between the Bakken and Eagle Ford and kudos to your team of how much better you have made those assets. What is a reasonable inventory life that you look for across the portfolio? What are your expectations? Just to kind of keep this kind of program and these kind of returns, how long do you think you should have?

Well, I mean, it's -- inventory is something that we think about and work on each and every day. We'll never be satisfied on that front from a quality as well as a quantity standpoint. Just so, on your first question, I think a 60-40 split between more mature assets and our developing assets to us makes perfect sense. It's very consistent with last year. If you -- again you're going to be guided by enterprise returns and organic free cash flow generation, you have to be able to strike the right balance between that mix of assets, and we feel very good. We're still progressing our less mature assets. We're still delineating them. In many cases, we're still growing them in the case of Northern Delaware. When we think about inventory life, we feel very good that the work that we've done, in both Bakken and Eagle Ford, continue to push that inventory life forward in time. We -- with just the work that we've done last year, combined -- we'd say we've got about a decade of inventory across both Bakken and Eagle Ford combined at, kind of, 2019 consumption rates. And obviously, in the other 2 assets, we've got multiple decades of inventory there at current consumption rates. So we feel very good about the work that we're doing not only to develop our inventory but to continue to replace that inventory in a very structured and methodical sort of way.

Thank you, Lee, great quarter.

From Tuohy Brothers, we have Jeffrey Campbell.

First of all, congratulations on the quarter, and thanks for getting me in. Lee, it looks like international is shifting into, what I would call, managed decline, and I understand that it's a free cash generating asset. But I was wondering what metric or metrics do you monitor to decide if or when international might be more valuable to someone else than Marathon?

Yes. And I guess on that point, Jeff, I would say first of all, all international is not created equal. I think we've been very explicit in talking about the foundational elements of our portfolio, four U.S. resource plays and E.G. And if I just focus on E.G. for a moment, it is a long-life, low-decline asset with essentially no capital requirements going forward. So it's a free cash flow generator for us. It is -- really, there's 2 value propositions in E.G. There is the Alba Field itself, and then there is the value of that infrastructure sitting in a very advantaged position in West Africa, an LNG plant, a Methanol plant as well as a gas plant, storage and, of course, an offloading berth. Our view is, that is going to be a natural aggregation point of gas going forward. So we still see a very strong value proposition that exists in E.G. despite the fact that we are in that kind of 8% to 10% kind of decline from an Alba Field perspective. We think there -- again, there's really 2 embedded value propositions there: one, our equity barrels that we can generate from Alba; and the other is taking advantage of this world-class infrastructure that we have on the ground there.

Yes. No. That makes a lot of sense. Thanks for that answer. And the other question I wanted to ask was just what's the goal for the Eagle Ford EOR program that you're testing? I was wondering could this become a meaningful tool in the overall management of the Eagle Ford decline rate at some point or is there some other goal in mind?

Happy to provide a little bit of extra color there, Jeff. We, in the past, had done a single-well trial and then a 4-well trial where we're looking at the incremental uplift from that. This next phase of the project, which we're implementing this year, is a multi-pad deployment of the same techniques and technology. It'll provide us on the clarity over the scale that we need to understand what the degree of uplift is. There is certainly large potential in terms of incremental recovery. Simulation studies that we've done and that others have done show an uplift in excess of 30% to the EUR. And so that -- this would be the proof point for us on that throughout 2019 and into 2020, and then we'll be able to see where to take the program from there. But this is a program at scale across 4 pads, like I said.

Yes and, Jeff, if I could maybe just add to it, I think that we have high confidence in the physics of enhanced recovery via miscible flooding in unconventional reservoirs. Really it's now sorting out really the economics and scale-up that and then assessing how that competes for capital allocation within the portfolio. But when you look at the oil in place and that we're leaving behind in these reservoirs, to think that we're not going to chase that with innovation and technology, I think, just doesn't make sense to us. So it's that next phase for a lot of these a bit more mature areas is, really, how do we leverage some of those same techniques that have proven successful in more conventional reservoirs to get our recovery factors up much higher. I mean, just a few percentage points movement in recovery factor across these large fields is a difference maker.

And we'll now turn it back to Lee Tillman for closing remarks.

Well, I want to thank everyone for your interest in Marathon Oil, and we look forward to delivering on our commitments for our shareholders again in 2019. Thank you very much.

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