Marathon Oil Corp

NYSE:MRO

Earnings Call Transcript 2019-Q3

[Operator]

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

[Guy Baber, Vice President of Investor Relations]

Thank you, Brandon. Thank you to everyone for joining us this morning on the call. 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; 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 to the risk factors described in our SEC filings.

With that, I'll turn the call over to Lee, who'll provide his opening remarks.

We will then open the call up to Q&A.

[Lee Tillman, Chairman, President & Chief Executive Officer]

Thanks, Guy. And thank you to everyone joining us this morning. Third quarter once again featured exceptional execution across all aspects of our business. This consistent differentiated execution against a transparent framework for capital discipline is driving compelling bottom line financial outcomes for our shareholders that compete not only against our independent E&P peers, but more importantly, against the broader market as well.

We continue to consistently and comprehensively deliver against our framework for success, which defines our brand of capital discipline. We are driving our corporate returns higher, generating sustainable free cash flow at conservative pricing, prioritizing return of capital to shareholders through dividends and share repurchases and improving our capital efficiency, cost structure and resource base, including the just announced addition of over 1,000 operated locations, all through differentiated execution.

Our strong operational and financial performance continues to be powered by a transformed multi-basin portfolio and a top-tier balance sheet, the foundations for our continued success.

Turning to third quarter highlights. I will start my commentary by addressing the strong financial outcomes we have now delivered for multiple quarters that serve as proof points for our business strategy and that define our investment case. It starts with our returns-first orientation.

On a year-to-date basis, our annualized cash return on invested capital is 20%, consistent with the prior year, despite a 12% decline in WTI prices and meaningful weakness in NGL and gas pricing. This underlying corporate returns improvement is an outcome of our success across multiple dimensions: portfolio management, concentrated capital allocation, more efficient operations, high-margin oil growth, lower cash costs and well cost reductions. Additionally, it is this returns-first mindset that drives our comprehensive framework for ongoing resource capture and enhancement. More on that in just a moment.

Second is our commitment to sustainable free cash flow generation at conservative pricing. This marks our seventh consecutive quarter of post-dividend organic free cash flow generation and our now well-established track record on this front remains unique in the sector.

We generated $81 million of post-dividend organic free cash flow during 3Q bringing our year-to-date organic free cash flow to approximately $300 million. Since the beginning of 2018, our cumulative post-dividend organic free cash flow totals over $1.1 billion. This translates to an annualized organic free cash flow yield of approximately 6% on a year-to-date basis and 9% since 2018, leading our E&P peer group and competitive with the S&P 500.

Third, we continue to return significant capital back to our shareholders through both dividend and share repurchases. Year-to-date, we have now repurchased $300 million of our own shares, funded entirely with post-dividend organic free cash flow.

Since the beginning of 2018, cumulative repurchases now total $1 billion, representing approximately 7% of our outstanding share count and again funded entirely by post-dividend organic free cash flow. And over the same time period, we have returned 25% of our cash flow from operations back to shareholders through our dividend and share repurchases.

We have a $1.45 billion repurchase authorization outstanding and continue to believe that a balanced approach to share repurchases governed by organic free cash flow offers a great return to our shareholders. Our commitment to shareholder-friendly actions is further underscored by a return of capital metric within our executive compensation scorecard.

Finally, differentiated execution is the engine that powers delivery against all of our commitments. And third quarter was again a quarter long on execution proof points. High margin U.S. oil production exceeded the top end of our guidance and we are now guiding to full year U.S. oil growth of 13% versus 12% previously.

Development CapEx during third quarter was in line with expectations and our annual $2.4 billion development capital budget remains unchanged. Completed well costs per lateral foot remain on a declining trend in all basins. Unit production costs in both the U.S. and International segments are at record lows, since we became an independent E&P in 2011. And success across all elements of our returns-focused resource capture and enhancement framework is delivering on its promise adding about three years of drilling inventory.

This success coupled with our extensive portfolio transformation and differentiated position in four of the best U.S. resource plays, means large-scale M&A is not a consideration.

Lastly we continue to take proactive steps to enhance our already peer-leading balance sheet. We executed three separate transactions that are leverage-neutral, extend maturities and generate cash savings. Importantly, we are investment-grade at all three primary ratings agencies.

Briefly touching on the asset-specific third quarter operational highlights, that are underpinning our enterprise financial success. In the Eagle Ford, we continue to deliver compelling financial returns and meaningful free cash flow. During third quarter, we achieved a new record for oil productivity as measured on an average IP30 basis an impressive accomplishment after eight years of operating in the play as our team continues to harness learnings from our 1700-plus horizontal completions in the Eagle Ford.

Beyond another productivity record with our focus on all drivers of capital efficiency we are making great progress in reducing well costs with third quarter completed well costs per lateral foot 10% below the 2018 average.

Further, we continue to organically add and upgrade the economic quality of our inventory most notably through a successful redevelopment test in core Karnes County taking advantage of understimulated our early generation completion designs.

In the Bakken, we continue to build on our hard-earned reputation as a best-in-basin operator. Capital efficiency continues to impress with our average completed well costs down to just $4.9 million during third quarter a 20% reduction relative to 2018. We also are seeing encouraging early results from another South Hector core extension test, marked by strong initial oil rates and a basin-leading average completed well cost of only $4.5 million.

Extended production data continues to validate the economics of 2018 delineation tests in both South Hector and Ajax with average well payouts of about 10 months on actual costs and pricing. In Oklahoma, we have reduced our activity down to four rigs as part of a concentrated program in the more oily and more economically competitive areas of the play as we protect our returns in a challenged gas and NGL pricing environment and maintain our focus on free cash flow generation.

In the over-pressured STACK we continue to deliver consistently strong and predictable performance along with some of the lowest completed well costs in the play. In the oily SCOOP Springer early productivity from our first three operated wells this year is, outperforming type curve expectations affirming the confidence we have in the additional 9 Springer wells, we will bring to sales during fourth quarter.

Turning to Northern Delaware. We continue to protect our leasehold, delineate our position and improve our margins all while driving capital efficiency improvement particularly in the Upper Wolfcamp and our Malaga area, where third quarter delivered a 35% increase in well productivity coupled with a 20% reduction in well costs relative to 2018.

Looking ahead fourth quarter activity will shift to include more delineation work in the attractive Red Hills area of our footprint. Internationally, we closed on the sale of our U.K. asset during third quarter simplifying our international portfolio to our free cash flow generating integrated business in EG.

Our integrated EG asset delivered approximately $100 million of EBITDAX during third quarter with unit production costs of less than $2 per BOE. The third-party Alen backfill gas project remains on schedule with first gas expected in the first half of 2021.

We believe there is inherent strength in a portfolio of quality assets that span the development cycle from exploration through the full field development and EOR. We have previously shared our comprehensive framework for resource capture and inventory replacement and this quarter we are providing aggregate results that demonstrate the success and impact of this approach.

This framework is designed to continue improving an already robust resource base through a sustainable multifaceted effort, all fully consistent with our returns-first orientation. Importantly we are generating success across all three elements of this strategy: organic enhancement resource play exploration or REx and the bolt-on acquisitions and trades.

The combined success the result of disciplined capital allocation and a constancy of purpose has been transformative resulting in the addition of over 1000 company-operated locations to our inventory equivalent to roughly three years of company-wide drilling.

Complementary to these additional locations. the economic returns of hundreds of existing Eagle Ford and Bakken drilling locations have been significantly upgraded. Given the importance, I would like to spend a few moments on each of the three elements of this framework.

Our success starts with what we call organic enhancement or core extension through productivity uplift, enhanced recovery, cost reduction and efficiency improvement. In the Bakken and Eagle Ford alone organic enhancement has resulted in the addition of over 500 new drilling locations to our plan of development since the beginning of 2018, more than replacing the last two years of inventory consumption for both assets.

At the same time we have meaningfully enhanced the economic returns of nearly every remaining drillable location in the Bakken and Eagle Ford with hundreds of existing locations upgraded to top tier. As a result, the vast majority of our approximate decade of inventory in both plays offers compelling economics. And while, the bulk of both our future Bakken and Eagle Ford inventory has been meaningfully upgraded on an economic basis, we continue to believe

And while the bulk of both our future Bakken and Eagle Ford inventory has been meaningfully upgraded on an economic basis, we continue to believe there is more resource to unlock, through additional core extension in the Bakken, through redevelopment opportunities in the Eagle Ford and even through enhanced oil recovery with our Phase 2 EOR pilot in the Eagle Ford demonstrating encouraging early results.

Additionally, our organic enhancement workflows, the product of years of disciplined work are fully transferable to our less mature assets in Oklahoma and Northern Delaware, another example of the power of our high-performing multi-basin model.

The second element of our resource capture enhancement framework is our resource play exploration program or Rex, the objective of which is to drive outsized full cycle returns through low-entry costs, high-quality exploration at scale. We are pleased to announce we are now advancing exploration and appraisal activity in two oil plays of scale, including a new Texas Delaware oil play with potential for over 400 extended lateral locations.

This new oil play spans over 60,000 net acres of contiguous oily leasehold perspective for both Woodford and Meramec oil targets. The play exhibits outstanding reservoir characteristics with the Woodford over 350 feet thick, more than 700 feet of separation between the Woodford and Meramec intervals and two excellent source rocks.

After securing our initial acreage position in 2018, we have since drilled and completed two exploration tests this year. Early results from these first two Woodford exploration wells are robust, demonstrating all the attributes we were hoping to prove in the play: strong oil deliverability, low water-oil ratios and shallow decline profiles.

We kept this promising early exploration well performance very tight, which allowed our team to move swiftly and surgically to fully capture what we had identified as the sweet spot of the play through targeted acquisitions that we expect to close in the fourth quarter.

With our focus on full cycle returns, we established our position at a low entry cost of less than $2400 per acre. We expect to deploy a full rig line for appraisal and delineation in 2020 as we continue to progress our understanding of this exciting new opportunity.

Separately in the Louisiana Austin Chalk, we continue to advance our exploration program. We welcome Equinor as a new 25% non-operating working interest partner in the play. On a cash basis, our partnership helps fund the incremental REx acquisition spending during fourth quarter related to coring up our new Texas Delaware oil play.

Just as a reminder, our Louisiana acreage is focused in what we characterize as the western fairway of the play in the over-pressured volatile oil and condensate phase windows. Our core position has largely never been drilled. And in fact, a material portion had never been leased for oil and gas operations and is on trend with historic Austin Chalk wells that have delivered prolific cumulative oil production even though developed by short laterals with no modern stimulation. Results from our first Austin Chalk exploration well are expected early next year with additional activity planned for 2020.

The third and final element of our resource capture and enhancement framework includes bolt-on acquisitions and trades to further bolster existing core positions. To that end, we are pleased to announce an Eagle Ford bolt-on that satisfies all of our key criteria: contiguous, largely undeveloped with inventory upside, industrial logic with meaningful synergies and accretive financial return.

This acquisition includes approximately 18,000 contiguous net acres adjacent to our existing Northeast Eagle Ford leasehold in Lavaca County. While largely undeveloped the asset comes with cash flow from existing production as well as valuable midstream assets that are synergistic with our existing acreage. We expect to close on this transaction by the end of January.

The acquisition effectively cores up a high-return, 70-well development area with upside potential that has demonstrated strong well performance from modern completions. With a cash transaction price of $185 million and our demonstrated execution capability in the Eagle Ford, we are confident in our ability to drive a strong, full cycle return from this opportunity.

To summarize, this level of comprehensive delivery across all three elements of our framework requires a returns focus, a constancy of focus, financial commitment, differentiated execution, technical excellence and top industry talent, the same factors that make this approach sustainable into the future.

To close out my prepared remarks, I will provide a high-level preview of our 2020 plan, which remains a work in progress that will be shared in final form next February. Rest assured, our framework for success will not change. We will put corporate returns first. We will build on our track record of sustainable free cash flow at conservative pricing. We will prioritize return of capital to shareholders through repurchases and dividends and we will maintain our focus on differentiated execution across all aspects of our business.

Our focus as a company into 2020 is less E&P and more S&P. For almost two years now, we have delivered financial outcomes, corporate returns, free cash flow and organically funded return of capital that few E&Ps in our peer space have matched. And while we will continue to work hard to retain and build upon our competitive advantage versus direct E&P peers, we are just as focused on effectively competing with the broader market on a financial basis and doing so in a volatile commodity price environment.

To this end, our 2020 budget planning basis will remain at $50 per barrel WTI, although our enterprise free cash flow breakeven will be below that level despite the headwinds of NGL and gas pricing. Total and development capital spending will be down year-over-year in 2020. And as a result our U.S. oil growth is expected to moderate from the double-digit growth levels that have characterized the previous two years.

We will drive sustainable broad market competitive growth on both an annual and exit-to-exit basis in 2020 as well as into 2021 with the final growth level simply an outcome of our rigorous and disciplined capital allocation process that prioritizes corporate returns and free cash flow generation. The optimization and shape of the production profile is critically important to assure sustainability across both 2020 and 2021. And as such, we expect average-to-average and exit-to-exit growth rates to be comparable.

Our fourth quarter U.S. production guidance reflects our intentional transition to this more moderate growth trajectory that further enhances our free cash flow capacity in both 2020 and 2021. While our wells to sales will decline in the fourth quarter fully consistent with our initial plan, which always had 4Q marking the low point on quarterly wells to sales, we are running above the high end of the guidance range for wells to sales for the full year, have strong exit-to-exit U.S. oil growth and just raised our 2019 full year U.S. oil growth guidance by 100 basis points.

We are confident in the operational momentum and capital efficiency we are carrying into 2020, and most importantly, in our ability to deliver on all elements of our framework for success.

More specifically, relative to the U.S. resource play capital allocation split that has characterized our development program for the last couple of years approximately 60% to the Eagle Ford and Bakken and about 40% to Oklahoma and Northern Delaware, we will allocate a greater share of our development capital to our highest return assets the Eagle Ford and Bakken. This will drive oil production growth for both assets in 2020 supported by the tremendous resource base enhancement success we have realized in both plays that has only further enhanced capital allocation optionality across our multi-basin portfolio.

Finally, with a focus on establishing line of sight to outsized full cycle returns our REx program will transition from one heavily weighted toward acreage capture to one more focused on exploration, appraisal and delineation drilling in our new Texas Delaware oil play and in the Louisiana, Austin Chalk.

In summary, we are proud of the results we have delivered and we are excited about our outlook. While we are frustrated by market volatility and by our sector's equity performance, we believe in our strategy and our framework for success. Within that context, we will remain focused on what we control, which is our execution and the consistent delivery of compelling bottom line financial and operational outcomes quarter-after-quarter. In time, it is this superior financial performance that will ultimately be rewarded by the market.

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

[Operator]

Thank you. We will now begin the question-and-answer session [Operator Instructions] And from JPMorgan, we have Arun Jayaram. Please go ahead.

[Arun Jayaram, JPMorgan]

Yeah. Good morning, Lee. I wanted to maybe clarify…

[Lee Tillman, Chairman, President & Chief Executive Officer]

Good morning.

[Arun Jayaram, JPMorgan]

Yeah. Good morning. I wanted to see if you could maybe elaborate on your commentary regarding 2020 as well as the outlook comments you made on 2021. Is it -- did I understand this correctly that you anticipate MRO to deliver year-over-year U.S. oil growth in both years as well as on an exit-rate basis for both years? And does that contemplate lower spending than the $2.4 billion development CapEx budget that you had this year?

[Lee Tillman, Chairman, President & Chief Executive Officer]

Yes. On your first part, Arun, absolutely, you've interpreted it correctly. We think it's -- first of all, it's vitally important that your starting point is from a position of driving returns and sustainable free cash flow generation. And to that end, we will optimize our production profile as an output of that. And we believe, it's very important from a sustainability standpoint to ensure that that profile holds true for not only average-to-average growth, but also for exit-to-exit growth particularly when you look across a kind of a multi-year time line.

[Arun Jayaram, JPMorgan]

Great. And just wanted to -- my follow-up is regarding how should we think about REx spending in 2020 and 2021, as you transition more from a leasehold capture mode into testing the concepts. And I was also wondering if you can maybe elaborate on the level of infrastructure that is in the Texas Delaware oil play that you highlighted last night?

[Lee Tillman, Chairman, President & Chief Executive Officer]

Okay. Great. I'll take the -- maybe the REx spend question and maybe let Pat comment a little bit about the new Texas Delaware oil play including the infrastructure. On your first question, Arun, around the REx spin we do anticipate spend in 2020 and 2021 to be consistent with the kind of longer-term run rate guidance that we have provided in the past, which is the nominal $200 million mark.

We believe that we can continue even with this transition to more of an appraisal and exploration drilling program to live within that type of budget. And maybe with that I'll let Pat make a few comments about the new Texas Delaware oil play.

[Pat Wagner]

Sure. Good morning Arun. Just there is existing shallow production and ongoing development on these leases that is above the Woodford and the Meramec. In fact we have our gas production from these two wells already on pipe and we'll have all of our oil production on pipe by the end of the year. These are very large leases with favorable surface ownership and we don't anticipate any problems with development plenty of infrastructure. I'd also say we're only 20 miles from the Wink terminal, so we're very close to the markets and we feel really good about this.

[Arun Jayaram, JPMorgan]

Great. And is the rig line that you anticipate Pat in the Texas Delaware oil play, is that going to be within REx or within the broader budget?

[Pat Wagner]

It will be within REx.

[Lee Tillman, Chairman, President & Chief Executive Officer]

Yeah. I would say Arun given the nature of the type of drilling, bear in mind that even though we have two very encouraging wells, one of them has about 100 days of production, the other about 150 days of production. We're still in the very early phases. And this is a very large acreage position, which is completely undeveloped. So we really still are in an exploration and appraisal mode even as we go into 2020. But we do have very good confidence though that we are seeing in these two wells the types of results that we were expecting.

[Arun Jayaram, JPMorgan]

Great. Thanks a lot.

[Lee Tillman, Chairman, President & Chief Executive Officer]

Thank you, Arun.

[Operator]

[Operator Instructions] And with that from RBC Capital Markets, we have Scott Hanold.

[Scott Hanold, RBC Capital Markets]

Yeah, thanks. Just a little bit more on this new area in the Permian you all found. Can you give us a sense of how you built this concept? I mean, obviously, there are a lot of companies running around in the Permian Basin and this is not out on the beaten path. So what did you find differently than others are seeing? And how confident do you feel on success going forward?

[Lee Tillman, Chairman, President & Chief Executive Officer]

Yeah. Maybe I'll make a few general comments and then again I'll hand over to Pat to maybe talk a little bit specifically. I want to maybe remind everyone again just about the concept that is inherent in our REx activities. And I mentioned this in my remarks, this is really the pursuit of these low entry cost opportunities that have appropriate scale that we believe can generate truly outsized full cycle returns. It's a very different model. It's a very different organizational structure.

The talented members of this team are compensated a bit differently than the rest of the organization. So it's a very different approach that we have taken within the REx program. And, of course, in this case the Texas oil Delaware play is one that really we've been working since 2018. So it has been a work in progress. But maybe I'll let Pat share a little bit more about the journey and how we find ourselves where we are today.

[Pat Wagner]

Sure. Good morning, Scott. Lee kind of hit on the organizational structure and kind of the way we've set up this team, which I think has been very important in -- to the success.

The team has been very focused on looking for oil resource that has multiple targets and they've been very surgical in the way they look at that. There is this play that we have identified that we're revealing today that has Woodford, has Meramec and potentially other zones in between.

We initially leased 20,000 acres, drilled the two wells and we're very enthusiastic about the results. So then we quickly went out and grew the play to 60,000 acres. We feel like now we've captured the core of the position and we feel very good that it's set up well for development and we're ready to move into delineation and further appraisal.

[Scott Hanold, RBC Capital Markets]

Okay. And as my follow-up question on the new -- in the Eagle Ford on the new acreage do you plan on allocating some activity in 2020, 2021? And how much to that area?

[Lee Tillman, Chairman, President & Chief Executive Officer]

Yeah. We'll get into more specifics on relative capital allocation. But you should assume Scott that this acreage will fold into the current optimization that we're doing across the enterprise right now to develop both our 2020 and 2021 execution level plans. And this will just be part of that broad enterprise optimization.

[Scott Hanold, RBC Capital Markets]

Okay. Thanks. Look forward to it.

[Lee Tillman, Chairman, President & Chief Executive Officer]

Thanks, Scott.

[Operator]

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

[Doug Leggate, Bank of America]

Hi, good morning everybody. I wondered, if I could just pivot, Lee to the international just for a second and ask you if you could give us an update on how you see the longevity of EG at this point. I know I've touched on this before, but clearly a big part of your go-forward proposition is your significant free cash flow on a couple of your plays onshore, but also from EG. So where do we stand today in terms of any efforts you see to continue to enhance that following the Noble transaction for example and just how you see the longevity of that free cash flow? And I've got a follow-up please.

[Lee Tillman, Chairman, President & Chief Executive Officer]

Yeah. Yeah, thanks Doug. Yeah, first of all maybe just a statement just about, which of the assets are generating free cash flow. Although EG is certainly a low investment, a high free cash flow asset I want to make it very clear that we are getting strong free cash flow support from our U.S. portfolio as well, particularly obviously in the Bakken and the Eagle Ford.

With respect to EG specifically, I would -- I talk about EG in terms of there are two value propositions within EG. There is the Alba gas condensate field, which is on a -- it basically is a long life, low decline asset. And then there is the value associated with this unique and differentiated world-class infrastructure that we have there sitting on Bioko Island, which of course is a gas plant, methanol plant and LNG facility with storage and offloading. That is a very unique piece of kit.

We've already leveraged that to bring in the Alen volumes and we expect again those molecules to show up in the first half of 2021. But we also recognize that both locally and regionally this is a gas prone area and we are the natural aggregators of gas. We have a very well-run world-class facility here that does have allege that will come available. And we want to make sure that we place that asset in a position to compete for those other regional and local gas volumes. And that's a big element of that go-forward value proposition for Equatorial Guinea.

[Doug Leggate, Bank of America]

I appreciate your answer. And obviously, we'll continue to watch how that evolves. My follow-up is probably on the – predictably on the new play. I – it's maybe a little bit of an obtuse question but clearly you haven't really given us a lot of detail for the obvious reasons. But I'm wondering, if you can speak to how this stacks up pardon the pun relative to the existing Delaware position in terms of oil maturity in terms of acreage continuity and whether there is any thought to the future relative capital allocation whether this might jump above the existing Delaware position in the queue. I'll leave it there. Thank you.

[Lee Tillman, Chairman, President & Chief Executive Officer]

Yeah. I think it's probably a bit premature right now to talk about relative capital allocation from a development capital standpoint. But certainly, Doug, we feel strong enough about the competitive nature – the potential competitive nature of this acreage by talking about a full rig line running there in 2020 with a view toward getting that play ready to compete for capital allocation in the development capital budget.

From a continuity and contiguous nature standpoint this is a very contiguous acreage position. As Pat already mentioned, we have large blocks. We also have 100% working interest today in the basin or in the acreage that we've acquired and so we believe this to be a very complementary asset to our already strong Northern Delaware position.

[Doug Leggate, Bank of America]

That's helpful. Thanks, Lee.

[Lee Tillman, Chairman, President & Chief Executive Officer]

Thank you, Doug.

[Operator]

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

[Brian Singer, Goldman Sachs]

Thank you. Good morning. When you think of the more S&P part of the going-forward strategy can you add some color on whether that means the first priority is free cash flow and how you broadly think about the desired ranges on more of a mid-cycle basis of free cash flow yield dividend yield and top line growth?

[Lee Tillman, Chairman, President & Chief Executive Officer]

Yeah. Certainly, from – when we talk about more S&P what we mean by that is returns first and sustainable free cash flow that is sustainable across a broad range of commodity price outcomes. We want to ensure that our model is robust at kind of the low end of the commodity price range and is competitive. But then we also want to make sure that the higher end if we do see price support that we can generate outsized full – basically free cash flow yields. We believe that presents an investment case that can gain traction because we're offering upside potential to offset some of the implicit volatility of the commodity. But the number one objective as we do our capital allocation and set our budget will be wrapped around corporate returns and generating that sustainable free cash flow yield.

Once, we obviously have that plan in place just as we've done for really almost now the last two years, we will then make prudent decisions about how best to share that free cash flow with our shareholders. We have a dividend today that is competitive with our E&P peers. And in fact, if you look at similarly sized S&P industrials it's also competitive. It's still a conversation that we have quarter in and quarter out, but today we still believe that a disciplined repurchase program in today's environment and based on where equities are trading today offers the best return to our shareholders. But those financial outcomes that we just went through Brian those are the objectives of our business plan. Again for us, volumes and production outcomes are just at their outputs from that process.

[Brian Singer, Goldman Sachs]

Great. Thank you. And then my follow-up is with regards to bolt-on acquisitions other acquisitions and then the interplay between that and returning capital to shareholders. First, when we look at the opportunity here in the Eagle Ford $185 million, how available are additional opportunities throughout the portfolio that could add scale to your existing assets? And when you think about saving up – potentially saving up cash for inorganic opportunities acreage or not how does that influence your return of capital to shareholders?

[Lee Tillman, Chairman, President & Chief Executive Officer]

Yeah. I would say that, we're constantly scanning the market for opportunities. It's a challenge that we talked about the characteristics of the Eagle Ford bolt-on the fact that it was synergistic that it was returns-accretive that it essentially offered largely an undeveloped position with upside. Once you start putting that kind of filter on the full opportunity set whether that be Eagle Ford Bakken or anywhere else that really narrows the field. And so we have to be very disciplined about how we evaluate and ultimately how we might transact even on small bolt-ons like the one that we just announced. But I think once you start applying the criteria that playing field gets reduced very, very significantly. And so we're always in the market. We always want to be opportunistic. And the financial flexibility that we have created with our balance sheet strength is something that we get to lean on when those opportunities do in fact come up. That also allows us to pursue those opportunities in a way that's not mutually exclusive to continue to return free cash flow back to our shareholders. Again, our return of cash to shareholders is governed by our free cash flow generation, and we can leverage our balance sheet to take on some of these more opportunistic things in the marketplace.

[Brian Singer, Goldman Sachs]

Thank you.

[Operator]

From SunTrust, we have Neal Dingmann. Please go ahead.

[Neal Dingmann, SunTrust]

Good morning, Lee and team. Lee real one quick question. I could not help but notice in the prepared remarks, you mentioned that you did increase your activity on your two highest margin plays the Eagle Ford and Bakken. I'm just wondering, could you speak to how you see the returns on these especially compared to your Northern Delaware position? Again, we know how good that is so I was interested to hear your comments throwing out the Eagle Ford and Bakken potentially even better returns than this?

[Lee Tillman, Chairman, President & Chief Executive Officer]

Yes. And I want to be really clear too that as we look ahead when we say increase, we mean increase on a relative basis. Again, the development capital program is coming down. It's the relative allocation that's going up. And it shouldn't be that surprising. Again, this is one of the advantages of the multi-basin portfolio. With really the dislocation of NGL and gas pricing right now that tends to drive you to your more oily assets. And so for us, that coupled with the fact that we have been so successful in the organic enhancement activities in both Eagle Ford and Bakken in this current pricing environment, it gives us the opportunity to lean on those a bit more.

We're still progressing activity in Oklahoma and Northern Delaware. Those returns and those more concentrated programs are still very competitive. But as you look at the near-term kind of pricing environment, there's no doubt that the Bakken and the Eagle Ford because of their oil weighting are superior from an economic return standpoint. I mentioned in my opening remarks that in some of the extension work that we did last year in the Bakken, even on actual pricing and actual costs, those wells pay out in 10 months. I mean, these are very impressive economic returns, but it all has to come to roost in your enterprise level return.

So we're going to design our program in such a way that it will ensure that we continue this underlying rate of change in our corporate level returns too. We don't want to get -- half-cycle returns are great as we do our internal relative capital allocation, but we're going to judge our investment program on how is it moving our enterprise level returns, certainly even on a price-normalized basis.

[Neal Dingmann, SunTrust]

Thanks for the clarification. And then looking at slide 14 maybe following up on the Bakken. You've all done a nice job of just continuing to expand that and extend that play physically down South. Could you talk as you sort of sit today, how you think about total core inventory and maybe where the focus is going to be for 2020 in that play?

[Mitch Little, Executive Vice President, Operations]

Yes. Sure Neal. This is Mitch. I think slide 14 that you're referencing there and the slide earlier in the deck where we really have highlighted organic enhancement helps characterize and gives you a good visual on how much we've extended the core. We certainly would say the majority of Hector and Ajax have been proven up through our organic enhancement trials. To put some context to that, if you look at Hector over the last two years, we've doubled well productivity while shaving 30% off of well costs. That's a game changer for economics in the Bakken.

And as Lee mentioned in his remarks, we've significantly upgraded the returns of hundreds of locations across both those basins to where the vast majority of our remaining inventory in both basins is top-tier. I also want to make it really clear the 500 adds that we talked about in the release, those are absolutely new sticks that weren't in our prior life of field plans of development. So we'll see a good mix of Hector and Myrmidon next year on the upgraded returns.

I don't have the exact split between those right now as we're still finalizing and tweaking the plans, but we'll certainly have activity in both areas. And we will continue our efforts across all these basins to drive further enhancements from the organic enhancement efforts that are targeting, not only well productivity, but also well cost. And we certainly see additional running room for future adds in both of those basins.

[Neal Dingmann, SunTrust]

Perfect. Thanks, Lee, thanks Mitch.

[Operator]

From Susquehanna, we have Biju Perincheril. Please go ahead.

[Biju Perincheril, Susquehanna]

Hi, good morning. Lee going back to the relative allocation of capital next year. I suppose the success that you're seeing in the Bakken and the Eagle Ford is a direct function of your understanding of that -- of the rock there. And when we -- in the Northern Delaware looks like you have sort of a methodical delineation program. So can you give us some goals or milestones you're looking for in that delineation before you can -- either before that asset can come to a more -- a higher proportion of your CapEx?

[Lee Tillman, Chairman, President & Chief Executive Officer]

Yes. I'll maybe say a few things and then also ask Mitch to chime in as well. You're right. We have been very methodical in our approach to Northern Delaware. You have multiple STACK plays across a very broad geographic area. We mentioned for instance in fourth quarter that we're actually moving over into the Red Hills area to continue our delineation there. So that work is really still ongoing. And in parallel with that delineation and appraisal work, we're also continuing to work on other aspects of the business in Northern Delaware to ensure that we're maximizing our margins. And that's everything from getting oil and water on pipe to ensuring that we have the absolute lowest lease operating expense there as well.

So we're doing all of the things that we need to do to be prepared, to take that asset into a more I would say aggressive growth mode that we get it to more of a scale in our portfolio. But we can be methodical. We can be patient. This is again the beauty of the multi-basin model. We don't have to get in front of our headlights. We can make sure that we truly are optimizing the field development plan. And that's what's going to be our focus and certainly, we have a lot of work left to do in that area in 2020.

[Mitch Little, Executive Vice President, Operations]

Yes, Biju I'll just add a little bit of additional color. I think Lee has covered the medium term outlook really well. Speaking specifically about 2019, about half of our activity was in the Malaga area in Eddy County and about half in Red Hills and we would characterize the Red Hills activity as more heavily weighted towards delineation.

You see across our more mature basins the type of productivity we're driving and those workflows translate to all basins we operate. And if I highlight the Upper Wolfcamp activities in Malaga where we've had enough activity in that area to move into development mode, you see similar kind of performance improvement there with 35% increase in productivity per lateral foot and 20% well cost reductions.

But this is a multi-bench play, lot of column to work with. I think we had tested six different intervals over the course of 2019 and we'll have more delineation as part of the program in 2020. So, there's an efficient pace at which to move forward on these. Some areas are moving into development and other areas we're still in delineation mode.

[Biju Perincheril, Susquehanna]

That's very helpful. And my second question was in the new play in the Woodford. In the slide deck you showed two landing zones. Can you say if the first two wells tested those both of those zones? Or were they both in one zone?

[Pat Wagner]

This is Pat, Biju. We're not going to disclose exactly where we landed the existing wells, but both of those wells did test the Woodford.

[Biju Perincheril, Susquehanna]

Understood. Thank you.

[Lee Tillman, Chairman, President & Chief Executive Officer]

Thank you, Biju.

[Operator]

From Stifel we have Derrick Whitfield. Please go ahead.

[Derrick Whitfield, Stifel]

Good morning all and thanks for taking my questions. Shifting back to the Bakken in Slide 13 specifically. You've done an exceptional job of taking capital costs out of the business and arguably have the lowest well cost in the basin. Could you comment on the drivers for the design savings and on whether or not you've tested or evaluated in-basin sand?

[Mitch Little, Executive Vice President, Operations]

Sure Derrick. This is Mitch again. Let me back up to kind of a high level and then I'll walk you through some of the specifics. I'm sure you can appreciate I'm probably not going to give you the full play-by-play of our success, but I can share the mindset and the approach we're taking and then I'll address your regional sand question.

What I would say is our corporate returns focus has really resonated well throughout the organization and deep into the organization. We started on this organic enhancement journey with a focus on well productivity which was really driven by high-intensity completions. But as we've evolved that approach, it's evolved to a relentless focus on not only well productivity, but well costs.

And so the way we attack that is we've evolved our proprietary workflows that -- we deployed targeted data acquisition. We integrate that with data analytics, advanced simulation techniques, and empirical results that really allow us to optimize from spud all the way through flow back.

We addressed well construction, reservoir targeting, pump schedule, cluster design, stage spacing, use of diverters, use of artificial lift; it's a very comprehensive list of things that we're attacking, and showing great improvement on.

Is there more room to grow or to go in the Bakken? We certainly believe so and our team certainly believes so. The last two quarters we've driven program completed well cost at new records. And in our Herbert pad which is the Southernmost Hector test to-date, we delivered $4.5 million completed well costs versus $4.9 million average for the Bakken.

We have looked at regional sand a number of times. We're not currently deploying it. We're always looking at alternative sourcing models. But we have seen some gains just in the contracting structures and strategies that have driven our proppant costs down in the Bakken as well.

[Derrick Whitfield, Stifel]

Okay, that's very helpful and comprehensive. As my follow-up perhaps building on Doug's earlier question on the Texas-Delaware oil play could you comment on the pressure gradients for the Woodford and Meramec intervals and speak to the range of oil yields you're expecting across the trend?

[Pat Wagner]

Sure Derrick, this is Pat. I won't give you the exact pressure gradients but both the Meramec and the Woodford are over-pressured. I didn't catch the last part of your question.

[Derrick Whitfield, Stifel]

Sure. The last part was just speak to the range of oil yields you're expecting across the trend.

[Pat Wagner]

Sure. Yes. It's about 65% average oil cut across the entire leaseholds.

[Derrick Whitfield, Stifel]

Thanks guys. That's very helpful.

[Operator]

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

[Nitin Kumar, Wells Fargo]

Good morning guys and thank you for taking my question. Maybe just going back to the 2020 and 2021 thought process. Could you quantify the maintenance CapEx that you're seeing for those years as you're bringing activity down and growth? I imagine that maintenance amount of spending is coming down, but if you could quantify that?

[Dane Whitehead]

Yes, we're not going to quantify maintenance capital. Obviously, we're still in the process of optimizing our business plan. We'll get more into the details of the plan in February. But suffice to say I think and Lee was talking about maintenance capital that even though we're setting our basis at $50 WTI, we expect the enterprise breakeven the point at which we're generating organic free cash flow to be below that in both of those years.

[Nitin Kumar, Wells Fargo]

Got it. And then just you mentioned the REx spending earlier about $200 million. What is the impact of Equinor? Like should we be thinking about the $200 million as a net Marathon number.

[Nitin Kumar, Wells Fargo]

Great. Thank you, so much.

[Lee Tillman, Chairman, President & Chief Executive Officer]

Thank you.

[Operator]

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

[Jeanine Wai, Barclays]

Hi good morning everyone. Thanks for fitting me in here.

[Lee Tillman, Chairman, President & Chief Executive Officer]

Good morning Jeanine.

[Jeanine Wai, Barclays]

My question is on 2020. So, in terms of your decision to spend less year-over-year and lower the U.S. oil growth rate, do you have any kind of ballpark estimate on how much this enhances your either free cash flow capital efficiency or corporate breakeven relative to what your initial plan was which I think called for an increase in development activity next year?

[Lee Tillman, Chairman, President & Chief Executive Officer]

Yes. First of all Jeanine, I would say, our objective was not to spend less. Our objective was in fact to enhance returns and drive free cash flow generation. And that model is what is as an output is generating a more moderate growth profile in 2020 and 2021. We're going to provide much more details more aligned with the last part of your question Jeanine as we get out into February.

Similar to this year's plan we expect to quantify the plan not only in terms of operational outcomes but also in terms of financial delivery as well based on our $50 planning basis. So I would just say stay tuned on that. But obviously we believe, that the optimized plan will strike the correct balance here between returns free cash flow generation while also achieving a more moderate oil growth rate here in the U.S.

[Jeanine Wai, Barclays]

Okay. That's really helpful. Thanks a lot. I look forward to February. And my follow-up is on the organic inventory expansion. You've made really good progress on that with the over 500 locations added in the Bakken and the Eagle Ford. Can you provide a little bit more color on this? So for example are the additions more heavily weighted in one play versus the other? I know from the slide it looks like it could be pretty even. And how much of the additions are related to 2019 improvement? And lastly what is your economic cutoff for moving locations into this bucket?

[Lee Tillman, Chairman, President & Chief Executive Officer]

Yes, I would say that your assessment is correct and that probably the split is generally pretty even maybe a little bit biased toward Eagle Ford. Again we talked about replacing a couple of years of inventory at current run rates. Obviously the run rate in Eagle Ford is a bit higher than the Bakken so you could kind of pro rata that to probably back into what that split is. We still obviously believe that there's a lot of remaining running room to chase there. I believe that the teams have done a good job. We believe it's a sustainable process as we look ahead and as we do with all three elements of the inventory enhancement framework.

[Jeanine Wai, Barclays]

Okay. Great. Thank you for taking my questions.

[Operator]

And from Raymond James, we have Pavel Molchanov. Please go ahead.

[Pavel Molchanov, Raymond James]

Thanks for taking the question. To EG, it's obviously going to be a similar portion last year [Technical Difficulty] relatively speaking. So can you talk about the [Technical Difficulty] that you're planning at the LNG facility in 2020?

[Lee Tillman, Chairman, President & Chief Executive Officer]

We lost a good part of that Pavel. You're really breaking up. I know the question pertained to EG, but ex that it was very difficult to hear your question.

[Pavel Molchanov, Raymond James]

Yes. I was asking if, in 2020 any significant [Technical Difficulty] or maintenance cycles in EG?

[Lee Tillman, Chairman, President & Chief Executive Officer]

Yes. Got you. That's much better Pavel. Thank you. I'll turn over to Mitch for that.

[Mitch Little, Executive Vice President, Operations]

Yes. Sure Pavel. Again, we'll disclose more specifics in February when we release our capital budget. But there are some maintenance activities at a couple of the onshore facilities in 2020.

[Lee Tillman, Chairman, President & Chief Executive Officer]

And we'll give a bit more disclosure on that in February, so that it can be rolled in to everyone's modeling for the EG asset.

[Pavel Molchanov, Raymond James]

Okay. And as your balance sheet continues to kind of delever, what's your latest thinking just broadly skiing on hedging?

[Dane Whitehead]

Yes. This is Dane. Thanks for asking a question. I can answer. Right now, for the balance of this year, we're about 40% hedged on oil with three-way structures with about a $56 floor and ceiling I call north of $70. About half of that volume as we head into 2020 is currently hedged with three ways at like $55 to $65. We have a great balance sheet, very low breakeven price, so lots of financial flexibility. So we think of hedging in that context and are very patient not to rush into a flattish to macro-dated curve and add positions. We've been pretty opportunistic as we leg into it and expect us to continue to do that, just be very patient, but mindful that it's nice to have some downside protection as we move through '20 and into '21.

[Pavel Molchanov, Raymond James]

All right. Appreciate guys.

[Dane Whitehead]

You bet. Thank you.

[Operator]

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

[Lee Tillman, Chairman, President & Chief Executive Officer]

All right. Well, we recognize that investors have choices and we appreciate your interest in Marathon Oil. Execution excellence leads the way in our company. And again I want to personally thank all of our dedicated employees and contractors who deliver on that mandate 24/7 quarter in and quarter out. Thank you very much and that concludes our call.

[Operator]

Thank you. Ladies and gentlemen, thank you for joining. You may now disconnect.