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Marathon Oil Corp
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Welcome to the MRO Fourth Quarter 2019 Earnings Conference Call. My name is Sylvia and I'll be your operator for today's call. At this time all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. [Operator Instructions] Please note this conference is being recorded. I will now turn it over to Guy Baber. Mr. Baber, you may begin.
Thank you, Sylvia, and thanks to everyone for joining us this morning on the call. Yesterday, after the close, we issued a press release, slide presentation and an investor packet that address our fourth quarter and full year performance, as well as our 2020 capital budget and associated guidance. 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 in the press release and presentation materials, as well as to the risk factors described in our SEC filings.
With that, I'll turn the call over to Lee, who will provide his opening remarks. We will then open the call up to Q&A.
Thanks, Guy. And thank you to everyone joining us this morning. I will begin my comments covering our forward two-year outlook. And in doing so, I will also cover our track record of execution against our framework for success.
This track record against a transparent set of priorities, corporate returns, sustainable free cash flow generation, return of capital to shareholders is unique in our peer space, it's comprehensive and it has resulted in bottom line financial and operational outcome that few E&Ps have been able to match.
Most importantly, it has resulted in financial outcomes that also compete on a heads up basis against the broader market. Our challenge is less E&P and more S&P. It is this successful track record of execution that underpins confidence in both our strategy as well as our sustainability to continue delivering, despite an ongoing backdrop of uncertainty and volatility.
Looking to the specifics of our forward two-year plan, as you would expect, our outlook prioritizes the financial metrics that matter most; corporate returns improvement and sustainable free cash flow generation across a wide range of commodity prices. And as you've heard me say, again and again, it all starts with our returns-first orientation.
Corporate returns improvement remains a top capital allocation objective, as such, it should be no surprise that it's also a key element of our executive compensation scorecard and our focus is bearing fruit.
Our underlying price normalized 2019 cash return on invested capital is over 50% higher than in 2017. This robust improvement is the product of success across multiple dimensions, portfolio management, concentrated capital allocation, efficient operation, high-margin oil growth and significant cost reductions.
Looking ahead, we fully expect to continue building on this momentum. Disciplined reinvestment across our high quality multi-basin portfolio will continue to drive our underlying corporate returns higher at a rate that outpaces our production growth.
The second key element of our outlook is sustainable free cash flow generation at a wide range of commodity prices. Our track record of free cash flow delivery is well-established at this point and speaks for itself.
Fourth quarter marked our eighth consecutive quarter of post dividend organic free cash flow generation, a track record that is largely unmatched by anyone in our peer group. In total, we've generated approximately $1.3 billion of post dividend organic free cash flow since the beginning of 2018 with over $400 million delivered during 2019.
With improving capital efficiency, we expect and even stronger underlying free cash flow profile for 2020 and 2021. At a flat WTI oil price of $50 per barrel, we forecast around $600 million of post dividend organic free cash flow over the next two years.
A few other important takeaways from our two-year free cash flow outlook. Our plan is resilient. Our outlook translates to a post dividend organic free cash flow breakeven oil price of $47 per barrel WTI in 2020, with an even lower breakeven in 2021.
Our low oil breakeven price advantage hedges and conservative balance sheet effectively insulate us from temporary downside price volatility. That said, should commodity prices further deteriorate for an extended period of time, we have ample flexibility built into our plan to respond without negatively impacting our underlying operations or our hard earned capital efficiency.
Let me be clear. outspending cash flow in 2020 is not an option for Marathon oil. And we will adjust our plan as necessary to protect free cash flow. Our underlying capital efficiency and free cash flow momentum improves markedly over the next two years.
In fact on a flat $55 WTI basis, our projected 2020 and 2021 free cash flow is similar to that realized in 2018 and 2019, yet at a WTI oil price that is $6 per barrel lower along with much lower gas and NGL prices.
Our upside leveraged to even modest oil price support is significant. While the forward curve is depress today, commodity prices will undoubtedly remain volatile. And are crude weighting, coupled with a low enterprise breakeven oil price is a powerful combination in any price environment.
At $55 per barrel WTI, we generate $1.3 billion of post dividend organic free cash flow over the next two years, at $60 per barrel WTI this rises to over $2 billion. Our track record of free cash flow generation is differentiated and our disciplined approach to capital budgeting has served us well over the last two years.
And our forward outlook is not only attractive against E&P peers, but delivers organic free cash flow yields competitive against the broader market at moderate commodity prices.
Moving on to the third key element of our framework. Rest assured, we will continue to prioritize the return of capital to our shareholders, through a competitive dividend and through our $1.4 billion of outstanding share repurchase authorization. Notably, return of capital to shareholders remains a component of our executive compensation scorecard.
Since the beginning of 2018, we have returned approximately $1.4 billion of capital back to our shareholders, representing around 23% of our cash flow from operations. This has included $1 billion of share repurchases that have reduced our outstanding share count by over 7%, including $350 million of share repurchases executed in 2019.
Importantly, this return of capital has been entirely funded by organic free cash flow, not by asset sales proceeds. Over the last two years, we have successfully distinguish ourselves as one of the only E&P companies that has both generated meaningful free cash flow and returned a significant portion of that free cash flow back to investors.
This leadership position is important to us. And we fully expect to continue building on the success in the years to come. Finally, differentiated execution remains the engine that powers our delivery of financial performance. It is a broad mandate, but really centered on execution excellence and consistent delivery against our external guidance.
Over the last two years we have consistently delivered on our commitments with no increase to our initial development capital budget while exceeding our annual oil production growth guidance. Our capital budget is a commitment not a suggestion.
We have consistently improved our capital efficiency driving a 10% annual reduction in completed well cost per lateral foot and 15% annual reduction in U.S. unit production expense in 2019.
And we realize success across all elements of our resource capture framework cumulatively adding over 1000 locations through a combination of organic enhancement, resource plan exploration, and bolt-on acquisitions and trades.
The addition of these new locations represents approximately three years of inventory, further demonstrating the long-term sustainability of our strategy. It is not just about results, but how we deliver those results. And 2019 was yet again a year that we can be proud of, including our best safety performance on record.
And as we look to 2020 and 2021 differentiated execution will remain a defining characteristic of our company. We will continue delivering on our commitments, $2.2 billion of development capital in 2020, contributing to 6% U.S. oil growth at the midpoint, with comparable capital and growth expected in 2021.
We will maximize our capital efficiency through more efficient operation fully expecting to continue driving our well cost and unit production expense lower. And we will remain as focused as ever on further improving our already high-quality resource base through our sustainable resource capture framework, all with an eye on full cycle returns.
Transitioning to the specifics 2020 program, our disciplined $2.4 billion total capital budget is down 11% from 2019, it is also down from 2018 spending levels. Our budget is comprised of $2.2 billion of development capital and $200 million of resource play exploration capital, successfully balancing corporate returns, free cash flow generation and our strategic objectives.
The outcome of our rigorous capital allocation process is 6% U.S. oil growth in 2020 at the midpoint of our guidance with oil growth outpacing boe growth consistent with our focus on corporate returns.
Again, we expect comparable development capital and comparable oil growth in 2021. Importantly, our forward trajectory is sustainable prioritizing ratability and consistency of operations to maximize capital efficiency over a multiyear period.
The outcome is returns creative oil growth on both an annual and exit-to-exit basis in 2020 and 2021, while prioritizing free cash flow generation. And I want to emphasize again that our plan is both resilient and flexible. We can't predict forward commodity pricing, but we do know that it will remain volatile.
While, our low cash flow breakeven and conservative balance sheet insulate us to downside volatility, should pricing deteriorate to below our breakeven levels for an extended period, we have the flexibility to adapt without compromising our underlying operations or capital efficiency. And for avoidance of doubt, under any reasonable commodity price scenario, we will not outspend our cash flow.
Moving on to the asset specific detail that make up our 2020 program, roughly 70% of our development capital will go to the Eagle Ford and Bakken, up from approximately 60% during each of the last two years.
This shift reflects the relative returns generated in the current commodity price environment that places a premium on oil mix relative to gas and NGL, and further highlights the strength and flexibility of our multi-basin portfolio.
The recent success of organic enhancement in these two basins with over 500 locations added since 2018 and hundreds more upgraded provides the opportunity and confidence to allocate more capital to these high return assets.
The Eagle Ford will continue to deliver strong returns and free cash flow, but will also contribute oil growth even with an expected year-over-year reduction in wells to sell. Coming off the strongest two oil productivity quarters on an IP30 basis and the history of the asset.
We expect continued strong results from our primary development program across Karnes, Atascosa and the Northeast core which was recently expanded with the fourth quarter closed of a bolt-on acquisition that added about 18,000 contiguous and largely develop -- undeveloped net acres.
Additionally, we will continue progressing organic enhancement initiatives, including our redevelopment and enhanced oil recovery programs. Early results from both of these programs have been encouraging with both having the potential to meaningfully add to our total resource base.
In the Bakken, we will continue delivering strong financial return, free cash flow and oil growth. Our 2019 Bakken development program will pay out in 11 months at actual 2019 cost and pricing.
While this accomplishment is impressive, we expect to drive further improvement to these already industry-leading financial returns in 2020. The result of an increase in well productivity and further reductions to our well cost.
Completed well cost already average below $5 million during fourth quarter, down 18% from the 2018 average with a recent pad delivering an average completed well cost of $4.3 million.
In Oklahoma largely in response to the dramatic weakness in gas and NGL pricing relative to oil, we are reducing our investment to a more concentrated two to three rig program focused on oil-prone areas in the SCOOP to protect our returns and prioritize free cash flow generation.
Critically, our Oklahoma asset transition to positive free cash flow generation during the fourth quarter benefiting from the combination of reduced spending, efficient operations and strong productivity, including basin-leading performance from the SCOOP Springer.
Over the next two years we fully expect Oklahoma to maintain its positive free cash flow status even at the current depressed forward curve for natural gas with 2020 oil production comparable to the 2019 average and overall oil mix for the asset rising.
In the Northern Delaware capital efficiency will continue to improve with an expected average lateral length increase of over 35% in 2020, a strong indicator of the progress in our ongoing efforts to core up our position.
We will strategically pace our investment with a focus on full cycle returns while we continue appraising our acreage incorporating learning, enhancing our margin profile and realizing early development success in critical intervals.
On only a modest increase in wells to sales, the asset will again contribute to total company oil growth. After successful divestments in the UK and Kurdistan, we have simplified our international portfolio to our integrated gas business in Equatorial Guinea which had another strong year, delivering just over $400 million in EBITDAX.
While 2020 financial delivery will be off trend from 2019 due to the combination of scheduled maintenance and weaker commodity prices, we expect earnings to recover in 2021 and beyond.
Schedule maintenance during 2020 includes the first quarter turn around already underway at our AMPCO Methanol plant as well as planned E.G. LNG maintenance during the fourth quarter.
Regarding price, aside from the obvious impact on condensate, weak gas prices will affect our legacy Henry Hub length L&G contract and associated E.G. LNG equity income. Global menthol prices have also fallen to cyclical lows.
Looking ahead for E.G. Our 2021 earnings forecast is similar to 2019 price normalized. We began to realize benefits from the Alen backfill agreement in 2021. Our legacy Henry Hub LNG price contract expires in 2023, and there are no significant plant E.G. turnaround until 2024.
Further, we continue to pursue additional backfill gas opportunity to leverage our advantaged infrastructure position. Bottom line, our unique integrated business in Equatorial Guinea will remain a strong contributor to our total company earnings and cash flow stream for years to come.
While that covers our development capital and producing assets, we have also established a $200 million resource play exploration budget for 2020. This budget reflects the transition from primarily acreage capture to exploration and appraisal drilling activity in two oil plays of scale; the Texas Delaware and the Louisiana Austin Chalk. Our overarching objective remains competitive full cycle returns through low entry cost.
In the Texas Delaware, we have established the contiguous 60,000 net acre position perspective for both Woodford and Meramec targets. We now have three Woodford wells online at an average 60% oil cut.
Extended production history from our first two wells continues to demonstrate strong productivity, lower water-oil ratios and shallow declines. Our recent third Woodford well is on flow back with early rate consistent with our expectations. Our initial Meramec exploration well is in progress.
In the Louisiana Austin Chalk, our first modern completion in the overpressure Western Fairway of the play is on flow-back and cleaning up. While it is far too early to draw conclusions, the well is demonstrating strong productivity with recent oil rates of 1200 barrels of oil per day on a restricted choke and had a flowing wellhead pressure above 8000 psi.
Gas oil ratio, API gravity at around 49 degrees and water-oil ratio are all consistent with our pre-drill expectations. Again, some encouraging early performance in contrast to some erroneous conclusions you may have seen drawn from state data featuring test rates in the first 72 hours of cleanup.
With the early results of the first well confirming our expectations on initial productivity, oil quality, as well as reservoir energy, we recently spud our second exploration well in the play and we'll have results to discuss later this year as we continue to integrate longer dated production with 3D seismic.
In summary, we are proud of our results and how we deliver those results; safely responsibly and ethically. And our executive compensation scorecard reflects those core values with safety environmental performance in GHG intensity each represented alongside corporate returns and return of capital.
For two years now, we have delivered financial and operational outcomes that few E&Ps in our peer space have matched. Yet, 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 the financial metrics that matter and doing so in a volatile commodity price environment.
We believe in our strategy and our framework for success, corporate returns first, sustainable free cash flow generation and prioritizing return of capital to shareholders, a framework builds upon our multi-basin portfolio and a balance sheet that is an investment grade at all three primary rating agencies.
Within that context, we will remain focused on what we control, which is our execution and the consistent delivery against our framework, quarter-after-quarter, year-after-year. We continue to believe that 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.
We will begin the question and answer session. [Operator Instructions] And our first question comes from Scott Hanold.
Yes. Hi. It's Scott Hanold from RBC.
Good morning, Scott.
Just to kind of playoff some of that -- the last commentary you made there early in what gets the Marathon rewarded by investors? Certainly, you've been putting up some good free cash flow numbers. The market doesn't seem to be really view that is positively as one would expect. How do you think about this versus option that you have to pivot other things and that may include obviously capture of a bigger resource position?
Yes. Thanks Scott and good morning. You know, Scott, we are committed really to allocating capital that balances returns improvement with sustainable free cash flow generation. That's our model. That's our frameworks for success. I think we've now clearly established a track record against that model, that track record I believe speaks for itself. I think we've taken not only a strong shareholder friendly actions, but we've also delivered on our underlying operational commitments. And to us it really comes down to ensuring that model is sustainable, that model is resilient and that we continue to protect the upside through our oil leveraging. But, we believe in our strategy, Scott, and you should really expect no changes for us going forward. Hence, the reason we provided the two-year view of our financial outcomes.
Okay. Appreciate that. And then, talking a little bit about the Delaware -- Northern Delaware basin. It looks like capital to that area is obviously down a little I think year-over-year, and with Eagle Ford and getting a little bit more, but can you talk about what you've learned in some of that Red Hills, initial Red Hills well you've drilled. I mean, I would have expected Delaware to be a bigger part of 2020. I guess is my base question. And what have you've found in some of these core areas that you have relative to say the opportunity in the Eagle Ford?
Yes. Let me talk a little bit about overall allocation and perhaps I'll flip over to Mitch to provide a little more operational color on Red Hills and the program we just completed there in fourth quarter. First thing, not to state the obvious Scott, but the entire total capital budget is down 11%, development capital is down 9%, and actually from a mix perspective the Northern Delaware is still receiving essentially a very similar mix of that lower capital allocation. Again for us, it comes down to that capital allocation is driven by the confidence in generating those high returns and hence that's why you've seen that slight makeshift from 60% to 70% to Bakken and the Eagle Ford. That in no means is means that we are disappointed in Northern Delaware. It just means we have superior opportunity today and other parts of our portfolio, because of the current commodity price environment. With that, maybe I'll handover to Mitch and let him give a little bit of color on our -- the specifics of our program.
Yes. Sure, Scott. As you're referencing, we had a fair bit of delineation work in 2019 included in the Red Hills area. What I would say about that is we're encouraged by the early results from the delineation work. We tested a lot of different intervals, as well as some different completion designs, saw some particularly encouraging signs in the Upper Wolfcamp and Bone Spring. Relative to the capital allocation as well, wells to sales this year will be slightly up from 2019 levels. The majority of that activity is going to be focused in those intervals, the -- both the Wolfcamp and Bone Spring and it will across Malaga and Red Hills. Little bit less delineation activity this year as we are focused on the corporate returns and free cash flow generation. And that also give us time to integrate some longer-term performance data from the 2019 delineation efforts and feed that into our capital allocation process.
Okay. So overall would you say the Northern Delaware, is there anything that limit you from going faster? Is there any infrastructure? It sounds like, wells are performing good. So is there any infrastructure concerns or issues that need to be addressed as well in that area?
Now, we're making great progress there, Scott, and by year-end, we had I think about 90% of oil and water on pipe. We've got good midstream infrastructure on the gas side as well. And so, it's really -- the underlying driver there is our capital allocation process and focus on top level corporate returns.
Understood. Appreciate it. Thanks.
Our next question comes from Derrick Whitfield.
Good morning. Thanks for taking my questions. In regards to your 2020 and 2021 outlook, your broad outline suggests capital efficiency is improving in both 2020 and 2021. Would it be fair to assume the capital efficiency gain in 2021 is largely driven by the moderation of your U.S. base declines suggesting you're not banking lower well costs into 2021 estimates?
I think, there's obviously a lot of factors that go in to the efficiency improvements year-over-year. But I would say that a consistent theme in both 2020 and 2021 is still a continued improvement and not just well productivity, but also our ability to drive completed well cost, as well as our own I'd say unit cost at a field level lower. And that theme simply just continues and accelerates a bit into 2021. So, it's a multiple factors, but certainly that trend that we have established now over the last two years of not only driving our capital costs down from a completed well cost standpoint, but also our unit production expense in the U.S., all of that is contributing to that improvement in capital efficiency moving forward.
That's helpful. And then as my follow-up, shifting over to the Louisiana Austin Chalk, the initial results suggest a highly charged reservoir with strong energy drive mechanism in place. Are you expecting that degree of wellhead pressure across the Western fairway?
Hi, Derrick. This is Pat. That's correct. I mean, we have a flowing tubing pressure today of over 8,000 pounds and it's as expected. This is a very highly pressured part of the play with very good deliverability and we do expect that the Western fairway will have this sort of pressure.
Thanks. It's very helpful guys. Thanks.
Our next question comes from Arun Jayaram.
Yes. Good morning, Lee.
Good morning, Arun.
Since you created the REx -- good morning. Lees, since you created the REx program, we've seen a pretty sharp retrenchment in dollar per acre valuations, as well as public market valuations for E&P. I was wondering if you could comment how inorganic opportunities are now competing relative to REx in terms of portfolio enhancement. And if you've looked at any deals more recently given this backdrop?
Yes. I think what I would do, Arun, I'll take you back to our overall resource capture framework. And it's not an exclusive strategy. If you look at the three elements of that strategy, it starts first and foremost with organic enhancement, which is really working the assets that we already have in the portfolio. And the team has done an incredible job there in not only replacing inventory, but uplifting a good bit of the additional forward inventory.
The other piece of that is an organic growth looking at both small bolt-ons, as well as trades. And in that, the example I would point to is in fact the position that we just established in the Northeast core of the Eagle Ford that closed at the end of the quarter. And here we had the ability to add on to an area that now has created this 70-well development opportunity for us. And so, that part -- that market opportunity we continue to look at those. And then as you mentioned the third element of that is the REx program. We believe that you need to generate success across all three of those dimensions.
It really isn't an all-of-the-above strategy and in some years it may flex more toward one of those three than the others. But that is a strategy. And certainly, Pat and his team look at all those opportunities whether they be REx opportunities or inorganic opportunities that are around our existing footprint.
Got it. And just based on that commentary, there appears to be any focus on call it larger scale M&A?
Well, I think, we have worked very hard to develop this comprehensive resource capture framework. We've transformed our base portfolio and created this differentiated position here in the U.S.. And what that means is, that for us, really large scale M&A is not required for our forward success. We're improving our returns. We've generated free cash flow over the last eight consecutive quarters. So our model is delivering the financial outcomes. And so, in that context any opportunity, whether it be large or small scale inorganic is going to be looked at through that lens. How can it be accretive to what we're already achieving. And that's a as you might imagine a very high bar.
Great. And one modeling question regarding E.G., Lee highlighted how that business unit generates a little bit more than $400 million of EBITDAX in 2019. You expect that to recover in 2021. I was wondering if you could give perhaps the impact from the maintenance and downtime and the lower Henry Hub prices in 20 relative to that $408 million you printed last year?
Yes. Arun, this is Mitch. The maintenance impacts are pretty well laid out in the slide deck. But just to kind of go back through those. We're in the midst of a major turnaround at the AMPCO methanol facility. That's going to have about a $30 million earnings impact on the quarter. And then expect it to be back up and running for the rest of the year at kind of full rates. In Q4, we then have some planned maintenance at the LNG facility, which will impact the gas rates. But we'll continue to process the liquids and so they're not going to be an impact on liquid rates.
Sensitivity to product prices, we can't talk about the specific terms of the E.G. LNG contract for confidentiality reasons. But it is a Henry Hub length contract. We're seeing pretty material degradation in that index relative to 2019. And so that's going to be meaningful. And then, of course, methanol prices are at kind of a cyclical low right now as well. So, I think it's important to look forward. We've got the long-lived Alba field with shallow decline and essentially no reinvestment. That's been on a steady trend and we expect it to continue to do so.
And then looking forward, we've got the Alen volumes that should start up in 2021, early 2021. The Henry Hub index contract expires at the end of 2023. So back on -- in 2021 our normalized prices back to earnings levels similar to 2019 and then additional upside through the things I mentioned, as well as continuing to look to source additional backfill volumes following the Alen agreement that we signed up last year right.
Great. And this is in your free cash flow guide though?
It's absolutely. All of that's baked into the two year profiles that we've given you.
All right. Thanks a lot.
Our next question comes from Jeanine Wai.
Hi. Good morning everyone. My first question is on the two year cumulative free cash flow. For the updated tier, can you walk us through how to reconcile the recalibrated $600 million versus $750 million plus. I know some of this is likely commodity price related and so you just walk through some of the easy stuff. But we're also wondering if you could quantify the capital efficiency improvements, which would be a positive offset to using lower prices?
Yes. Hi Jeanine, this is Lee. Just relative to the last disclosure on the two-year view and the delta there. It really is all about pricing. If you go back and you look at the price decks that were used to calibrate the 750. And again, we're not trying to predict pricing. We're simply putting a benchmark case out there for you. Obviously, it had much higher pricing for both gas and NGL. We kind of brought those back to more market based levels to present what we believe is a much more realistic view of the free cash flow generation.
And so, despite the fact that we actually are having an improvement and underlying capital efficiency, obviously, it's very difficult to offset the full impact of a significant downshift in both gas and NGL pricing. But without quantifying what I would tell you is directionally capital efficiency is improving. The bulk of that delta is really associated with the assumptions around gas and NGL pricing.
Okay, great. That's very helpful. Thank you. And my second question is related to REx. In terms of again capital efficiency tailwind year-over-year. REx budget for 2020 reflects transition from acreage capture to more exploration or appraisal kind of thing. So how much of the 200 million of REx this year is actual productive CapEx as opposed to spending more money on seismic or additional acreage capture either within known REx areas or otherwise?
Yes. Jeanine, again, we don't provide that fine line on it, because obviously we'll be driven by performance throughout the year. But the budget is primarily focused on exploration and appraisal drilling in both Texas Delaware and Austin Chalk. Obviously, there are still some spend in seismic and geoscience work there. But the bulk of it is really oriented toward continuing to explore and appraise with the bit in those two plays.
Okay. Thank you for taking my questions.
Thank you, Jeanine.
Our next question comes from Doug Leggate.
Well, thanks. Good morning, Lee. I got a couple of interrelated questions and I apologize for getting into this level of detail, but I've got -- my first one is on E.G. and my second one is on the value proposition of Marathon, but also the industry. I just want to get your perspective on that. First on E.G., the free cash flow guidance you've given, clearly is a big chunk of that comes from E.G.. Yesterday, Noble laid out trajectory for how Alba declines over time and it appears the bulk of the backfill as I understand it is going to come from Alen. So I'm just wondering, can you walk us through how you see the free cash flow evolution of E.G. in your trajectory? And then, I'd like to get into the valuation question if I may.
Yes. I'll offer my thoughts and if I miss anything I'll ask Mitch to jump in. First of all, what I would say is that we feel very strongly that the E.G. asset is going to be a free cash flow generator for the future for the company. And the Alen backfill we believe is just a first step as we continue to look to leverage what is a truly a world-class piece of infrastructure there. And so, we think that we have -- but I want to emphasize that from a free cash flow generation standpoint essentially we have all of our assets ex-Northern Delaware are generating strong free cash flow going into both 2020 and 2021
And so, I don't want to paint this as an E.G. only story. The thing that differentiates E.G. is the fact that the reinvestment levels are relatively de minimus there. However, from an absolute free cash flow generation standpoint, all three of our U S basins ex-Northern Delaware are contributing strongly to that free cash flow profile going forward in time.
I appreciate the answer. My follow-up is kind of related to this. And again forgive me for this lead, but we all know how bad the sector has performed and you have been early to committing to free cash flow and you should be commended for that. The issue we're all facing however is that the annual -- the free cash flow you're suggesting in your guidance the $1.3 billion over two [ph] years, let's assume that's annualized. Your enterprise value is $12.4 billion. If you can sustain that and then go to maintenance capital, the metrics required to justify material upside to the share price are pretty challenging even at 1.3 billion cumulative two-year free cash flow.
In other words, if you do a DCF on what your trajectory looks like, we're having a tough time seeing what -- how the industry positions itself as a deep value proposition. So my question is how do you see the free cash flow evolving? And what do you think you're sustaining capital is on a reasonable timeline assuming you've got the inventory to support it. So it's a bit of a detailed question, I understand that. But the issue is, how do we show the value proposition because a $650 million annualized free cash flow number doesn't get your $12.4 billion enterprise value?
Yes. Well, first of all, I mean, obviously we look at multiple financial metrics, Doug, you know, free cash flow is important, but as is corporate returns. And our commitment is that as we allocate incremental capital to the business that it is going to be accretive. Those dollars will be accretive to driving those cash returns on invested capital higher. Hence, when we look at it from 17 to 19 on even a price normalized basis, we've had a 50% improvement and our cash return on invested capital.
I think from a value proposition standpoint when we kind of look at the metrics that matter and we look at pre, post dividend even free cash flow yield for ourselves, we feel that does compare very favorably for similarly sized industrial companies within the S&P 500. So, we believe that the value proposition is one a high rate of change on corporate returns coupled with the ability to generate that free cash flow at relatively moderate oil pricing that essentially delivers the yield that is competitive with the broader S&P space. And we believe that's a recipe for success and competing for forward investment.
And of course, the key thing is being able to do that consistently. Because you really can't talk about returning cash to shareholders until you actually generate the cash. And that's what we've been doing for the last two years. And so, I think we've got the track record. I think from a value standpoint, if you look at returns, if you look at free cash flow yield and our return of cash to shareholders, I think there is a very valid investable thesis there. And now, I'm talking specifically about Marathon, there are some broader issues within the sector that we can probably talk about on another day.
Appreciate, you trying to answer the question. Thanks a lot, Lee.
Our following question comes from Paul Sankey.
Hi, Lee. Thanks. Actually Doug and I are on the same track. But I wondered how you think about the potential for a CapEx cut and levels of sustaining capital as sort of part of that same question effectively. For example, in 2020 what would you say is your growth capital versus your sustaining capital? Thanks.
Yes. Well, first of all, given that we have a relatively low enterprise breakeven WTI price well north of -- sorry, well south of $50. We feel that, we have the resilience even with where the current strip looks today to execute our business plans, drive returns and drive free cash flow. So, today even though we have the flexibility to adapt, we don't believe that we're in a price band that would require Marathon to take that kind of move. If we do see sustained pricing that just below that enterprise breakeven, we feel that that is a longer term outcome. Then we have a lot of levers available to us to dial back capital.
And I think you've seen from our past history, we've been very disciplined around our capital. We set our budget. We adhere to that budget and any potential for upside price performance we simply drive that to the bottom line and basically produce more free cash flow. I think from a maintenance capital standpoint, obviously for us when we look at improving capital efficiency over the next couple of years that's a bit of a moving target and it's clearly impacted by the activity in the previous year. But we are well south of $2 billion probably in that kind of $1.8 billion kind of range on maintenance capital going forward.
That's very helpful. I've got a really quick specific, I apologize specific modeling question then I'll ask -- try for a final question with a very big one. Is there a production impact from REx appraisal drilling incorporated in the 2020 volume guide?
Yes, there is. It's obviously highly risked, Paul, because we -- this is still an exploration program and it's relatively de minimis.
Thank you. And then the big one would be, again a follow-up to the idea of attracting general aspects of sector. Is there potential for you to do a big merger, a big deal something a real big calculus move? Lee, I'd be very interested about your thoughts? Thank you.
Yes. Well, I guess right now, we believe that the right catalyst is consistently delivering corporate returns and free cash flow and getting that cash flow back to shareholders that we believe that is the right strategy, the right mechanism to attract that investor back. As I've said, I think in a previous question, the work we've done on our portfolio, the success that we're having with our resource capture framework, that model is designed to ensure that large scale M&A is not required for our forward success.
And obviously, again, as I stated any inorganic opportunity whether it's large or small has to be looked at through a lens of financial accretion, free cash flow accretion, balance sheet accretion, natural synergies from a portfolio standpoint, as well as overcoming potentially social issues. So, there are pretty significant barriers for that. And even just a general sense. But for us specifically we've tried to ensure our model delivers on the investor mandate without a requirement for pursuing that.
Thank you, Lee, to be very clear here. Thank you.
Our next question comes from Neal Dingmann.
Good morning, Lee and team, my first question centers on your Bakken play. Just wondering looks like for the quarter for 4Q, your NGL and gas production the plate grew about 30% sequentially, while the production for oil was down a bit. I'm just wondering, was that due largely to the processing capacity coming online? And could maybe in conjunction with that just speak to your expectations for oil cut for that play going forward?
Hey, Neal, it's Mitch. The way you've characterized it is accurate. As you well know, the renaissance in the Bakken and the increased productivity drove increased activity and it's taken a little while for the midstream infrastructure to catch up. There has been a lot of infrastructure added in the back half of 2019 and that will continue through 2020 and early into 2021. So, you're seeing the benefits of that relative to our mix. We would expect to see increasing infrastructure that impacts our ability to capture even more of that volume. However, as we've guided, we also expect for the Bakken to deliver oil growth in 2020.
Got it. Okay. That's clever. Thanks Mitch. And then my second question, really, Lee, just more on what the guys have been talking about. Just wondering how do you balance when you think about balance in the shareholder return with the resource play exploration capital spend? And just secondly, I'm just wondering, how do you determine how much of cash -- when you have free cash flow especially though if prices go down, how do you allocate that between the two. Does that impact exploration? Or after you decide that you want to pay out a requirement amount or how is that sort of balanced?
Well, I think first of all, in the REx program, to be successful long term you do have to have a bit of a constancy of purpose. We've talked about a longer term run rate of a $2 million in REx over time. We believe that that type of investment within that resource capture framework that I described earlier will allow REx to deliver the type of resource and inventory that we will ultimately need to replace what we're consuming. So, there's a little bit of I guess reverse engineering is the way I would put it to come to the amount of investment.
Now, they're going to be put and takes in any given year. We saw some large investment years as we established the two actual acreage positions. Now, we're back really at a kind of a couple hundred million in run rate. From a return of capital standpoint, we have to really strike the right balance between obviously shorter-term returns, free cash flow generation, but also meeting these strategic objectives which are continuing to replenish our inventory and that's part of the balancing act.
Today, we certainly feel that the repurchase of our shares based on valuations is a good return and a good use of capital allocation. And it's simply again striking the balance between that and longer-term value creation that exists within the resource capture framework.
That's clear. Thanks for all the details guys.
Our following question comes from Brian Singer.
Thank you. Good morning. I wanted to pick up on that topic of asset sustainability and breakeven oil prices. Can you talk a little bit more about the reserve bookings for the year and provide any more color there in terms of percent-proved developed notable revisions that impacted the reserve replacement in finding and development costs. I was going to ask how that influences your thoughts on inorganic growth, but since you've talked about that maybe you could talk about what your expectations are for reserve replacement and F&D costs from this year's budget?
Yes. Hey, Brian. Let me at least take the first part of that. With regard to reserves, I think it's important to remember that reserves kind of follow the capital, both what we spent in 2019 and what we have in our forward plan. And in this commodity price environment as you've heard all morning here, we're allocating to drive return enhancement and that means a lot of capital going for the oil. You'll see that in our growth rates, with oil growth rates exceeding, equivalent growth rates 70% of our capital would go into Eagle Ford and Bakken, very oily assets.
And really what you see -- as you peel the layers back on our headline reserve numbers is that our reserve placement ratio for oil was well over 100%. This year even though it may boe basis be below that. And then of course in our press release we had some F&D calculations in the appendix there. The headline number is $26 a barrel, but there are some fairly significant things to know about that. We reduced capital and our Ford plan much like we did in this year's budget and almost exclusively coming out of the gas here areas in Oklahoma and that had a fairly significant north of $7 impact on F&D.
And then there are some PDP tails that come down with lower pricing, lower SEC pricing again, largely gassy. That was almost another three dollars. So if you account for all that you can get to an F&D number, that's in the $16 to $17 range which is a little bit higher than our historic three year average, but pretty much closed on trend. And when you consider the oil content, there was pretty strong.
Great. Thank you. And then my follow-up is with regards to the Eagle Ford. You talked about some strong well performance, the best two quarters from a 30 date oil rate perspective. A, do you expect those wells to have and the performance of those wells to have? And the performance of those wells to have proportionate impact on EURs? Or should the post 30-day decline rates pick up based on either where or how they've been drilled and flowed? And then B, how do you view the depth of the remaining inventory relative to the results that you've been highlighting here for the last six months?
Yes. Hey Brian, it's Mitch again. With respect to your first question there's usually some benefit to EUR from modern completions and seeing this record IP30s, but we're going to need longer dated production to prove that out or to quantify the ultimate impact. I would say as a more general statement, the initial IP30 uplift is a little bit greater than the EUR uplift across most of our plays. But we typically do see an EUR benefit as well. To your latter question I think this one is probably the most important one. We currently talk about a decade of remaining inventory in the Eagle Ford at the current levels.
And I want to make really clear a couple of things that we're working on in the organic enhancement space are additive to that. The old adage, "Big fields keep getting bigger," certainly proving out for us in the Eagle Ford and Bakken where we've replaced the inventory. We've consumed the last couple of years. We've got a fair bit of activity on the redevelopment front in the Eagle Ford. We're targeting areas that were originally developed on wider spacing with early Gen completions. We now have sent seven successful pads under our belts with 100 percent success rate, spans over an area of about 25 miles east to west across our position and with the early encouragement there we've identified hundreds of remaining opportunities that we're working to prove up.
And just to be really clear, that's in addition to what's in our current PD of about 10 years of inventory. On top of that, we're well into phase two of our EOR pilot. That particular pilot is a multi-pad pilot, but we'll go through sequential cycles of missable gas injections so can flow back. We've got three cycles to-date. Completed on that that are in line and slightly exceeding model expectations. And I think what we can say from that very clearly is there's no question that the physics work across the black oil window in the Eagle Ford. And the Eagle Ford has some particular fluid characteristics and geologic characteristics that make it advantaged to most basins.
We'll continue that pilot looking to validate model results and inform, how we might expand that to a broader scale, look at optimization of the cycle parameters and durations and then refine program economics, so that we understand fully how that's going to compete within the broader portfolio which is already rich with a lot of top tier opportunities. So I think when we look at what we've already delivered in the Eagle Ford through organic enhancement uplift and additions and the excitement around both of these opportunities going forward, still a lot of running room in the Eagle Ford for us.
Great. Thank you.
Our next question comes from Jeffrey Campbell.
Good morning. Lee, it looked like that the return of 2019, the return of capital to shareholders exceeded the full year 2019 organic free cash flow generation. I was wondering about the thought process there and with ample cash on the balance sheet currently is this something that could be repeated again in 2020?
Yes. In general, Jeff, what we have talked about is that organic free cash flow is going to be the governor on incremental return of capital back to shareholders. Obviously, we can't perfectly match those. But in general, when you look at our organic free cash flow across 2019 post dividend, which was about $410 million. We actually did $350 million-ish and share repurchases on that basis. So you should expect those to be in lock step with one another. Obviously, there'll be some puts and takes across quarters. But generally speaking, that's the philosophy. We're not going to obviously spend money that we don't have. And we certainly are going to do damage to our investment grade balance sheet.
Okay, great. Thank you. My other question is on Slide 16, I noticed that the Marjorie and Lloyd wells were described as infills since the results were strong. Can you provide some color regarding the parent wells on the pads, vintage [ph] and spacing would be of interest?
Yes Jeff, I'm not sure I can recall all the specific details on the parent vintage. We can certainly get back to you on that. But these were two pads on four-well per section. And as I recall performance was pretty well in line with parents and certainly very strong returns as we've fine tuned our approach across all of Oklahoma and really driving significant improvements in capital efficiency across our entire position there.
Well, let me just follow up then, because I think that the question is there's been a lot of talk about parent child degradation. Sounds like from what you just said that there was not a lot of degradation in these child wells relative to the parents on the pads. Is that fair?
Yes. That's fair. And there's a lot of work that goes into optimizing our development approach here. And looking carefully at both landing zone, completion style and well spacing all contribute to that. We've made some really important inroads on all of those elements over the past few years.
And if I could just follow-up on that slide with one more question. I noticed in the footnotes that it looked like you were suggesting that the well cost was less than $5 million. Do you happen to remember what the average lateral lengths were on those wells?
I think they were 7500-footer, Jeff. If that's incorrect, we'll get back to you and correct that.
Okay. Yes. Looks like a really competitive cost, which is why I was asking.
Yes. No Jeff, you're spot on one of the reasons beyond the productivity of the wells that we wanted to highlight the Marjorie and Lloyd pads was in fact the ability to drive the completed well costs lower and even on a normalized basis you can see that the costs there are very competitive. And as you point out in the footnotes, the actual costs are very impressive as well.
All right. Thanks for the color. I appreciate it.
Our final question comes from David Heikkinen.
Good morning guys and thanks for taking the question. Your operating efficiency last year added 10% to 15% more wells than the original plan and your CapEx was in line, given your efficiency and savings. As you think about the plan this year, you talked a little bit about efficiency and savings. Would you would you increase your well count again? Or what's the outcome in 2020 and 2021?
Yes. Well, David, certainly we tried to provide some guidance within the deck on notionally the range of growth operated completed wells we expect for the year. Clearly, we've taken the efficiency gains that we've seen on both the drilling and the completion side, which have been substantial in 2019 and those have been of course applied into the forward plan. To the extent that we continue to see further improvement on top of those assumptions we'll obviously have to moderate and pace our activity accordingly.
But from our standpoint it just goes back to our budget is our budget. We will optimize always within that budget. But that's our development capital number, the 2.2. And to the extent that we see more efficiency, we'll have to accommodate that within that $2.2 billion budget.
So you spend the money on drilling and you just get more wells as opposed to returning to shareholders or building more cash balance?
Well, obviously we want to make sure that we deliver across all of our commitments, David, we want to make sure that we're delivering first and foremost on returns the free cash flow generation and then obviously getting it back to shareholders. And in many most respects the volume metric is just an outcome of that of that process.
Maybe I'm thinking about last year wrong and if you had those savings and the efficiency you could have delivered a lower budget and better cash returns, but you'd made the same CapEx plan and delivered more wells instead? Am I thinking about that wrong?
Well, I think that one of the other though advantages was we still had investment opportunities that allowed us to continue to drive our corporate level returns higher. So we did have good investable opportunities that were represented even by that bit higher well count and we felt that that competed very favorably against returning some of that back to shareholders, which again we still returned $350 million back to shareholders on share repurchases and another $160 million on dividend. So over $500 million back to shareholders last year.
Yes. You you'll have a great track record of free cash flow. I was just trying to answer the question of more free cash flow that it seemed like others were asking about earlier. So, thanks guys.
This concludes the Q&A session. I will now turn the call over to Mr. Lee Tillman for final remarks.
Thank you. I'd like to end by thanking all of our talented and dedicated employees and contractors, who made 2019 another year of differentiated execution for our company. They are collectively our sustainable competitive advantage. Thank you for your interest in Marathon Oil. And that concludes our call.
Thank you ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.