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Marathon Oil Corp
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Welcome to the Marathon Oil Corporation 3Q 2018 Earnings Conference Call. My name is Christine and I will be your operator for today's call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. Please note that this conference is being recorded.
I will now turn the call over to Guy Baber, Vice President, Investor Relations. You may begin.
Thanks, Christine, and thank you to everyone for joining us this morning. Yesterday, after the close, we issued a press release, slide presentation, and investor packet that address our third quarter results. These documents can be found on our website at marathonoil.com. Joining me on today's call are Lee Tillman, our 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 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 to Q&A
Thanks, Guy, and thanks again to everyone joining us this morning. Third quarter was once again highlighted by differentiated operational execution across our multi-basin portfolio, underscored by our unwavering commitment to capital discipline. It is this foundation that is leading the delivery against our major strategic priorities, compelling improvement in corporate returns and cash flow per debt adjusted share, organic free cash flow generation, ongoing resource capture and enhancement, and additional return of capital to shareholders.
Specifically, for the third quarter in a row, we have again raised our guidance for annual improvement in both corporate cash return on invested capital and cash flow per debt adjusted share. And with no change to our original $2.3 billion development capital program, we have raised our annual resource play oil and boe production growth guidance for the third consecutive quarter. We began this year by budgeting on a conservative price outlook of $50 WTI. And as oil prices have outperformed our plan, we have remained disciplined and we have maintained our focus on differentiated execution. Our capital budget is not a suggestion. It is a commitment upon which we must deliver. We are not chasing higher prices by ramping our spending, rather through superior execution and capital efficiency, we are driving meaningful corporate returns improvement and are delivering significant free cash flow for our shareholders. This is our model for 2018, for 2019, and in the future.
Our organic free cash flow generation during third quarter was robust at $320 million bringing the year-to-date total to over $630 million. This coupled with our peer leading balance sheet further enhances our financial flexibility and allows us to support an all of the above strategy that balances enhanced return of cash to shareholders with low-cost, high-return resource capture. And we are confident that we will continue to successfully accomplish both objectives in the current environment.
All of uses of capital are tested against our returns-first orientation. And with our shares trading at a discount, we have now repurchased $500 million of our own stock this year leaving $1 billion of buyback authorization outstanding. This supplements our already peer competitive quarterly dividend. Year-to-date, we have returned over $600 million to our shareholders through the combination of our dividend and share repurchases.
Looking ahead, we will remain disciplined and thoughtful with our approach to future stock buyback activity. Our actions will continue to be guided by our focus on returns and our pace governed by our sustainable organic free cash flow generation.
We have also maintained our focus on resource capture and enhancement, primarily through three complimentary efforts, organic core extension in the Eagle Ford and Bakken, small bolt-on acquisitions and trades such as in the Northern Delaware with the recent BLM lease sale, and our resource play exploration program. We recently spud our first exploration well in the emerging Louisiana Austin Chalk play with results expected in 2019. This multipronged approach provides a sustainable framework for ongoing resource base improvement with a focus on full cycle returns and without the need for any large scale M&A.
Recognizing that M&A has been very topical recently, our extensive portfolio transformation that has created a differentiated position in the four best U.S. resource plays means the hard work on our portfolio is behind us. We are now capturing the advantages of our multi-basin model and are focused on execution at scale. Large scale M&A is not a consideration nor is it required for our future success.
So let's turn our attention to some of the numerous highlights for third quarter and not surprisingly, excellence in execution was again our primary theme. We exceeded the high end of our total company and resource play production guidance while our development CapEx declined 8% quarter-on-quarter. In the Eagle Ford, our asset team continues to set the standard, where our capital efficient execution and advantage pricing are driving some of the best financial returns in our industry.
Our third quarter production in the Eagle Ford was up 8% sequentially. Although our objective entering the year was to hold our Eagle Ford production relatively flat, on a year-to-date basis, oil production is up 10% from the prior year on 10% fewer wells to sales. Capital efficiency has been impressive as we are effectively doing more with less. A significant driver of our outperformance has been the impressive results we are achieving outside of Cairns County in the extended Atascosa County core.
In the Bakken, we continue to deliver industry-leading results while simultaneously extending the core of our acreage position. During the third quarter, a 6-well pad in West Myrmidon achieved an average 30-day IP of over 4,700 oil equivalent barrels per day at 73% oil cut. This pad included three new industry record Three Forks wells highlighted by the Jerome well, which establish a new Williston Basin IP 30 record of around 4,800 barrels of oil per day, one of the best oil wells ever completed in the North American resource plays.
Importantly, we are delivering these results alongside an intense focus on capital efficiency as evidenced by our average third quarter completed well cost per lateral foot falling 20% below the trailing 12 month average; truly remarkable execution from our teams and an example of working both the numerator and denominator of capital efficiency.
We also took another important step forward in our core extension efforts to dramatically uplift the quality of our Bakken inventory delivering a strong two-well pad with our first enhanced completion test in the southern part of our Hector acreage. This success follows the consistently strong results we have realized across the northern part of Hector in addition to our successful second quarter test at Elk Creek. Our core extension efforts will continue as we plan to test enhanced completions further southwest in our Ajax area before the end of the year.
It is difficult to have a conversation about the Bakken without addressing recent pricing volatility at Clearbrook. So, let me make a few comments. While we expect differentials to improve with the return of Midwest refiners from heavy maintenance and as incremental barrels begin to move on rail, it is important to understand that we have broad diversity of offtake out of the Bakken to several end markets, and we purposefully maintain flexibility to respond to market conditions. We believe basin pricing will improve near term and over time stabilize to the marginal cost of transport to coastal markets, similar to pricing seen throughout most of 2018.
Further at a company level, a key competitive advantage of our multi-basin model is our exposure to varied end markets for our product, with approximately 50% of our production linked to premium LLS and Brent pricing.
In Oklahoma, third quarter marked the successful transition to multi-well infill pad development. In the overpressured STACK, we are optimizing our development approach at the DSU level to deliver more predictable, more efficient, and highly economic results at various spacing solutions. Both the Irven John infill at four wells per section spacing and the HR Potter infill at seven wells per section spacing are exhibiting very strong early performance, and were delivered at an average well cost 15% to 20% below the parent wells.
Amplifying this quarter's performance, longer term production from our 4Q 2017 Tan overpressured STACK pad at nine wells per section spacing is 40% above type curve at 270 days. In the SCOOP, we delivered two more highly economic Woodford wells following the success of our 2Q 2018 Leitner infill at eight wells per section spacing, which is now trending 70% above type curve at 120 days.
Turning to the Northern Delaware. We are strategically advancing our position and preparing for future development as we further core up our footprint, HBP and delineator acreage, capture efficiencies, improve our cost structure and secure midstream solutions. We are making tremendous progress on multiple fronts highlighted by a 50% increase in completion stages per day versus the trailing 12 month average, and a 20% increase to our gross company-operated well locations through bolt-ons and trades since entering the play in 2017.
We are also realizing very encouraging early development drilling results, including a recent three-well upper Wolfcamp pad in Malaga that achieved a 30-day IP rate of about 540 boe per 1,000 foot of lateral at over 60% oil cut. Outside of our four resource plays, we continue to deliver tremendous value from our world-class integrated gas development in EG, which contributed around $190 million of EBITDAX during the quarter.
In summary, third quarter results have again demonstrated the strength of our returns-driven, multi-basin model. We remain solidly on track to deliver a strong rate of change in our key financial performance metrics highlighted by an 85% annual improvement in cash return on invested capital at $65 WTI, while also delivering meaningful free cash flow and enhanced return of capital to our shareholders.
As we look ahead to 2019, rest assured that our framework for success will not change. We will remain focused on improving our corporate level returns and growing our cash flow per debt adjusted share. We will protect our financial flexibility and our peer-leading balance sheet. We will remain capital disciplined and set our activity levels to generate sustainable free cash flow at a conservative oil price, and we will return additional capital to shareholders while also maintaining our focus on ongoing resource-based enhancement that generates full cycle returns. In our framework, high-value oil growth is simply an outcome.
The proof points of our commitment to the strategy lie in the strength of our year-to-date results and the discipline we've demonstrated and in the free cash flow we've delivered. We believe the successful execution against our framework has already begun to differentiate us from our peers as industry discipline has frayed amidst higher prices. And we fully expect this differentiation to continue with our peer-leading execution amplified by our advantaged multi-basin model. Thank you.
And with that, I am happy to turn the call over for Q&A.
Thank you. Our first question is from Ryan Todd of Simmons Energy. Please go ahead.
Great, thanks and congratulations on the quarter. Maybe if, just to start out, as we're looking at 2019. I mean I think you've been pretty consistent on your priorities over the course of 2018 when we think about how you like to manage, to balance organic growth versus free cash flow generation and cash return to shareholders in 2019. Can you give us a little, some rough framework around how to think about organic spend and, or activity levels into 2019.
Yeah. So absolutely, Ryan, again as I said in my opening remarks, we're, you should expect no surprises from us in 2019 as we get prepared to release our capital budget in February of next year. Obviously we're still busy integrating all the performance data from this year and our multi-based and optimization but just a few things that you can take away in terms of the framework.
It will be returns first with a commitment to capital discipline, no different than this year. We think that's differentiated us this year and that, that approach we'll continue to do that in 2019. I think this year holding our budget essentially unchanged while still being able to essentially raise our resource play production guidance across three consecutive quarters is notable.
But specifically we're going to look to drive a strong rate of change in our corporate returns and cash flow per debt adjusted share and we're going to look to set our 2019 activity levels to deliver organic free cash flow on a conservative oil price deck.
Our objective is sustainable, organic free cash flow that can support an all of the above strategy and that's going to include incremental return of cash to our shareholders as well as opportunistic resource capture. For us, it's not an either/or proposition. Production growth, as I already stated in my comments, is going to be an output of our process and we are going to be very much focused on high value oil growth because that's where our margins are being generated
Thanks, Lee. Maybe a follow-up question on STACK. It's got a lot of attention lately from various peers across the space. I mean, you're showing some strong results from your recent spacing tests across a variety of Williston Basin assumptions. Can you talk a little bit about your latest thoughts on the play, base-case, spacing, and maybe how we should think about activity in 2019 in that play maybe both in terms of amount of activity and whether it will remain concentrated in the overpressured window? Thanks.
Sure, Ryan. This is Mitch. And, we've been talking for a couple of quarters now about the transition to development mode in the overpressured STACK and in the SCOOP. We've been integrating data from our own activity and from industry. We're applying some advanced seismic processing techniques to help guide the combination of well spacing, landing zone and completion design. And it's the intersection and the combination of all those factors that we're starting to hone in on. And, evidenced by the last three pads in the overpressured STACK are on different well spacing with some differences in completion design as well, but delivering very consistent results. We're going to continue, as we've kind of highlighted in the Oklahoma slides, continued development in the overpressured STACK and SCOOP. You see a number of upcoming pads there.
So, we would intend to stay with that philosophy to continue to leverage the learnings and the application while we're driving well costs lower. We reported 15% to 20% lower on those two specific pads were actually seen improvements in the last quarter across the entire basin that are even above that. And we continue to drive capital efficiency both from the well performance side and from the well cost side across all of our basins. So you should see continued activity with our focus on development in both the overpressured STACK and SCOOP as the majority of our program going into 2019.
Yeah. And maybe just to add there, Ryan, as well, clearly, those two areas are fully in development mode. The team is striving for predictability, consistency, and higher returns. But we're going to continue obviously our delineation and appraisal efforts that go across the entirety of the play as well as we go into 2019.
But what's the average cost of oil there in the play now?
Well, there's multiple plays there, Ryan. We've got various lateral lengths, we've got various pressure regimes that we're drilling in, so we would have to get down to a very granular level. And, I don't have all of that sitting right in front of me. There's a number of different well types, lateral lengths, and drilling and completion designs. So there's quite a range there.
But I think what's probably notable is the comment that Mitch made earlier, Ryan, about we have already relative to the parent wells taken a significant step down. Are we fully where we want to be yet? No. We still have, in our view, there's still work to be done there to improve the capital efficiency and we're, as we do more of this, we're going to get better at it, just like we are in Eagle Ford and the Bakken, where we get a lot more at bats.
So I'm very encouraged. I think the combination of productivity and a focus on well cost is going to make the STACK and the SCOOP very competitive in our portfolio.
Great. Thank you.
Thanks, Ron.
Thank you. Our next question is from Arun Jayaram of JPMorgan. Please go ahead.
Good morning. Lee, I was wondering if you could give us any high level thoughts on just capital allocation between the different basins in the U.S.
Yeah. As I stated, we're a little early in the process to get down to a basin level that's clearly going to be a part of our February capital budget release. And as I stated, we've got an immense amount of very positive data to incorporate in our planning cycle this go around.
What I can tell you is with the results that our asset teams are achieving today, all of the basins are competing well for capital allocation. We're going to remain very focused on corporate returns and we want every dollar of our development capital budget to move that key financial metric in the right direction. At a very high level, you should expect the Eagle Ford and the Bakken to continue to receive the majority of our total resource play capital. That's where we're seeing the best returns and the best capital efficiency. And just for your reference, this year, those two basins were about 60% of our capital allocation in 2018.
But as you can see in the 3Q results, Oklahoma and Northern Delaware are delivering strongly and their going to compete for capital even though they are less mature and much earlier in the development cycle. Strategically it's going to be essential for us to continue to fund those two assets for things like leasehold, delineation, appraisal, and early pad drilling so that we keep them on the correct trajectory going forward.
The one other thing that I'll mention too which kind of fits in the context of just capital allocation and in totality is that directionally, we also view that our REx spend, our resource play exploration spend, will also be trending downward as we look forward into 2019.
That's very helpful. And just a follow-up, could you give us a little bit more details on, I know it's a scheduled turnaround every three years, but give us some thoughts on the capital for that turnaround and the cash flow impact and production impact.
Let me start, Arun, by talking about the turnaround activities and as part of our normal long-term maintenance program, we have a major turnaround like this every few, every three years or so. And if you look back to Q1 of 2016, you'll see sort of a similar type of event. It involves long-term preventative inspections on our rotating equipment there, requires a full field shut down for a period of time in this case, along with vessel inspections and the typical kind of maintenance work we do to ensure the world class reliability that we deliver from that asset and have delivered over the past decade plus.
In this particular turnaround, we'll also be taking advantage of the shutdown to perform some, pre-install some tie-ins. As we've talked about we're progressing agreements to bring additional backfill gas through the facilities that we have on Punta Europa. We continue to progress those and we're going to take advantage of this turnaround to make those preemptive tie-ins. You shouldn't view the capital or cash expense related to this turnaround as meaningful in the context of the corporation or even our international operations but production-wise we have, I think if you reference back to the 2016 we saw 10% to 15% impact on the quarter and that's probably a good guide as we go into, for this event in 2019.
All right. Thanks a lot.
Thank you. Our next question is from Paul Sankey of Mizuho. Please go ahead.
Good morning, all.
Hi, Paul.
Lee, hi. The criticism that we hear of Marathon typically, or the worry, is that you're short of inventory. Can you address that for us please and give us what your version of that critique is? Thank you. Your counter, I should say.
No. No. Absolutely. I think from our perspective when you look at the extensive portfolio transformation work that we've done, the differentiated position that we we've established in for the best U.S. resource plays, we feel very confident that our current resource base is both high return and high quality. And, as I mentioned in my opening remarks, even with that, we are continuing to progress a multi-pronged approach to continue to even enhance that very strong base. And we've talked about a few of those.
It really starts with some of the organic enhancement activities that are already producing fantastic results in the Eagle Ford and the Bakken. The net effect of that is to extend the life of that inventory. We've talked about small and very selective bolt-ons in places like Northern Delaware. The fact that Northern Delaware, we're up over 20% on gross co-op locations since we did the original acquisitions back in 2017; and that's through trade, some acquisitions, and even the most recent New Mexico BLM lease sale. And then, we have our resource play exploration program, which certainly offers the potential to generate outsized returns based on very low entry costs. It's certainly still exploration and we need to always come back to that. But with all of those efforts ongoing in parallel, we feel very comfortable that we have a comprehensive strategy in place to replenish and improve our resource base, and that does not include large-scale M&A.
I had a follow-up, but actually, you just answered it right there. So, I'll leave it there. Thank you.
All right. Thanks, Paul.
Thank you. Our next question is from Doug Leggate of Bank of America. Please go ahead.
Thanks. Good morning, everybody. Lee, I'm not sure if you or Mitch want to take this one, but it's a question back to the spacing in the STACK if I may. Looking at what some of your peers, the difficulties they've had, I'm sure you're familiar with what Devon has been saying about moving back to a sort of four-well per section type of spacing unit. And you guys seem to be knocking it out of the park on nine-well spacing. I'm looking at the Tan infill. Obviously, the, I guess, the HR Potter, however you want to put it, to coin that phrase is pretty consistent again beating the type curve. But, I'm looking at the variability in the geology and I'm just trying to understand what are you guys doing differently? Because it looks like you've kind of cracked the code here as it relates to your performance relative to your peer group. So any color you can offer on how you're managing to meet these wells would be great? Thank you.
Sure, Doug. This is Mitch. Again, we talked a few quarters ago, we came back and talked about the tailored approach to development strategy and completion design across the STACK. And, I think we were one of the first to come out and say on the far eastern edges, it would be less than six wells per section. And it would be in the heart of the play where we see the best geology, the thickest section and some pressure we would expect to see instances of greater than six wells per section.
I think our results over that time period would prove that out and it looks like industry is kind of centralizing around a similar view that we've been talking about. I think if you look at how we're approaching that without getting into the specific recipe, I would say a couple of unique advantages that we're applying. The database is basically the same for all players, more or less.
The art comes in how you integrate that data in looking at the interplay between well spacing, well landing zone and completion style. We've got over a decade of experience, well over 2,000 horizontal, unconventional completions. We've got a centralized model that allows us to quickly transfer those learnings from one basin to another. And we've got an attitude within our teams that is to never be satisfied with what we did yesterday. So an attitude that's focused on making sure we capture all the learnings not only from our own work but from outside activity.
I mentioned earlier we are doing some advanced seismic processing. We're using that work to target specific zones within the Meramec, across the pressure windows and across the geology, which helps us target the wells in the right interval, and we think is helping guide us to the right spacing specifically tailored to the sub-region and in many cases down to the DSU.
Yeah. And I think, Doug, just from my perspective, we have, as Mitch stated, we've been a proponent of, it's not going to be one size fits all across this play. We have really focused our attention on areas that we feel that we have the predictability and the consistency, these higher competence development areas like the overpressured STACK and the SCOOP Woodford. That's not to say that there still aren't areas within Oklahoma and even secondary zones that we still don't need to understand and bring that same level of competence to.
And so, I think what you'll see in 2019 is a mix of both of those, both the development pads that we've really started talking about this quarter but also continuing to progress our knowledge base in other zones and other areas of the play that we hope to move to field development in the future.
Guys, I appreciate the answer. If I may try and characterize it as a kind of quick follow up here. So are you at the point now, if each development area is a kind of bespoke well-design, how much running room do you have now in terms of line of sight to call this a transition from early development to full field development. Are you ready to move into the full field development mode here yet?
Yeah. I think for the two areas that we just addressed, Doug, which are the overpressured STACK, specifically the Meramec and the SCOOP at Woodford, that is where we are today. We view those as kind of the foundational elements moving into 2019 and we would intend to hang our appraisal and delineation work around those two development areas.
Okay. Last one from me. It's the same topic I'm afraid. The type curve, was the type curve a parent curve or a fully developed average curve for your parent/child assumptions going forward? I'll leave it there. Thank you.
Sure, Doug.
I'm looking at the 1575 MBOE, is what I'm looking at. 1525 MBOE, sorry.
Yeah. 1525 MBOE, I think, yeah. We've had that type curve out for quite a while as you know and we have tried to put type curves out there that are a blend of parent and infill wells in forming that type curve and to describe what we would view as our mean or average expectation across that particular type curve area. So you can think about it as a blend and as an expectation for what we hope to deliver. But, we're going to continue to provide actual data to inform the construction of your own type curve as well.
Thanks, guys. It looks like this got some upside risks. I appreciate your comments.
Thanks, Doug.
Thank you. Our next question is from Jeanine Wai of Barclays. Please go ahead.
Hi. Good morning, everyone.
Good morning, Jeanine.
Good morning, Jeanine.
I guess just following up on some of the capital allocation and inventory questions, specifically in the Eagle Ford. Can you talk about how the year-to-date results have changed your view of the asset from a portfolio perspective? I think, specifically, did the delineation and improved well results really support adding a little bit more activity? Or given where you are with the other resource plays, should we think about the results as supporting a stronger case for the more than less approach that you mentioned?
Then, this is just because you made a, clearly, a lot of progress in priming the Delaware and now especially Oklahoma and, but your commentary you also reiterated that the Eagle Ford has some of the highest returns and it also provides pretty valuable cash that supports other parts of the business that don't necessarily generate immediate EBITDA?
Yeah. I think for us, Janine, the Eagle Ford is a very unique asset in the sense that it's relatively mature but we have now uplifted the value of a large portion of the acreage there that probably, not so long ago, we would have deemed as lower tier and likely not competing as strongly for capital allocation.
I think what that does for us is it gives us the flexibility to optimize the Eagle Ford to deliver what it needs to do within our broader portfolio. We can certainly grow the Eagle Ford if that's the role we want it to play or we can use it as you stated as more of a free cash flow, capital efficient engine.
Obviously, when we look at these plays and we look at how they fit into our multi-basin optimization, we're looking at many factors including maximizing the use of existing infrastructure to avoid further capital spend, say, on the facilities side. All of those things go into our calculus in terms of where we want to push capital.
But as you rightly say with the level of returns that we're seeing there, we fully expect Eagle Ford to compete very strongly in 2019 and beyond. Almost under any scenario, we see it generating free cash flow within the portfolio, whether that's on a flat production basis or a slight growth profile. But, the beauty again of the Eagle Ford is very capital efficient. It's a fantastic asset team. They continue to push the envelope on innovation and I think there's still a lot of excitement ahead in the Eagle Ford.
Okay. Thanks. And I guess my second question is on well cost. It sounds like you recently took an opportunity to lower cost by switching out a frac crew. As we look forward, what other opportunities are there for incremental well cost savings, whether that's through further self-sourcing and debundling or locking in maybe opportunistic attractive service contracts, or is it really primarily just on continued efficiency gains?
Sure, Jeanine. This is Mitch. The simple answer is all of the above, but I'll try to give you a little bit more context. As you rightly stated, we made an intentional decision in the Eagle Ford, which was completed in third quarter but, to swap out one of our frac crews to a different type of service model that allowed us to vertically integrate more of the commodities and supplies internally and self-source those. We're already seeing meaningful contribution to well costs as a result of that. We continue to press on the commercial relationships and partnerships, the efficiency side where we're seeing continued improvement across the basins in terms of pump time or a number of stages completed per day, drilling efficiencies are coming hand-in-hand with that. And, we continue to pursue opportunities that would expand using things like self-sourcing, also looking at local or more regional sand sources, which have a lower cost of transportation. So, it's really an all-of-the-above strategy, and our teams are intensely focused on the entire capital efficiency equation, both the well performance side and the well cost side. And so efforts across many of those spaces, and we still see opportunities to drive further improvement in our cost structure.
And I think, Jeanine, just on the commercial side of things, when we look at where we spend our service dollars, are really on the, obviously, on the drilling and the frac side. And, we have never had more diversity in our frac providers than we do today. We're seeing opportunities in the market to term up some element of our fleet to lock in some strong commercial terms. So, all of those things are coming into play to continue to allow us to drive costs down on a completed well cost basis.
The other thing I will just mention since we're talking about a little bit of the, a little bit of moderation in our wells to sales in fourth quarter is that in aggregate, we are still delivering wells to sales above the midpoint of our guidance for full-year, and all basins are also within their guidance. So, these are, some of the things we're talking about here are very normal variations in our cadence quarter-to-quarter. There's not some step change occurring here.
Okay. Great. Thank you for taking my questions.
Thank you. Our next question is from Bob Morris of Citi. Please go ahead.
Thank you, and congratulations, Lee, on a nice execution this year. Mitch...
Thank you.
...on, you've covered, certainly. Mitch, you've covered most the questions I had on the STACK, but just one quick question. Are you using choke management on these wells to sort of control when you cross over on bubble point there in the overpressured part of the STACK?
Yeah. Let me address that from a little bit higher level if I could, Bob, and I'll come back and answer your question specifically. But, the way I would characterize it is, there's some ongoing industry experimentation on choke management strategy, and really looking to understand the trade-offs, if any, between kind of returns based on fast flowback strategy, and ultimate recovery, and how that ultimately impacts overall capital efficiency. We obviously are monitoring that activity. We participate in a lot of that activity.
But generally, I would say we're operating with a moderate to slightly aggressive strategy. And we do that by integrating real-time, bottom-hole pressure data into our choke bumps, and use those in combination to kind of drive how we open up chokes on these wells. It's a bit early to reach the ultimate and final conclusion on this. There's a handful of pads with kind of two years plus history but the evaluation that we've done would not show any noticeable impact to EUR based under the different flowback strategies. So we think we've pretty well landed on how we're going to continue to operate these wells as we keep our focus on returns and don't, at this point, see any noticeable impact on EUR.
Okay. Thanks. That's helpful. And then my follow up is, in the Bakken it was encouraging to see the results on the two wells on the Lars pad. Were you surprised there that the Three Forks had a higher flow rate than the Middle Bakken that far south?
I think we've been surprised to the upside across Hector over the last several quarters and really impressed with the work that the team has done there to extend the core out of Myrmidon into Hector and of course we have the successful Elk Creek pad as well. I think you're fairly characterizing that the surprise in the Three Forks has been even greater than in the middle Bakken. But the overwhelming direction of those extension and activities have been positive and the Lars pad two wells are competing very well with kind of industry activity and peer activity out there. So, very encouraged by Lars. We're going to continue a few more tests down in the southern portions of Hector to confirm the overall extent of that. And of course we're on track to have our first test in several years in the Ajax area during 4Q. So more news to follow on that.
Yeah. We look forward to that. Thanks, Mitch. That's helpful.
Thank you. Our next question is from Brian Singer of Goldman Sachs. Please go ahead.
Thank you. Good morning.
Good morning, Brian.
Lee, you highlighted when you were talking about your decision to ramp up the buyback, that it was in part based on the relative valuation of your stock. And I wondered if you could discuss what essentially your second priority would be, i.e., how the capital would be allocated were the stock not trading at a discount?
Yeah. I think that given our returns-first orientation, Brian, that really is kind of the toggle switch for us to really start considering the share repurchase. And to the extent that we made that test and found that that was not competing adequately for capital, we have multiple other uses for that capital on hand. Clearly, we have many developmental opportunities that we could pursue if that was the right decision. We obviously have our work in resource capture. We talked about kind of this multi-pronged approach, everything from small bolt-ons to the activity in REx. And also bear in mind that REx will ultimately, we hope, have some wells go into predevelopment mode. And so there could be some funding requirements there.
We have already a peer competitive dividend that exists today; $170 billion a year of annual dividend. That's certainly an area that could also be tested to see if there was an action that needed to be taken. It's something that is assessed and evaluated each and every quarter in our discussions with our board, no different than share repurchase. Certainly from a from a debt standpoint, we did a fantastic job in 2017 reducing gross debt. We don't have a maturity until 2020. So really from a debt standpoint and a debt metric standpoint, we don't really see a lot of action required there but I think that's broadly how we would think through it, Brian.
Great. That is helpful. And then, my follow-up is actually a follow-up to Jeanine's question early on in the Eagle Ford. When you think about the opportunities to extend resourcing, you highlighted Atascosa County in one of the slides, how significant is that opportunity set from here? How significant do you see the potential for additional inventory and would those additional locations be consistent with the rate of return of what you're drilling now?
Yeah. Well, when we think about it from a risk inventory standpoint, Atascosa County obviously was already contributing risk inventory just at a lower economic value. The effect of the work that the Eagle Ford asset team has been to uplift that area and drive those returns even higher and so, we would expect that this is more centered around value and returns. It would have, obviously the net effect of extending that inventory performance over time at the same kind of run rate. So that's absolutely a positive there. And also, bear in mind, this is on a go-forward basis, our most underdeveloped area in the Eagle Ford.
Hey, Brian. This is Mitch. I would just add to that, in the release this quarter in the slide deck, we highlighted 28 wells across Atascosa year-to-date average IP 30 of 1,530. If you go back a little bit further, we have over 60 wells that we've brought online now across Atascosa with new generation completion. And the results across those 65 are pretty consistent with the 28 that we're reporting on here. So, we have firmly established, expanded a core, the expanded core, across Atascosa County at this point in our view.
Thank you very much.
Thank you. Our next question is from Scott Hanold of RBC Capital Markets. Please go ahead.
Thanks. Good morning.
Good morning.
What I think would be helpful and I think you guys have heard, a lot of questions asking about the Eagle Ford, and effectively running room I think is the basis of most of those. And, I think it would be helpful for us if you kind of step back and think, when you look at your resource growth over the last couple of years, it's been pretty fantastic and I think there's some questions on how much room does say the Bakken and the Eagle Ford have left. I know you're say, circa 30,000 below the Bakken's all-time Marathon high. I'm sorry, the Eagle Ford, the Bakken's at an all-time Marathon peak. How much more running room opportunity do you see to grow those assets over the next couple of years?
Yeah. Well, certainly, as we look at the Bakken today with this core extension that we've enjoyed in Hector as we hopefully push that even further, potentially even into the Ajax area, there's little doubt that from a high value oil growth standpoint, the Bakken is going to have a very material role to play for us going forward.
I think, as I stated earlier on the Eagle Ford, I think there we have the luxury of modulating the performance of the Eagle Ford to really maximize capital efficiency and the infrastructure that we have in the field; that could either show it more in a flat profile like we enjoyed this year, or could see it actually get back into a growth mode depending upon how the multi-basin optimization ultimately drives capital and return. So, a lot of flexibility, but our view is that the combination of enhanced well productivity, with the team's continued ability to drive costs even lower, that's a pretty powerful combination. And under any scenario, the minimum expectation is an uplift in economics and value. And, I think at the end of the day, the net result will be an extension of the inventory and time.
Okay. Understood. It sounds like more economic considerations than say, you know, worry about what it's going to grow at.
Correct.
And then, kind of going back to just some of the budget framework conversations. How do, you talked about being conservative going forward, how do you look at the oil price as you consider the budget from a long-term perspective? I mean I know you guys used $50 this year, but certainly, it feels like depending on whether we were eight weeks ago or today, what you use for oil price can, and what you think is conservative, can change. But how do you think about that going forward as you budget for 2019 and 2020?
And then, also, I don't know if Dane has some comments on how you plan for, to hedge the portfolio with that in mind.
Yeah. Well, first of all, you're right. For 2018, we had designed our plan to generate organic free cash flow in a conservative $50 WTI world. However, don't confuse a planning basis with a prediction of where oil pricing is headed. We remain bullish on oil pricing going forward. We think our weighting toward oil is the correct orientation. However, in our budgeting, you should expect a similar conservative basis moving forward into 2019 that will allow us to confidently generate sustainable free cash flow that again it permits us to deliver against this all-of-the-above strategy.
That basis, however, should not be confused with our view necessarily of where forward oil pricing will be. We want to provide plenty of headroom between our planning basis and where actual prices may be trending to ensure that we can confidently deliver our development program across a broad range of actual price outcomes.
Dane, do you want to say a few things maybe about, on the hedging and commodity risk side?
Sure, Scott. As we came into 2018 this year, we set a target of about 50% of our oil production to put a floor under. And as you know, we use three-way hedge structures to do that to preserve some of the upside. As we've gone through 2018 and become a fairly significant free cash flow generator, with $1.5 billion cash on the balance sheet and $5 billion in liquidity, it feels like we've got more flexibility as we head into 2018 to be less hedged, I'm sorry, as we head into 2019. And the hedges we have in place right now for 2019 are about half of the 2018 level. And I think we're going to be very slow to add to that, if at all. We're going to be very cautious. We've been more focused frankly on things like Permian Basis (55:00) (sic) [Basin] (55:00) hedging. So, I think we've done a nice job on. And, we'll focus more on that than probably fixed price hedging as we head into 2019.
That's real helpful. Thanks.
Thank you. Our next question is from John Aschenbeck of Seaport Global. Please go ahead.
Good morning and thank you for taking my questions.
Good morning.
So, there's been a lot of color provided on 2019 so far, which has been helpful, but I was hoping to touch more so on your longer-term benchmarks which you haven't updated since Q4 earnings in February this year. But clearly, your U.S. capital efficiency has improved significantly since that time considering you've had the three consecutive production guidance raises.
So, I was curious, when should we expect an update on those longer-term benchmarks? Would that come with formal 2019 guidance? And then if possible, I was wondering if there's any way to quantify the outperformance you've seen this year in the U.S. and what the implications are to your longer-term benchmarks. I suppose what I'm asking more or less is, if you could rewind to the beginning of the year and know what you know now in the U.S., what would your longer-term benchmarks look like or how much better would they be?
Yeah, yeah. Well, first of all, I want to maybe just make sure everyone understands that, that the long-term guidance that I believe you're referring to, John, is the 2017 to 2021 guidance that was really geared toward demonstrating the potential of the portfolio at that point in time on a kind of fixed or flat price assumption. And, it was really, again not a business plan but really just illustrating the potential of the portfolio. We'll continue to look at options to provide transparency on mid- and longer-term plans and that may be something we look at in 2019. But, we really start with the premise of being returns focused first. Again for us, those growth CAGRs that we were showing even as part of that case were an outcome of a process that starts with a corporate returns view as its starting point.
And so for us, again, we're going to be very focused and what you'll see in 2019 is very much a focus on where our high value, high margin oil production is going but that also will be an output of our overall returns-first kind of capital allocation philosophy. In terms of, can I project forward on how performance and capital efficiency this year will impact not only 2019 but even beyond 2019, that's still work that's ongoing today.
As you might imagine, one of the beauties of the resource plays is, we get new data and new performance information each and every day and that is being integrated and built into our modeling, really in real time. The other thing I would point out just on budget in general is that we've moved to a mode where capital allocation is something that is essentially dynamic. It's something that we have flexibility in. We will set a budget plan for 2019 but as we move through the year and see performance, as we see costs, as we see commodity pricing, we have ample flexibility in the multi-basin model to make changes and tweaks to that capital allocation all along the way. So, it's a point in time view. That's the way it will be. We'll always be focused on delivering our commitments. But our path to achieve those commitments is something that can flex a bit during the year.
Okay. Got it. Appreciate the color there, Lee.
Thanks.
So for my follow up, I was hoping to get a little bit, a little more detail around your high level approach to uses of excess cash going forward. Was wondering, is it fair to think that you'll keep proceeds from asset sales on the balance sheet for leasing, small bolt-ons, other small transactions like that and then match up your buybacks with organic free cash flow? And then keeping with buybacks, what's your appetite in regard to expanding that program once you move through the remaining $1 billion authorization? Thanks.
Yeah. I think, again, today, our view is that a discipline repurchase of our shares is a good use of capital and it offers very competitive returns given our current market valuation. The pace of that buyback is going to be governed or informed by our sustainable free cash, organic free cash flow generation. It, we do not want that program reliant on disposition proceeds. That is not the intent.
This year, we were able to leverage disposition proceeds to drive a very opportunistic and successful REx program. And in fact, we more than fully funded our resource play exploration activities with the proceeds that we received in second quarter of this year. Those disposition proceeds are still available for us to use as opportunities might present themselves and that would be our view going forward.
But the strength of our balance sheet, the flexibility of it, the ability to act quickly and decisively if the right opportunity, small bolt-on, lease. I mean, lease sale is a great example. We could go into the lease sale, be very selective, but also be very decisive about what we wanted to achieve in that lease sale because of the strength of our balance sheet. And we could do that while still also delivering against our share repurchase program. So, to be able to do both of those simultaneously, again it's not an either/or proposition, that's the model that we want to continue to progress as we move into 2019.
I would maybe just add one final thing too, John, is that you shouldn't expect an exact match between free cash flow generation and share repurchase. I mean, that's certainly a governor, it's certainly something that's going to inform our decisions around pace, but it will not be a, if you will, dollar-for-dollar match.
Okay. Great. Got it. That's it for me. Thank you for the time.
Thank you.
Thank you. Our final question is from Jeffrey Campbell of Tuohy Brothers. Please go ahead.
Good morning, and congratulations on the great quarter. Just a quick follow-up on the Oklahoma discussion. Based on your results today, do you agree with the, broadly with the notion that the Woodford supports tighter spacing than the Meramec?
Jeff, this is Mitch, again. And, I think if you're referring to our activities in the SCOOP, we would generally see tighter well spacing per landing zone there than in the STACK. But as we've talked about on a number of occasions, the design or the development approach in the STACK is going to vary based on variations in geology and reservoir quality and pressure. We see a bit more consistency in those parameters in the SCOOP Woodford. And so, yes, we would agree that average well spacing is likely to be higher in the SCOOP Woodford.
Okay. Thanks for the color. And yes, I was thinking about the SCOOP when I asked that question. Following up on this business of organic inventory because I thought something interesting came up in the call. Do you view the effort in the Williston southern extension area similarly to Lee's description of Atascosa, which sounded like previously acknowledged locations that are getting better, or are the evolving results creating, or potentially creating, new organic inventory in the Williston?
Yeah. I think we would characterize it largely similar. The improvement in value, the improvement in capital efficiency has been the primary benefit from that. We generally have carried risk inventory in our long-term plans for those areas but at a significantly different value than what we've been able to achieve. There may be some opportunities as we continue to try these new approaches to revisit that but you can think of them largely the same for now.
And, if I could just follow that up, that being the case, it certainly could be said that these locations are far more likely to attract capital in the current environment than they might have been in the way that they were viewed earlier. Is that fair?
Yeah, I think that is fair. And I could bring you back probably to the beginning of 2018 when we revealed our capital allocation for this year. There was some surprise in the market with how much we were dedicating to the Bakken but it was on the backs of the great technical work that our teams had done, the evolution and strong improvement in returns that we had seen from those trials to-date, and the confidence we had in moving those into other areas. So, but accurate statement for sure.
Yeah. I'd maybe just add to that, Jeff.
That's great. Thanks so much.
It's kind of interesting to me as we look at the Bakken today that we've gotten, I feel like we've gotten a little bit spoiled and jaded in the Bakken. We've talked a lot about the Lars pad and I look at this, for instance this Myrmidon pad from the quarter, you look at not only the average across the pad but you look at the Jerome well which did 4,800 barrels of oil per day on an IP 30. And, all of a sudden, that's not even headline grabbing anymore which is shocking to me.
I mean these wells are incredible kind of world-class wells and certainly are some of the best that have ever been completed in the North America unconventional space. And, I just want to really, just compliment that team on what has been one of the most notable turnarounds in our portfolio. From almost zero capital allocation back in 2016 to where we find ourselves today, it is one of the most compelling success stories that I can point to in our portfolio.
I agree with you completely. I've been around long enough to remember when it was 400,000 barrel EURS. And we look at these wells now and they're just unbelievable.
Agree.
Yeah. Appreciate the comments. And not to pile on here too much, but it's also on the backs of well costs that are 20% lower than the trailing 12 months. And, I think the well cost part of the equation is a little bit underappreciated as we talk about flashy IPs and across all of the basins. But, great work on both sides of the equation there.
Okay. Great. Thanks for all the color. I appreciate it.
Ok.
Thank you. I will now turn the call back over to Lee Tillman for closing remarks.
Well, I would just like to wrap up by saying, thank you for your interest in Marathon Oil and thank you to our dedicated employees and contractors that safely deliver execution, excellence 24/7. We cannot produce these results without them. That concludes our call. Thank you very much.
Thank you and thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.