Marathon Oil Corporation (NYSE:MRO) Q1 2019 Earnings Conference Call May 2, 2019 9:00 AM ET
Lee Tillman - Chairman, President, Chief Executive Officer
Dane Whitehead - Executive Vice President, Chief Financial Officer
Mitch Little - Executive Vice President, Operations
Guy Baber - Vice President, Investor relations
Conference Call Participants
Arun Jayaram - JP Morgan
Neal Dingmann - SunTrust
Ryan Todd - Simmons Energy
Doug Leggate - Bank of America
Scott Hanold - RBC Capital Markets
Jeanine Wai - Barclays
Brian Singer - Goldman Sachs
David Heikkinen - Heikkinen Energy
Jeffrey Campbell - Tuohy Brothers
John Aschenbeck - Seaport Global
Pavel Malchonov - Raymond James
Welcome to the Marathon Oil first quarter earnings conference call. My name is Vanessa and I will be your operator for today’s call. At this time, all participants are in a listen-only mode. Later we will conduct a question and answer session. During the question and answer session, if you have a question please press star then one to enter the queue. Please note that this conference is being recorded.
I will now turn the call over to your host, Guy Baber, Vice President, Investor Relations.
Thanks Vanessa. Thank you to everyone for joining us this morning. Yesterday after the market closed, we issued a press release, a slide presentation and investor packet that address our first quarter results. Those documents can be found on our website at marathonoil.com.
Joining me on today’s call are Lee Tillman, our Chairman, President and CEO; Dane Whitehead, Executive VP and CFO; Mitch Little, Executive VP of Operations, and Pat Wagner, our Executive VP of Corporate Development and Strategy.
As always, today’s call will contain forward-looking statements subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied by such statements. I’ll refer everyone to the cautionary language included in the press release and presentation materials as well as to the risk factors described in our SEC filings.
With that, I’ll turn the call over to Lee, who will provide his opening remarks. We will then open the call to Q&A.
Thanks Guy, and thank to you to everyone joining us this morning. First quarter marked a continuation of our track record of successful execution against our well established framework for capital. This framework has been our touchstone as we have transformed our business to our advantaged multi-basin U.S. resource play model.
It starts by ensuring every dollar we spend advances our corporate returns. This returns-first mindset coupled with disciplined capital allocation resulted in a peer-leading year-over-year improvement in cash return on invested capital in 2018. We are well positioned to continue driving this significant rate of change in both our cash return and cash flow per debt adjusted share. From 2017 to 2019, our cash returns are on pace to almost double oil normalized pricing.
It also means prioritizing sustainable free cash flow at conservative pricing, over-production growth for growth’s sake, while driving our peer-leading enterprise breakeven lower. In first quarter 2019, we have already generated $80 million of organic free cash flow. Our organic free cash flow is expected to improve in the second quarter and over the course of the year, driven by our underlying operational momentum and amplified by a more favorable pricing environment.
With sustainable free cash flow, capital discipline for us means prioritizing the return of capital back to shareholders through both our peer competitive dividend and disciplined share repurchases. As a compelling proof point, in 2018 we returned over 25% of our net operating cash flow to shareholders. 2019 year-to-date, we have repurchased $50 million of our shares, and including the dividend have returned over $90 million to our shareholders. Organic free cash flow generation remains the governor on potential buybacks. We simply will not spend money that we have not earned, nor will we be reliant on disposition proceeds.
We continue to see good value in buying our shares at current prices, consistent with our returns focus, and with organic free cash flow inflecting higher, we expect our capacity for additional share repurchases to trend upward, allowing us to take advantage of our remaining $750 million authorization.
Finally, capital discipline is about differentiated execution that drives continuous improvement in capital efficiency and operating costs while also enhancing our resource base. In 2018, we held to our original development capital budget while raising our U.S. resource play oil production guidance three consecutive quarters, and uplifting our inventory through organic enhancement efforts in both the Bakken and Eagle Ford.
For first quarter 2019, our development capex is down 8% from year-ago quarter and represents just under 24% of our full year 2019 development capital budget. We are firmly and credibly on track to achieve our full year oil growth guidance with no change to our development capital budget. As we have consistently demonstrated, our budget is not a suggestion, it is a commitment, and we will not increase spending on improved prices to chase growth; rather, we will take that cash flow to the bottom line and share it with our shareholders.
Expanding further on our differentiated execution in the first quarter, U.S. product unit expense was down 12% from year-ago quarter and we are seeing lower completed well costs across all basins while still delivering strong well productivity. These four objectives - corporate returns first, sustainable free cash flow at conservative pricing, prioritizing return of capital to shareholders, and differentiated execution are how we run our business and are embedded in our executive compensation. They are supported by a foundation of our multi-basin portfolio and peer-leading balance sheet. We have concentrated and simplified our portfolio into four of the best high margin U.S. resource plays that span the development cycle in terms of maturity, providing capital allocation flexibility, broad market access, diversification of suppliers, and rapid sharing of best practices. Our current resource base is high return and high quality, and we are progressing multi-faceted efforts to continue to enhance it. As such, large scale M&A is not a consideration, nor is it required for our forward success.
Our balance sheet provides tremendous financial flexibility to execute our business plan across a broad range of pricing, and with the recent upgrade by Moody’s we are investment grade at all three major rating agencies.
With our framework for success as a backdrop, let’s turn our attention to a few of the more specific first quarter highlights across our multi-basin portfolio and how each of our assets are individually contributing to our collective enterprise-level success.
First at a high level, total company oil production was up 6% from year-ago quarter with U.S. oil production up 11%. Though we delivered within our quarterly production guidance, our results would have been even stronger without the impact of adverse weather effects across multiple basins during 1Q, especially severe during February in the Bakken; however, our D&C execution was unaffected and our well productivity was strong. Our only challenge was keeping our well capacity online. Importantly, we are carrying that developed well capacity into second quarter, as seen in strong April performance, and have good operational momentum that supports our expected 5% sequential growth in U.S. oil production for 2Q. We remain firmly on track to deliver our full year plan of 10% total company oil growth and 12% U.S. growth within our original $2.4 billion development capital budget.
In the Eagle Ford, due to consistently strong execution and advantaged pricing, our team continues to deliver financial returns and free cash flow that compete favorably against any basin across the lower 48. During first quarter, we drove further efficiency improvements from already impressive levels. Our completed well cost averaged just $4.4 million, down more than 15% from the year-ago quarter, while our completion stages per day and drilling feet per day were up 15% and 10% respectively.
In the Bakken, we continue to deliver industry-leading well productivity while realizing step changes in capital efficiency and associated bottom line returns improvement. More specifically, our 180-day cumulative oil production per well for the last two years is outperforming the peer group average by a significant 45%. We are delivering this leading productivity while continuing to drive our well costs lower. During first quarter, our average completed well cost was just $5.1 million, down more than 25% from 1Q18.
At the same time, we remain focused on continuing to enhance our resource base through both organic enhancement efforts and also through small bolt-on acquisitions and leasing. We are pleased to provide a positive update on both fronts as our fourth quarter core extension test in our Ajax area of the Bakken, where we hadn’t drilled for three years, is delivering truly impressive long term production, and we recently added over 50 new gross company operated locations to our position through a bolt-on acquisition and incremental leasing.
Turning to Oklahoma, we again reported strong and predictable results and optimized spacing designs in the over-pressured stack, where average well performance for our three first quarter in-fills each developed at DSU-specific spacing is outpacing our tight curve by over 50%. The team also continues to drive our well cost significantly lower, improving bottom line returns with average completed well costs per lateral foot for our first quarter stack in-fills down more than 30% relative to parent wells.
In the northern Delaware, we continue to strategically pace our investment with a keen focus on protecting our leasehold, delineating our position, and improving our margins all while delivering significant early development drilling success. Well productivity in Malaga has improved markedly as we advance our learnings, highlighted by a four-well pad that delivered an average IP30 of over 2,800 Boed at 62% oil cut, or approximately 400 Boed per 1,000 foot of lateral. Importantly, we also continue to make great progress in reducing both our capital and operating costs. We have made considerable progress in getting our produced water on pipe and will be at 100% water on pipe for our remaining 2019 wells to sales.
Stepping outside of our four U.S. resource plays, we had a very busy quarter on the international front. We successfully executed our planned triennial turnaround in EG with a return to full production levels achieved on schedule in early April. As previously announced, we signed agreements to process third party gas through our world-class EG infrastructure, positioning our EG assets to deliver strong free cash flow for years to come and to compete as a natural aggregation point for local and regional gas opportunities. Further, we continue to optimize our portfolio, as evidenced by our agreement to divest our U.K. properties, which will remove approximately $950 million of asset retirement obligations upon close, further enabling the focused allocation of our capital to our highest return assets.
As I’ve said before, we don’t believe it’s a mystery as to what investors are looking for, whether generalist or energy focused. It’s pretty straightforward. All investors are looking for companies that have the right portfolio of assets; that have the right strategy putting returns first, generating sustainable free cash flow at conservative oil prices, and sharing that cash flow with investors; that have a strong balance sheet to weather potential volatility; and that have the capability to execute on their commitments consistently. We believe we screen well on these criteria and our performance in 2018 and now first quarter 2019 stand as our proof points. We have a uniquely resilient cash generative portfolio that is already delivering compelling free cash flow yield relative to both other E&Ps and the broader market, with high value oil growth and outcome and all at an organic breakeven of $45 WTI.
From a sustainability perspective, we have shared a two-year outlook that provides visibility on the metrics that matter most. It is an outlook that prioritizes returns, free cash flow, and return of capital to shareholders. It all starts with continuing to drive our compelling multi-year rate of change improvement in key enterprise performance metrics, specifically our cash return on invested capital and cash flow per debt adjusted share, both of which, as a reminder, are a part of our executive compensation scorecard. We are on track to deliver a 30% CAGR on cash return from 2017 to 2020 at $60 WTI flat, roughly on par with the current forward curve.
With that returns-first orientation, we deliver sustainable free cash flow generation above $45 WTI with significant organic free cash flow expected through 2020 of $750 million at just $50 WTI flat, and over $2.2 billion or almost double the broader market free cash flow yield at $60 WTI flat. Our positive leverage to higher oil prices coupled with a low enterprise breakeven is a powerful and winning combination in any commodity environment, and though $50 WTI remains our planning basis in a commodity price at which we generate meaningful free cash flow, we believe that continuing to drive our enterprise breakeven point even lower is essential in a commodity business. It was only 2017 when our enterprise breakeven stood at just over $50 WTI. This sustainable free cash flow profile allows us to prioritize return of capital to shareholders and compete for the broadest cross section of investors. We also added a new return of capital metric to our executive compensation scorecard earlier this year to underscore this commitment.
Thank you all for listening, and with that I’ll hand it back to the operator to begin the Q&A.
We have our first question from Arun Jayaram with JP Morgan.
Good morning, Lee. Two questions on EG. One, I was wondering if you could discuss some of the details or cash flow uplift that you anticipate from the tolling and profit-sharing agreement for the Alen volumes with Noble.
Okay, well first of all, we’re very pleased to have the definitive agreements now executed for the Alen unit gas, and maybe just as a reminder for everyone on the call, we are taking advantage of existing capacity at our world-class integrated gas infrastructure at Punta Europa. Really, although I can’t get into specific commercial terms because they’re confidential, the value proposition for Marathon is through a combination of tolling and profit-sharing such that all parties benefit from exposure to global LNG prices.
I would also say that additionally, with only tie-ins and minor modifications required at our facilities with the Alen unit bearing all of the capital costs associated with getting the gas to Punta Europa, capital requirements to Marathon are really minimal. We expect first gas nominally in 2021, so with that we also are going to enjoy the added benefit of extending the Alba tail, our own equity molecules, by delaying any future turn-down of the EG LNG plant. When I think about the value proposition for us, Arun, it’s really building on that base EBITDAX that we’re already achieving through the Alba PSC, and this is layering on top of it through both a tolling arrangement as well as some market exposure through profit-sharing.
Great. My follow-up is the LNG from the facility is sold using a Henry Hub-based index. I believe this runs through 2023 or so. Could you give us some thoughts--you know, obviously the market is well above a Henry Hub linked index, so what kind of cash flow uplift that you could see if we were going to, call it mark to market towards current market prices for LNG?
Well certainly you’re absolutely correct, Arun - the agreement that we have in place, the long term agreement we have in place at EG is Henry Hub link, and it does run its course in 2023. Post that time, the Alba volumes will be subject to negotiation into the open market, so there’s absolutely the potential for uplift there. With the Alen volumes, obviously, we will have that exposure to the broader LNG market starting really when we see first gas from that opportunity, and although we really can’t quantify that expertly today, we know that, as you say, given today’s market, we feel that directionally that is simply adding incremental value to what is already a very high value asset for us.
Great. Thanks a lot, Lee.
Thank you, Arun.
We have our next question from Neal Dingmann with SunTrust.
Morning. My first question, you guys did a magnificent job on the spend for the first quarter, especially versus a lot of your peers out there. I’m just wondering, I’m trying to get a sense of cadence. You talked about your free cash flow plans not only for this year but the longer term plan. I’m trying to get a sense of spend as you see it for the remainder of the year, does it continue to trend just on a more linear basis, or how should we think about that, is my first question.
I’ll maybe start, Neal, just by reiterating something from my opening comments, which is our budget is our budget. We have a $2.4 billion development capital budget that compares to a $2.3 billion budget that we delivered against last year. We are a little bit front half of the year loaded in terms of wells to sales, so it was great to come in really with a ratable number in first quarter. You will have noticed that we had a large proportion, though, of wells to sales in first quarter. Many of those, we’ll see the advantage of, obviously, in second quarter and beyond, but everything is going in the right direction for us from a capital efficiency standpoint. The asset teams are doing a tremendous job of continuing to drive completed well costs lower. We certainly saw that as an advantage in first quarter.
As we look throughout the year, we’re very comfortable with delivery against not only our $2.4 billion budget but also our commitments on oil growth for the year. Importantly, that’s going to translate into very strong financial momentum as well, which is first quarter in our plan was always going to be our lightest from a free cash flow standpoint. That momentum is only going to build as we move into second quarter and the rest of the year.
Okay, great details there, Lee. Just one follow-up on that Slide 10, when I’m looking at the Bakken - again, your wells just continue to be superb there. My question is really on the focus area. You might have already said this, Lee, in other updates, but for the rest of the year, will there be also focus on moving down to Elk Creek or Hector or Ajax, or could you just talk about what the focus is, and if it is moving down there, how do expectations compare versus these stellar results you continue to see recently?
Sure Neal, this is Mitch. I’ll address that question. Absolutely as we go throughout the year, you’re going to see additional activity down in Hector area as well as Ajax, as well as continued activity in Myrmidon. It’ll be a bit more diverse program as we go throughout the year, but as you say, really proud of what the team is doing out here, really basin-leading efforts both on well productivity and on well costs. The program that we delivered in Q1, based on available public data for the basin, still looks to be delivering IP30s that are on average about 40% higher than peer average, and when we look at this program in aggregate, we expect the Q1 program to achieve payout in something around six months, so just really impressed with what the team is doing.
You know, we don’t drive our teams to focus on flashy IP24s or even flashy IP30s. The discipline that we’ve instilled is around capital efficiency improvement, looking at hat holistically from both well productivity and the well costs.
Very good, stellar - exactly. Mitch, Lee, thanks so much for the answers.
Thank you, Neal.
Our next question is from Ryan Todd with Simmons Energy.
Great, thanks. Maybe a follow-up first on the capex. You talked a little bit about it. Can you talk about the primary drivers of lower budget in the first quarter? Is it primarily lower well costs, and can you talk about whether you see those as sustainable, particularly whether you see any upward pressure on well cost or inflation, and whether it’s--I know it’s early, but if you can hold this type of efficient operations, whether there could be potential downward risk to the full-year capital budget.
I’ll maybe offer a few comments and then clearly Mitch can chime in as well, if he wants. When we look at completed well costs, I think of several buckets that are really contributing to our ability to drive those costs lower. First and foremost, it’s really working the supply chain. Our ability to integrate into the supply chain, do a lot of self sourcing has really been a key enabler across all of our basins. Our supply chain team has really stepped up and has just done an outstanding job in how they are assisting the asset teams and driving our costs down from a supply chain perspective. With some of that self sourcing, it’s opened up some interesting commercial opportunities for us as well, particularly with our pumping providers. I think those commercial terms that we’ve been able to put in place that really do reward strong performance and efficiency, so it’s a win-win for both the provider and the operator, have also been a key element of that cost direction.
Then finally, it’s just down to the sheer efficiency that we’re observing. We continue to see, whether it’s our rate of penetration on our drilling rigs and our time to drill coming down, or it’s simply the number of stages that we’re able to put away per day even though some of the stage, maybe, are more complex and more intense than they ever have been, we continue to see gains in those areas. So when you put all that together, that is really what is helping drive our completed well costs lower.
I think if we look out throughout the year, assuming that I think the mandate around capital discipline across the segment continues to hold true and thus supply and demand stays relatively stable in the service sector, we simply don’t see a lot of pressure from an inflationary standpoint that we would need to be concerned with as we move throughout the year. But that’s obviously going to be very dependent upon the activity levels and the response from other folks in our segment.
Thanks Lee. Maybe one more on--I appreciate the comments you made, how you’re not interested in any sort of large scale M&A, but you had a nice targeted pick-up of some additional inventory in the Bakken. Can you talk about how you view the environment, whether it’s in the Bakken or the Permian or other basins, in terms of whether there are additional opportunities for smaller bolt-on transactions like that, and what the overall environment feels like for those type of deals?
I think maybe first just stepping back a little bit, Ryan, and talking about our approach to enhancing and expanding our inventory and our resource base, it really is threefold. It starts with the organic enhancement work that’s been going on within our asset teams and within our basins. We saw obviously the results of that in the Eagle Ford and the Bakken as we continue to extend the core area in places like Atascosa County, obviously Hector, and Ajax. So that remains a key element, and we have dedicated development capital that is continuing to chase further organic enhancement this year.
The second element really is the one that you referenced, which is around small, bolt-on, incremental leasing that really fits hand-in-glove with our existing position in basins, so these are very surgical, very selective. We’re really looking at opportunities that are synergistic to the positions that we’ve already created. The 50-plus gross company operated wells that we talked about for the Bakken that came by way of a bolt-on and some leasing, that fits that description perfectly. We also continue to have ongoing opportunities for trade, etc. in places like the Permian, so that is a very important element and really complements the organic enhancement work that we’re doing in basin.
Then when you step a little further afield, we of course have the REX program, which is our resource play exploration program, that is really chasing those greenfield leasing positions that can offer the potential for outsized full cycle returns, so low entry costs, material positions near basins or even new basins, so when I look at all three of those things in concert, and then to me the final complementary effort to that is the work that we continue to do on enhanced oil recovery as well, and we’re on Phase 2 on EOR in the Eagle Ford. So when I look at that framework, we feel very good about our ability to continue to move the needle on both the quality and scale of our resource base going forward.
Thank you. Our next question is from Doug Leggate from Bank of America.
Thanks, good morning Lee, good morning everybody. Lee, I wonder if I could hark you back to the LNG question. It’s kind of aging us a bit, because I seem to remember writing about this in detail in 2005, so we’re all getting a bit older, I guess. But my question specifically is the license expiry in 2023, as I recall, there was a floor in the Henry Hub price somewhere in the 350 range, so I’m trying to understand when you--first of all, what is the prospect for you guys extending that license, and secondly, do you regain any destination rights that were given up to, at that time, BG and I guess now Shell?
Yes, first of all, for absolute clarity, I would not refer to them as licensing rights. It was simply commercial agreement for LNG sales off the back of the LNG, so I don’t want people to confuse that, for instance, with the PSC or anything.
Yes, I’m thinking more about the upstream side of it, sorry, in terms of the production. Sorry, I should have been clear on that.
Yes. Certainly the commercial terms that you described - again, we can’t get into details on our commercial terms. We’ve already talked about that that Shell/BG legacy contract runs its course in 2023, and at that point the Alba molecules are available for negotiation into the open market, so we are essentially released from the obligations of that contract. It doesn’t mean that we can’t renegotiate some type of deal with the existing partners with Shell, but we’re not limited to simply negotiating with them.
As I mentioned, one of the advantages of continuing to bring in additional third party gas opportunities is that we--it allows us to avoid taking the LNG plant into turndown mode, which allows us to extend the Alba tail which gives us more of our own equity gas molecules to get into the market, once that 2023 arrangement runs its course.
Okay, so to be clear, when does the PSC expire and what are [indiscernible] potential for you retaining--
The PSC doesn’t expire until--I think it’s post 2030, 2040, in that time period. PSC expiry is not an issue for us, and I would also add that in most cases, when we face extensions on PSCs particularly for a footprint like we have in EG, I think there would be an open door there to negotiate that to the satisfaction of not only us as the operator but also the government.
Okay, I appreciate that. My follow-up is--and I’m going to apologize in advance for this one, it’s an M&A question. Look - you’ve done a phenomenal job since you joined Marathon several years ago, and the free cash flow speaks for itself. I like to characterize it as putting good assets in the hands of great management. The downside of everything you’ve done, however, is that your share price has not really been differentiated relative to your peer group, despite everything that you’ve done, so I’m just curious what do you think Marathon has to do to see a step change in market recognition of what you’ve done, and I’m wondering if you see any appetite to take good assets into your management and eliminate what, in some cases, are excess overheads in what is clearly a portfolio that could fit very nicely with some other companies.
I think first of all for us--first of all, thank you for the kind words, and it’s been a complete and total team effort to get to where we are today in our transformation journey, so the recognition is really a team recognition here at Marathon. But on share price performance, we try to focus internally on the things that we can control, and ultimately we believe our model, our execution, our portfolio will ultimately win the day, and as investors, whether they be generalists or energy focused, begin to turn their attention back to the sector, we believe that we’re going to offer a very strong investment profile for them to take advantage of. We believe that we can compete with not only our own space but with the broader S&P 500.
Just on the M&A point, and again I’m not going to comment on current deals or anything in the market, but what I would say is when you look at the activity and recent announcements, and even some of the investment plans that we have seen from some of the majors, in my way of thinking, it only really serves to highlight the attractive characteristics of the U.S. short cycle unconventional assets, and the fact that on a risk-adjusted return basis the U.S. unconventionals compete at a global level. So we’re very committed to our multi-basin strategy, we believe that’s the right way to proceed. We think it delivers the right kind of shareholder outcomes, and we’re going to continue to execute against that model. We think with that consistency of execution, the recognition from the market and from investors will come.
So no desire to do anything corporate-wise?
Thanks Lee, I appreciate you answering a tough question. Appreciate it.
Thank you, Doug.
Thank you. We have our next question from Scott Hanold with RBC.
Thanks, good morning. Lee, you had mentioned a little bit earlier that obviously you’re not going to try to get ahead of some of the free cash flow generation with the stock buyback. Can you generally speak to how you expect to progress at that end? With respect to the U.K. asset sale, just to be clear, and I think you’re getting, what - about 140, 150 from that, that will not be part of, I guess, the buyback conversation? Is that targeted just for more REX spending, or how should we look at that?
Yes, first of all, let me take the first part of your question, Scott. It has always been a feature of our business plan this year, regardless of pricing, that our operational momentum and hence our organic free cash flow momentum would be inflecting between first and second quarter and improving as we move throughout the year. Having said that, we’ve also been equally clear that even on our share repurchase program, we’re going to be very disciplined with a governor of how much organic free cash flow are we actually generating. We’re not going to do anything that will damage our balance sheet. We have worked very hard. Our finance team has done a great job of positioning us now to be investment grade across the board with all of the ratings agencies. That’s come from, I think, a pattern of taking very disciplined and thoughtful actions around our balance sheet, and that’s going to continue in the future.
The U.K. transaction is progressing. We’ve kind of said that it would likely close in the second half of the year. When we see that money come into the portfolio, we also have to recognize that there is an offset to that, that is staying back in the corporate structure in the U.K. so net-net, we just have to remember that that by no means is a windfall that we could potentially immediately dedicate into share repurchases.
So we’re going to stay with our formula, which is we’re going to drive our share repurchases through our organic free cash flow. To the extent that we see other proceeds, those will be available for other attractive opportunities - you mentioned REX, we’ve talked about small bolt-ons today, all of that would be in play, and that’s a decision that we’ll take on game day when we see those opportunities arise.
Okay, that’s clear. Thanks, I appreciate that. As my follow-up, you did mention that you picked up a handful of new locations in the Bakken through some organic leasing. Can you give us some color on exactly what part of your acreage did you add there, and is it full operated stuff or is it just bolting on and is it more of a working interest increase? Can you give us a little color on that?
First of all, and I’ll mention a few things and then see if Mitch wants to chime in as well, I guess when I think about 50 gross operated wells between the bolt-on and leasing, I don’t think of that as a handful. I mean, that’s pretty meaningful, and that well count, just for clarity, that is gross operated well count. We don’t talk in terms of non-operated or OBO type well count, so I just want to be very, very clear on that.
Because we’re still active from a leasing and even a small bolt-on acquisition standpoint, we don’t necessarily want to get too specific about where we’re chasing opportunities, but I would just say that in general, these are fitting within our footprint in areas where we have developed confidence in our ability to drive more value than likely another operator from those positions.
Okay, appreciate the color. I didn’t mean to under-appreciate the size of the adds, because certainly it provides you some pretty good additional runway.
I’m sensitive to those kinds of things, Scott!
No worries, thank you.
Thank you. Our next question is from Jeanine Wai with Barclays.
Hi, good morning everyone. My first question is on the corporate objectives. Number three on the list is prioritizing return of capital, which you’ve spoken a lot about. We noticed that you layered in a fair amount of new hedges this quarter, and just wondering if that was opportunistic in wanting to lock in the cash flow now, or is there something that you’re seeing in the operating environment [indiscernible] what we’ve heard, one or two operators talking about cost inflation, or is there something in the A&D market that’s driving your decision on the hedges? I know you mentioned still being active in leasing and small bolt-ons. Just curious, because I thought that the prior commentary on hedges from Marathon was just that you had more flexibility heading into ’19 given the balance sheet and the free cash flow potential, so just wanted to check in on where you’re at on this.
Yes, let me talk broadly about commodity risk management and then I’ll let Dane address the hedge book directly. When we think about commodity risk management, we think about it really in three areas. One you mentioned, Jeanine, which is the strength of our balance sheet, that is part of our commodity risk management strategy. Number two, and also equally as important, is our very low enterprise breakeven point that we’ve established, so that provides us that latitude in a very broad range of pricing environments. Then the third element is in fact our formal hedge book and how we look at hedging, particularly in a portfolio that, for instance this quarter, is a 60% oil weighted portfolio.
With that, maybe I’ll just let Dane talk a little bit about the hedge book and our strategy that we’ve tried to put in play there
Yes, hi Jeanine. Following up on prior meetings with you, or maybe prior calls, commentary on the hedge objectives, in previous years we had a very strong, get 50%--floors in on 50% of our next year production, sort of objective, but as our financial position has improved and our financial flexibility has improved, we have felt like we’ve had the flexibility to be a lot more opportunistic along our way toward that goal. So we saw in this last price run-up the opportunity to put on some really attractive three-ways - 48 by 55 by 74, and so we took advantage of that market rally to put those on.
You know, we stay on top of this on a regular basis and when we see good value there, we put them in. It’s definitely there’s no linkage to transaction or any other things happening in our day-to-day business, it’s really just all about overall price risk management.
Okay, that’s really helpful, thanks. My second question is on well results. We noticed that well productivity as measured by the IP30s declined quarter over quarter, and the biggest declines were in the Eagle Ford and the Bakken, which were double digits. I know you indicated in your prepared remarks or in the commentary that you don’t chase flashy early production rates, but can you talk about what’s driving this rate of change, and does the oil productivity track a similar trend to the reported Boe results?
Sure Jeanine, this is Mitch again. Maybe I’ll reiterate a couple of the comments I made earlier on Bakken, and then I’ll jump to Eagle Ford and address that as well. I think it starts with taking a look back a little bit, and as I said, I’m extremely proud of the efforts our teams have done to uplift the quality of our inventory across our position in both Bakken and Eagle Ford. Our internal dialog and the discipline and the mindset that we’re establishing is one of capital efficiency and improving corporate returns, so we look at his holistically and over the long run, both from a well productivity and a capex perspective, in the Bakken as best we can tell from public data, our Q1 results are about 40% better than the next closest peer on IP30s, and payout for both our Eagle Ford and our Bakken Q1 programs is on the order of six months. That’s an investment that’s going to compete at the top of our portfolio and really anybody’s portfolio, day in and day out. I’m really proud of what we’re delivering.
All that being said, there will be some variability across all these plays, and that’s nothing unique. We publish our results every quarter down the pad level in Bakken and Eagle Ford, so you can see those trends over time. There’s no doubt that the very best ROC in each of those basins is going to deliver the very best results, so we’ve got results we’re proud of, really impressive earns If you take a look at the Eagle Ford specifically, those are the lowest well costs of any of our four basins. We’ve got access to MEH pricing, an extremely efficient operation in the Eagle Ford, and as I mentioned earlier, the returns from these programs are phenomenal.
I’ll leave it there.
If I could just maybe add in, Jeanine, that this all links back, though, to that first objective we talked about in our framework for success, which is enterprise level returns. Whether you look at Eagle Ford or the Bakken, both of those programs are driving our enterprise level returns directionally more positive, and so we can spend a lot of time talking about IP30s and they’re an indicative piece of information, but you also have to look at [indiscernible] production, well costs, all of those things, cycle times all factor into the economics of these wells, and the reality is our toughest comparison point is ourselves right now, particularly in the Bakken.
When you look at things from a relative standpoint, yes, there was some change in the mix, and we don’t get too wrapped around the quarter to quarter variations when we see that it’s being driven by geology and other fundamentals. We’re going to remain resolutely focused on returns and making sure that those well level returns translate into corporate level returns at the end of the day.
Okay, great. Thank you for taking my questions.
Thank you. Our next question is from Brian Singer with Goldman Sachs.
Thank you, good morning. A couple follow-ups on some prior questions. First, do the changes that you’re seeing in well costs and productivity vary the relative ranking and capital allocation between basins, and then are the efficiencies that you highlighted earlier on and your expectation for a lack of service inflation going forward already baked into your capex guidance for the year?
Yes, first of all on relative capital allocation, the results that we have been referring to today were really fully cooked into our original multi-basin optimization, so it in no way impacts the relative capital allocation. Recall Brian that we’re kind of on a 60% Bakken-Eagle Ford to 40% Oklahoma and Permian, and even within those splits, we are staying pretty true to that initial relative capital allocation that we talked about back in February. From that standpoint, this is not really impacting, I think, anything from a capital allocation standpoint.
Got it, and that applies too on an overall budget perspective when you think about the service inflation and the efficiencies? Is that all baked in, or--?
Absolutely, yes. We built in obviously assumptions around both efficiency and inflation into our forward plan. We’re tracking very well to both of those, so again we don’t see that as being in any way a factor in our go-forward capital program.
Great, thanks. Then as you return cash to shareholders above and beyond the dividend, you mentioned that the timing is going to be a function of when you see the free cash coming in on a quarterly basis, if I had to paraphrase what you said earlier. Is that the sole constraint, or are there any broader market factors or share price markers that would determine how aggressive you would want to buy back stock, assuming you’ve got the free cash coming in to do it?
Yes, it is a bit of a--I’ll call it a bit of a dual matrix in that sense, Brian. We look, one, at our current and forward free cash flow generation from a sustainability standpoint, so that’s generally linked to our operational performance coupled with where the forward curve is sitting, but we also look at our own internal relative NAV valuations relative to what we’re seeing on our shares in the market, and today we would say that our shares still offer a very good value. Again, going back to that returns first orientation, we believe that that is still the preferred mechanism today for getting money back to our shareholders. It doesn’t mean that we don’t look at the dividend and assess that each and every quarter, but today I think with the volatility, I think with the ability to scale to free cash flow and the returns that it offers, we feel very strongly that the share repurchase program that we’re on today is the right answer. We’ll continue to evaluate that as we see the market respond.
Great, thank you.
Thank you. We have our next question from David Heikkinen with Heikkinen Energy.
Good morning, thanks for taking the question. This is a nuance on your activity level and capital. It looks like your working interests are trending a little bit down the last couple quarters versus ’18. The trend for the last couple quarters, should that continue in the Bakken, Eagle Ford and Delaware?
Great observation, David, and that’s one that we obviously track and look at as part of our plan as well. We do have a little bit of a localized dip in working interest in the first quarter for both the Eagle Ford and the Bakken, but that’s going to recover in forward quarters to probably look a little bit more familiar to where we were, say in the first part of even 2018.
That’s helpful. I know you don’t budget and talk about OBO capital and production. What is your perspective, though, for OBO by region given your diverse asset base? I’m just curious, is Delaware coming in higher? Is there any other indications that you can see in Oklahoma, Eagle Ford or Bakken?
The areas, I guess, probably where we feel the non-operated the most are probably Oklahoma and northern Delaware. Not to say that we don’t have a little bit in the Bakken and the Eagle Ford, but the areas where we see probably the largest exposure are really in those two basins. I would say thus far, it’s probably still a little too early in the year to fully assess the trends, but we certainly would say that activity today is probably at or a little bit below our assumptions. Whether that trend continues or we see some of that pressure later in the year, that’s something we’re just going to have to watch.
Thank you. The next question comes from Jeffery Campbell with Tuohy Brothers.
Good morning, and congratulations on another solid quarter. I wanted to discuss the spacing variances that you mentioned in the press release in Oklahoma. First, are these primary variances within one particular zone, or are they variances between different zones? Also, does this encompass vertical as well as horizontal spacing within a zone or zones?
Sure Jeff, this is Mitch again. We’ve been talking for a little while, several quarters at least, on the integrated workflows and state of the art tools that we use, including 3D fracture modeling and seismic inversion processing in Oklahoma on particular to design our development approach in the stack and across the basin, down to a sub-region level. You’re aware that the characteristics change across the play, and so we’ve utilized that integrated workflow to optimize not only well density but also landing zone, so it’s going to vary across each of those. For example, the lower well density was across the single landing horizon where the other two pads would have been across multiple landing horizons, but all in the Meramec section.
Okay, good. That’s helpful, I appreciate that. The other thing I wanted to mention was just the northern Delaware Malaga wells were pretty impressive. I was just wondering are you starting to get some kind of an eye for what the activity level in northern Delaware, maybe in that area, might look like over the next year or so?
Yes, first of all, that team has advanced more quickly to multi-well pad drilling than really any other asset that we’ve been involved with, so they are moving at a very rapid pace but they’re still learning. There’s still a lot of delineation left to do there, it’s a big footprint. There’s also some leasehold work that we still have to do in northern Delaware. You couple that with some continued restrictions, I’ll just say globally for the industry around takeaway, etc., I think we’re on a very good pace there. I mean, we’re growing and we’re growing on a relatively small volume, but while we’re growing, we’re learning and we’re also producing these kinds of well productivity very early in the life of the asset, so all of that to me is very encouraging.
We view northern Delaware as one of the growth engines for the future, but we’re going to make sure that we pace that, one, in the context of how quickly we can learn and make smart economic decisions, but also in the context of optimizing that in our broader multi-basin portfolio.
Okay, thanks Lee. I appreciate the answer.
Thank you. Our next question is from John Aschenbeck with Seaport Global.
Good morning everyone, and thank you for fitting me in. Just had one question, really on the Eagle Ford. A lot of the focus over the past couple years has really highlighted core extension efforts in Atascosa County, which have been strong; but I also noticed in your slide deck that you still have what appears to be a very sizeable position in Gonzales and DeWitt Counties, where some other operators have been putting up some pretty interesting results. I was just curious how much activity do you have planned in that area in the near term, and when do you think you’ll have some type of, call it core extension test results to share with us? Thanks.
Sure John, this is Mitch again. I think we disclosed this as well in our initial capital release, but high 80s to around 90% of our activity is going to be in the Carnes and Atascosa County areas, which leaves the remainder to address things like you’re mentioned here on the call. We have pivoted to not only focus and continue to work on enhancing the quality of the inventory across that expanded core, but also looking at opportunities that have the potential to add hundreds of additional sticks across our Bakken and Eagle Ford positions. Those activities are being funded as well, and there’s many of them in progress. It’ll likely be late ’19, maybe early ’20 before we’re in a position to talk in more detail about those, but this effort and this advantaged quality that we’ve driven across our core basin for the last couple years is now being--continuing to focus on that, but also being expanded to look at opportunities that also increase the depth of inventory in both of those basins.
The short answer was yes, we do plan activity outside of Carnes and Atascosa this year, but the more holistic answer there is there’s a lot of good things going on in the Eagle Ford and Bakken, and our other two basins, for that matter, across the entire space of both, upgrading the quality and the quantity.
Okay, great. Thanks Mitch, that’s all for me.
Thank you. Our next question is from Pavel Molchanov with Raymond James.
Thanks for taking the question. Can I go back to the dividend, please? You’ve said that given where the stock is right now, a buyback is a better option in your mind. I know that what some of your peers have been doing is raising the dividend as a way of instilling, perhaps, a greater expectation of capital discipline in the sense that when you have a fixed payout amount, it tends to force the organization to work towards that. Do you see a logic in sending that same message, or not really?
I’ll maybe offer a few comments and then ask Dane maybe to jump in as well. First of all, I would say a lot of the sector activity has been raising dividend on what was already a low or nonexistent base, so where we sit today even with all those raises, we are still sitting right around the average from a yield standpoint. We think it does introduce some constructive tension around capital discipline and capital allocation which we think is valuable today in the current environment. Our preferred mechanism is share repurchase, but we continue to assess dividend and dividend yield and payout as a matter of course with our board each and every quarter, and to the extent that we see that that is a preferred mechanism, we’ll address that at that point in time.
That’s just where we are today. It doesn’t mean that’s where we’ll be a year from now.
Okay, that certainly makes sense. One about EG - you guys had about $60 million of free cash flow in the quarter despite, obviously, a low oil price to start the year. Is it fair to say that free cash flow would actually be negative had it not been for the EG operations?
No, absolutely not. We have multiple assets that are throwing off free cash flow today, and even with--the big impact in the first quarter in EG was of course the triennial turndown, which took us down basically to zero rate for a period of time, so that’s--so that EBITDAX number is not a ratable number to use for the remainder of the year.
But even with that impact in the first quarter from EG, we still had strongly flowing free cash from places like the Bakken and the Eagle Ford that more than took up the slack, hence the reason we were able to generate $80 million of organic free cash flow in the quarter.
Yes, I’d just add that the $80 million free cash flow number is not directly comparable to an EBITDA, a $65 million EBITDA number. There is in-country tax on this.
Yes - 25% tax rate.
[Indiscernible], so keep that in mind as well.
Okay, good point. Appreciate it, guys.
Thank you. We have no further questions. I will now turn the call over to Lee Tillman for closing remarks.
We recognize that investors have choices, and we appreciate your interest in Marathon Oil. Execution excellence leads the way in our company, and I’d be remiss without thanking all of our dedicated employees and contractors who deliver on that mandate 24/7, quarter in and quarter out. Thank you very much, and that concludes our call.
Thank you. Ladies and gentlemen, this does conclude our conference call today. We thank you for participating, and you may now disconnect.