馬拉松石油 (MRO) 2017 Q4 法說會逐字稿

Welcome to the Marathon Oil Corp. 2017 Q4 Earnings and 2018 Budget Conference Call. My name is John Oak, I'll be your operator for today's call. (Operator Instructions) Please note that this conference is being recorded. And I will now turn the call over to Zach Dailey.

Thanks, John, and good morning to those listening. Last night, we issued a press release and slide presentation that address our fourth quarter results, full year 2017 results and our 2018 capital budget. Those documents as well as our quarterly investor packet can be found on our website at marathonoil.com.

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 Tillman, our President and CEO, who will provide a few opening remarks before we begin Q&A.

Thanks, Zach, and thank you, to everyone for joining us this morning. I'd like to begin with some highlights from 2017 followed by some key messages around our 2018 capital program. 2017 was truly a pivotal year in our ongoing transformation to a U.S. resource play focused independent E&P. We made progress across every element of our playbook: balance sheet, cost structure, portfolio. And we achieved high return growth within cash flows at moderate oil pricing. Our differentiated position in the 4 lowest-cost highest-margin oil plays demonstrated its strength as we consistently outperformed quarter after quarter.

Importantly, we balanced our 2017 CapEx and dividend with cash flows, excluding the late December U.K. tax settlement under appeal, while WTI averaged just above $50. We achieved that cash flow neutrality while delivering on all our 2017 commitments, including near the top end of our total company production guidance, driven by a strong 31% exit rate from our U.S. resource plays.

We ended 2017 with a stronger balance sheet from our $1.75 billion reduction in gross debt, a lower cost structure with $115 million in annualized interest expense savings, a 35% reduction in unit G&A expense over the last 3 years and the lowest U.S. unit production expense since becoming an independent E&P. We also finished the year with a more concentrated portfolio with the sale of Canadian Oil Sands and entry into the Northern Delaware, an outstanding consistent execution across all 4 basins as evidenced by peer leading well results.

Our 2018 capital allocation philosophy is fully consistent with how we manage the business in 2017, which is to deliver a returns-focused program that balances cash flow with our CapEx and dividend and do that at a moderate oil price of $50 WTI. We'll direct over 90% to the U.S. resource plays and maximize corporate returns by focusing on high-efficiency development in the Bakken and the Eagle Ford while providing flexibility for the Northern Delaware and Oklahoma to transition to multi-well pads at the appropriate pace while continuing delineation and appraisal work.

Our 2018 program was informed by the results generated in 2017, strong performance across the Eagle Ford even as we move farther west outside Karnes County, best in basin wells in both our Myrmidon and Hector areas of the Bakken. Outstanding results from our first STACK volatile oil infill development and continued learnings from our black oil infill pilot program and impressive early results in the Northern Delaware.

Internal competition for our development CapEx is broader, more diverse and more intense than it's ever been. You should expect our capital allocation to remain a dynamic realtime effort as we continually optimize across our 4 basins, leverage learnings and respond to performance trends as well as the macro environment.

Moving to some specifics for the 2018 capital program. Our returns-focused development capital budget of $2.3 billion is self-funding at $50 WTI, including our $170 million dividend and will generate meaningful free cash flow at $60 WTI. We are very oil leveraged and we will generate an incremental $500 million in operating cash flow for a $10 move from $50 to $60 WTI inclusive of our hedges. We have about 50% of our oil and about 20% of our gas hedged for 2018.

We forecast total 2018 production up 12% at the midpoint compared to 2017 on a divestiture basis, while total annual oil production is expected to increase about 18% at the midpoint on the same basis, driven by 20% to 25% annual oil growth in the U.S. resource plays. This growth is simply an outcome of our returns-focused capital allocation. As a reminder, we continue to exclude Libya from all of our production guidance.

Almost 60% of the development budget will be allocated to the high-return Eagle Ford and Bakken assets, which have demonstrated step-change performance operating at scale. Approximately 1/3 of the development budget will be allocated to our Northern Delaware and Oklahoma assets where a majority of 2018's drilling activity will transition to multi-well pads while continuing strategic delineation and appraisal.

At a basin level, I couldn't be more proud of our Eagle Ford team in 2017. They delivered their best year of well productivity despite navigating Hurricane Harvey. Activity levels in 2018 will be ratable, similar to last year, while we continue our successful high-intensity engineered completions in both our core Karnes County wells and Atascosa County while leveraging the benefits of LLS pricing. We expect Eagle Ford 2018 annual production to be essentially flat while generating free cash flow.

For the Bakken, we've now delivered 15 of the 25 best middle Bakken wells in Williston Basin history, 7 of which came in the fourth quarter. Our step change in completion design and application of technology, paired with world-class rock, has proven to be a powerful combination.

In 2018, we'll further test our upgraded completion design in other parts of Hector as well as Ajax while keeping the majority of CapEx directed toward our high-confidence Myrmidon area. We expect strong growth in the Bakken while generating free cash flow at $50.

In Oklahoma, we delivered an impressive 9-well STACK volatile oil infill that is exceeding early expectations with the new wells averaging over 1,800 boe per day IP30. In the black oil window, we continued our pilot program with our third and easternmost infill, and these results have helped inform our pace of activity in 2018 to ensure we determine the most economic development solution for each and every DSU. Oklahoma will deliver self-funded growth this year, including secondary target delineation and a transition to 80% pad drilling while completing our STACK leasehold requirements by year-end.

And finally, Northern Delaware demonstrated remarkable execution in Q4 with average IP30s from all 11 wells of over 1,800 boe per day, including a 2 well pad averaging almost 3,300 boe per day that was 62% oil.

In 2018, we'll focus on the Upper Wolfcamp, the X-Y and Third Bone Spring. A portion of the 2018 CapEx will be spent increasing our year-end operational DUC inventory by 65% as well as testing the Avalon and First Bone Spring later in the year.

As a result of this concentrated capital allocation, the U.S. resource plays will increase to about 70% of the total company production mix, driving a natural expansion in margins. Through our portfolio transformation and cost structure reset, we expect to increase 2018 unit EBITDAX margins by 35% relative to 2015 on a price normalized basis.

Additionally, we expect to deliver a strong annual rate of change on the key corporate performance metrics of cash return on invested capital or CROIC or cash flow for debt-adjusted share, both of which have been integrated into our executive compensation structure. We recognize there is no single perfect performance metric to determine the health of an E&P business, and we must consider many financial and operating metrics.

However, we believe when viewed together, these 2 metrics are indicative of the performance of the current development capital program as well as the overall strength of the business. They are transparent and readily determined from publicly available data. At $50 WTI, we see a year-over-year improvement in CROIC of about 30%, while at $60 WTI, that increases to over 50%, readily outpacing our production growth. Cash flow per debt-adjusted share also enjoys a material year-over-year improvement.

Our development capital program is balanced to live within our means, inclusive of the dividend at $50 WTI and generate meaningful free cash flow at $60. It is certainly refreshing to be having a conversation about free cash flow generation, and we have already established a track record of cash flow neutrality in 2017, so this represents the next natural progression of our business model.

Should we continue to see pricing above $50 or execute further divestments, we have multiple options: balance sheet, resource play leasing and exploration, bolt-on acquisitions and direct return of capital to our shareholders. But any action will always be driven by seeking the greatest long-term value for our shareholders.

Expanding a bit on our options. On the balance sheet, we have done some great work in 2017 and as a reminder, we have yet to receive final proceeds of $750 million from the Oil Sand sale. We will continue to seek opportunities to lower our corporate costs.

We have an active resource play exploration team that is pursuing low entry cost organic leasing opportunities that would be accretive to long-term returns. Our business development team continues to assess bolt-on acquisitions in core basins that create synergistic combinations, not just simply adding more acreage. And finally, enhancing our direct return of capital to our shareholders that builds upon our already competitive dividend of $170 million per year.

In closing, a remarkable and pivotal 2017 has positioned us strongly for 2018 success. We have transitioned from portfolio transformation to execution delivery at scale across our differentiated position in the 4 lowest-cost, highest-margin U.S. resource plays. And we met or exceeded our 2017 commitments while living within our means, including paying our dividend at just above $50 WTI.

We expect our margins to expand as we continue to shift our production mix to a greater weighting of U.S. unconventionals, better aligning our volumes to our investment concentration. This margin expansion story, coupled with outstanding financial flexibility, will help drive corporate level improvements in both cash return and cash flow growth per debt-adjusted share and position us favorably to outperform the competition through the end of 2018 and beyond.

I want to conclude by thanking all of our dedicated employees and contractors who have made such a difference in 2017, driving execution excellence in every asset, every quarter. Thank you. And with that, I'll hand it back to the operator to begin the Q&A.

(Operator Instructions) And our first question is from Arun Jayaram from JPMorgan.

Good morning, Lee. I was wondering if you could maybe comment -- within the organization, the technical group, et cetera? I wanted to flag Slides 13 and 15, where the company really has gone from drilling, dare I say, kind of mediocre results in some of the basins to some of the best results that we're seeing in E&P today. So I just wanted to see if you could maybe comment on internally some of the things that you've done really to drive these improvements in overall results.

Yes. Thank you, Arun, for the question. I appreciate you recognizing those 2 teams because there really has been a remarkable uplift and truly a step change in performance and [where] really 2 of our core developmental areas as we look into 2018. And Arun, as you might expect, it's not one thing that's driving that performance. It's a collection of things. And certainly, from a technology aspect, I truly believe that what you're seeing here is also a bit of the strength of our 4-basin model approach where we're able to learn across basins, apply those learnings very rapidly across all of our major plays. So when we identify a best practice or a technique that's proving dividends in one of our plays , we're very rapidly transferring that into our other basins, and that allows us, I believe, to get up that learning curve very, very quickly.

Great, great. And just my follow-up, it's just -- I just wondered, Lee, if you could go through kind of your land strategy in the Delaware basin and opportunities to kind of increase your acreage position in the core, expand your opportunities to do longer laterals, et cetera.

Yes. Thanks, Arun. Our strategy really in Northern Delaware is less about just gross acreage adds and it's more about finding acreage that fits a very specific criteria. And we're going to do that through swaps and trades as well as through some small bolt-ons, and we've completed some of all of the above. But that criteria echoes just what you were addressing, Arun, which is we're looking for those synergistic adds that are going to enhance our overall working interest that will allow us to convert nonoperated to company-operated wells and will provide us more optionality to have longer laterals in the portfolio. And so we continue to work that hard. It's still very competitive in the Northern Delaware. I mean, you probably will have noted in our material that we're a little cagey even about the location of some of our well results, and it's because it remains an active area. And our land team and our asset team are out there looking for those kind of hand-in-glove fits that are going to make a difference in our position.

Our next question is from Paul Sankey from Wolfe Research.

Good morning. We love the returns targets. Can you just talk about the baselines? This is Slide 4 obviously. The baselines from which you're growing the delta. Does that make sense?

Yes, it absolutely makes sense, Paul. We try to provide in the supplemental data all the pieces needed to do the math. But just to be really clear, we're more focused on the rate of change. But when we look at the absolute metrics in 2017, CROIC is right around the 12% baseline and the cash flow per debt-adjusted share is right around about a buck 90, or a little bit more than that. So that's the baseline that we're coming off of.

And just let me double check here. So the -- and this is -- the improvement obviously is going to be a 2018 over 2017 improvement that you're targeting?

That's correct, yes. What we try to do was provide at least line of sight on what that year-over-year kind of rate of change or momentum effect is going to be doing because we think again that it's a bit indicative of multiple things obviously, the portfolio moves. But clearly, that transition with more of our volumes being sourced from the unconventionals and the impact of the 2018 capital program as well.

Right. And then given the uncertainty around oil prices always, can you just confirm that you'll be pretty much sticking with the capital program, let's say, regardless of whether oil was to go to $70 a barrel or some sort of upside? And I guess, the question ultimately would be whether you want to accelerate more in the Delaware given that you're essentially pursuing the Bakken and Eagle Ford first. I wonder whether there was a temptation to accelerate -- do more if there was more cash available or whether you're happy with the scale of spending and growth.

Yes, thanks, Paul. Just with respect to your first question about the development capital program. We feel that, that program is well optimized across all 4 basins. It fits within our overarching criteria to deliver that capital program within cash flows at a high rate of return and do that at a moderate oil pricing, so we don't visualize flex in that development capital program. In terms of acceleration, we always test how much, how fast can we go. And in many of these basins where we're still just migrating from kind of appraisal, delineation and the early phases of multi-well pads, there is an appropriate pace where you can process the data, learn from it and then drive those learnings into your forward decision-making. And so there is a balance there between smart acceleration and just accelerating for acceleration's sake.

Okay. So that -- having said that, you're really firm on the CapEx program for this year and so it's going to be a moot point?

Yes, clearly, we're going to always be examining the program throughout the year as we get new data. And in my opening comments, Paul, I talked about the fact that we don't view our capital allocation as static, but that allocation is going to be within that framework. Could we redeploy a little bit of capital from one basin to another? Sure, that's absolutely possible. But in terms of the construct and the level of the spend, we feel very comfortable with where we are on the $2.3 billion.

Our next question is from Jason Gammel from Jefferies.

A couple in the Eagle Ford, if I could, please. I've seen some pretty outstanding results out of -- not only your Austin Chalk wells but from others in the industry. I was curious, just in terms of that play, how much running room do you think you actually have there? And then maybe if you could further comment on the remaining drilling inventory that you have in the Eagle Ford as a whole that would be, let's say, less than $50 breakeven price. And then finally, if I could please, you talked about bolt-on acquisitions. Would you see this as an area where you could potentially be a pretty natural consolidator of properties given that many others in the industry have kind of walked away from the play to a certain extent?

Yes. Let me take a couple of those and I may pitch the Austin Chalk question over to Mitch to address and talk about the specifics there. But I think in terms of inventory, Jason, we have talked in the past about kind of, at current run rates, in terms of wells to sales, we've got about a decade of high-quality inventory, right? Now I know you are referencing a specific kind of breakeven point. But we think that, that inventory is a solid inventory to speak from when we address the Eagle Ford. In terms of bolt-on opportunities, in our core plays, we're always looking for small opportunities that might be accretive to our overall footprint. And we certainly evaluate those on an ongoing basis through both the asset team as well as our business development teams. So that's always on the table. I mean, a lot of folks have solidified their positions there. We are in a very high-quality area of the Eagle Ford, which makes it a little challenging because the folks usually around us are also pretty comfortable with their position as well. But we're always going to keep the aperture open there. So with that, maybe I'll let Mitch just talk a little bit about the well results and specifically Austin Chalk.

Yes. Sure, Jason. This is Mitch to address the Austin Chalk specifically, certainly, we are encouraged by our most recent test there, more so in the northeastern portion of our position within the Eagle Ford. We will continue to test the Austin Chalk and extend the area of delineation there away from the most recent wells. But our program will largely be focused, like it was last year, on 40-acre lower Eagle Ford development, extending high-intensity completions and engineered flowbacks into Atascosa where we're seeing significant uplift in the productivity and the well returns from that program, which is really upgrading and has upgraded the overall competitiveness of the Eagle Ford in driving a fair chunk of that year-over-year improvement that we showed on the slides.

I'd also maybe just mention too, Jason, as we have stepped more to the west in the Eagle Ford, some of those areas are also much more lightly developed than some of our core areas. And so there's a considerable amount of running room there to elevate those returns into kind of our top-tier type of economic returns. So a tremendous amount of opportunity, and the team is generating some really terrific results out to the west.

Yeah, the results have been very impressive. Very helpful. Thanks, guys.

Our next question is from Pavel Molchanov from Raymond James.

When you talked about not envisioning any upward flexing of the capital program, essentially, should we assume that, to the extent that you were generating free cash flow at $60, you're going to be putting the cash on the balance sheet? Or are there other uses you anticipate for that?

Yes. Again, just to reiterate, we're very comfortable with the capital program, irrespective of the ultimate prices that we see in 2018. But in respect that if we do see consistent and sustainable free cash flow generation through the year, which obviously would be north of our breakeven and certainly in the $60 range, we would be -- we're going to go through our priority list at that point. And what we're going to be driven by is what is in the highest and best interest of the shareholder, what's going to generate the best long-term value. We always start with the balance sheet. I give a ton of credit to Dane and the team here for really doing some outstanding work on the balance sheet in 2017 through some very unique features of our capital structure. And so I would say, a lot of maybe some of the low-hanging fruit there we've captured, that by doing so, that also brought along with it some pretty significant corporate cost reductions. We're always going to test our comfort levels with the balance sheet first and also seek those opportunities that can continue to drive our corporate costs even lower.

Once we get kind of beyond the balance sheet, I think our next view is taking a look at some of those other high-return opportunities. And the two that really stand out to us, and we've talked about a couple of these already is really, one, our ability to drive our resource play exploration opportunities where we're looking for low-entry cost, potentially very high return and accretive return opportunities in and around current basins as well as even looking at new plays and new basins. We've already talked about bolt-on opportunities. We mentioned the Eagle Ford, but more specifically, the Northern Delaware. And then finally, we have to reflect on the fact that we're already returning $170 million of dividends directly to the shareholder. But if we meet those other high-return opportunities, that's a discussion that we have each and every quarter with our Board of Directors around -- are we calibrating that dividend and that direct return to shareholders correctly? So that's going to really be the priorities that we'll work through in that instance where we are seeing that consistent and sustainable free cash flow generation.

Okay. And a follow-up about the North Sea. This is obviously now the by far, the smallest part of your portfolio. You have talked about selling it in the past, and we are actually seeing pretty decent pickup in M&A activity in both the U.K., Norway and even Denmark. So with the kind of appetite in the industry for some of these assets, would you be perhaps looking to revive that asset sale effort?

I think that as you stated, we made an effort to monetize the U.K. asset when we sold our Norwegian sector asset back in 2014, and were not able to, in our view, capture value for that asset that time. A lot of credit to that team that they have continued to drive costs down, improve reliability, lower the abandonment costs and do many things that are continuing to improve the overall economics of that asset. But -- however, we would view that as sitting outside of our core assets, which are the 4 U.S. resource basins, plus EG. So having said that, I agree with your assessment that since 2014, we have had new players come into the North Sea that offer potentially different monetization routes. And the business development team will continue to assess that market and look at those opportunities in due course. But there's no doubt that the U.K. remains outside of our core portfolio.

(Operator Instructions) Our next question is from David Heikkinen from Heikkinen Energy Advisors.

The perspective on Eagle Ford inventory was helpful. How many years do you think you can continue to grow and sustain the Bakken?

Yes, we haven't provided a fulsome update on the Bakken inventory. And David, a lot of that has to do with the fact that we're just in a high rate of change in the Bakken today with the success obviously that started in the geologically advantaged Myrmidon area that's now carried down into at least the higher-quality areas of the Hector. We're pushing south in Hector this year. We'll also do some testing in Ajax. So given all that rate of change and the fact that we really don't have a tremendous amount of production history on the newly-designed completions in the Hector, we really need to get some time there so that we can do, I would say, a more fulsome job of providing a comprehensive update on the Bakken inventory that reflects what is a tremendous amount of new data and new information.

So maybe end of the year, start getting sort of that thought process of everything together. But it looks pretty sustainable on our numbers, so it looks good to us. On the other side, Oklahoma resource plays, you made a statement that the Eve pilot -- you announced 5 of the 6 wells and it informs your pace of development and the best economics. What -- can you kind of characterize what informs means, and like what that -- what do you think about in the black oil window?

Yes. I'm going to kick that one over to Mitch, who can probably give us a little more color just across the black oil window in general.

Yes, sure, David. Let me kind of a start from a little bit higher level that I think addresses your question. If you think about the normally pressured black oil area versus the overpressured area of the STACK, there's been much less activity in the normally pressured area. We drilled 3 pilots over in that area in pretty rapid succession and really, testing the higher end of well spacing. We had between 5 and 6 infills plus a parent in the 3 pads, but effectively tested equivalent spacing between 6 and 9 wells per section in those 3. The results haven't met our expectations thus far. And we think, with our returns-focused capital allocation, it suggests it's prudent to moderate our pace there. Let us integrate those learnings and concentrate more of our efforts into the overpressured area in the near term, where there's been more industry activity. We've actually progressed into the development mode, particularly in the oil window in the overpressured area. And as you mentioned, or others have mentioned, certainly very encouraged by the 9-well Tan infill test.

What I would say in terms of informing, this play is certainly not ubiquitous. We're integrating massive amounts of subsurface completion and production data, integrating that with all available tools and technology to get down to essentially a DSU-by-DSU development solution, the right combination of both well spacing and completions. I think notionally, we would say, the Eve was our furthest eastmost test. And between aggregating all of that data it would suggest on the far east sides, the solution will likely be less than 6 wells per section, but well count increasing, as you move west, into the thicker and more pressured areas and certainly early data from the Tan at 9 wells per section is very encouraging. But we need to monitor that longer-term.

Our next question is from Biju Perincheril from Susquehanna.

I had a question about -- in the Eagle Ford, with the new -- the completion improvement. Have you tested anything in the Gonzales area, the Barnhart area?

Sure. We have concentrated a fair bit of our activity in the Karnes area. But as we've disclosed for the last several quarters, we're progressing more and getting more concentrated down into Atascosa. But we also have tests across the entire play, and that would include Gonzales and Barnhart. But we disclosed every quarter the wells to sales and where our activity is, and that's probably the best measure of -- seeing how we're allocating capital across our position.

Got it. And then some of these completion improvements in the basins modeling that you're doing, can you talk about how close you are to applying that? Or are you applying that now in the overpressured area of -- in the STACK?

I think if I follow the question, Biju, we obviously have an extensive position across the STACK, in all phase windows, in all pressure regimes, including both company operated and operated by others, nonoperated positions where we have access to all of the details around completion style. Over the past 18 months or so, particularly in the volatile oil area, we tested a pretty extensive range of completion parameters, including varying proppant loading from 1,500 to up over 3,000 pounds per foot, different stage phasing, cluster spacing and fluid composition. And so we do feel like we're narrowing in on the right completion design there, which we employed on the Tan and have had very successful results previous to the Tan, on our parent wells in that area. And so we feel like we're honing in on the right answer in that -- in the overpressured window, yes.

I'll now turn it back over to Zach Dailey for closing remarks.

Thanks, John, and thanks to everybody for joining us today. We appreciate your interest in Marathon Oil. We look forward to speaking with you soon.

Thank you. Ladies and gentlemen, that concludes today's telephone conference. Thank you for participating, and you may now disconnect.