馬拉松石油 (MRO) 2015 Q3 法說會逐字稿

Welcome to the Marathon Oil Corporation 2015 third-quarter earnings conference call. My name is Sylvia and I will be your operator for today's call.

(Operator Instructions)

Please note that this conference is being recorded. I will now turn the call over to Chris Phillips. Mr. Phillips, you may begin.

Thank you, Sylvia. Good morning and welcome to Marathon Oil Corporation's third-quarter 2015 earnings call. I'm Chris Phillips, Director of Investor Relations. Also on the call this morning are Lee Tillman, CEO and President; JR Sult, Executive Vice President and CFO; Mitch Little, Vice President International and Offshore Exploration and Production Operations; Lance Robertson, Vice President North American Production Operations; and Zach Dailey, Director of Investor Relations.

As has become our custom, we released prepared remarks last night in conjunction with the earnings release. You can find those remarks and the associated slides at marathonoil.com. As a reminder, today's call is being recorded, and our comments and answers to questions 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. Please refer to the aforementioned slides for additional information on forward-looking statements.

Reconciliations of any non-GAAP financial measures we discuss can be found in the quarterly information package on our website. With that, I will turn the call over to Lee.

All right. Good morning. Thank you, Chris. Our priorities this year have been exercising capital discipline, reducing costs, capturing efficiencies, progressing our non-core asset sales, and protecting the balance sheet. And our most recent actions have been fully consistent with those objectives.

Last Thursday we announced the decision by the Board of Directors to adjust our quarterly dividend from $0.21 per share to $0.05 per share. We felt that this action was prudent, in the best interest of all shareholders, and appropriately addresses the uncertainty of a lower-for-longer commodity price environment. It will increase annual free cash flow by more than $425 million, and aligns with our priority of maintaining a strong balance sheet through the cycle.

The additional capital flexibility is essential to support growth from our deep inventory of investment opportunities in the US resource plays when commodity prices improve. Further, it is another step in the transformation of Marathon Oil from its integrated legacy to becoming a leading independent E&P company focused on capturing value in the US unconventional resource plays.

Turning to the third quarter, we delivered operational results that reflected consistent execution, efficiency gains and lower costs. The third-quarter capital investment in exploration program came in below expectations, down 7% sequentially to $623 million. We have been able to reduce our 2015 program by $200 million to $3.1 billion, primarily through a combination of US resource play efficiency gains and phasing of international projects.

Total Company net production from continuing operations, excluding Libya, averaged 434,000 oil-equivalent barrels per day, a 6% increase over the year-ago quarter and a 7% increase over the prior quarter. Record production from oil sands mining and higher production from Equatorial Guinea contributed to the increase from the prior quarter. We are on pace to achieve the high end of our total Company 2015 production growth guidance at 7% year over year, and US resource play growth at 20%, even with the $200 million reduction to our 2015 program.

In The US resource plays net production averaged 212,000 oil-equivalent barrels per day, up 10% over the year-ago quarter and down 4% over the prior quarter. Our quarterly variance was driven primarily by lower sequential production from the Eagle Ford due to timing of wells to sales late in the third quarter and step out and delineation drilling tests. Our asset teams target the right balance of high confidence development activity and continued resource delineation that positions us for growth as we look through the current cycle.

In the case of the Eagle Ford this quarter, the team was focused on development drilling in core Karnes County, while also testing the limits of delineated acreage. We had another quarter of solid reductions in completed well costs, faster feet per day drilled, and more frac stages completed per month. We also previously announced additions to Eagle Ford 2P resource of 165 million oil-equivalent barrels, driven by the upper Eagle Ford and Austin Chalk.

Though our operated Oklahoma resource basins program is still dominated by leasehold activity, we brought our first SCOOP Woodford downspacing pilot online late in the third quarter. Early results are in line with our type curve and supportive of 107-acre spacing. Importantly, the learning curve improvement as we drilled and completed the well illustrate the potential for Oklahoma to become significantly more efficient when we move to development mode. During the quarter we announced a 35% increase in SCOOP and STACK 2P resource, adding 400 million oil-equivalent barrels.

The Bakken team had an outstanding quarter, despite reduced completion activity, delivering 61,000 net oil-equivalent barrels per day, in line with second-quarter volumes. Results were driven by continued outperformance from the Doll pad wells in West Myrmidon, enhanced up time, as well as consistent performance from our three downspacing pilots. The team continued to aggressively attack costs, lowering direct expense in the quarter from a variety of factors -- reduced water handling costs in contract services, getting more of our product on pipelines, and greater efficiency gains from workover rigs.

International productions and sales volumes were higher in the quarter, primarily as a result of the performance of the new Alba C-21 well, the EG wireline intervention program, and high operational availability. The EG compression project achieved mechanical completion during the third quarter and is preparing for transportation from the Netherlands to site. Installation and startup is set for mid 2016.

Oil sands mining reported outstanding operational results in the third quarter, recording the highest level of production in the history of the asset, as well as the lowest operating cost ever per synthetic barrel. These results were driven by increased reliability and up time, as well as an intense focus on reducing costs.

We've made great strides so far this year focusing on those elements of the business that we control by reducing activity levels and capturing capital efficiencies. We have also reduced total Company E&P production expenses and G&A costs, excluding special items, by about $136 million or 28% for third quarter 2015 compared to the same quarter in 2014. Similarly, on a year-to-date basis, the savings amount to over $290 million, over 20%.

Drilling efficiency remained a focus across our US unconventional plays, with our best Eagle Ford rig drilling a well that averaged 3,000 feet per day in the third quarter, similar to the exceptional pacesetter performance in the previous quarter. This performance was achieved while maintaining our geo-steering accuracy to land in the target window 98% of the time. Our other two areas, the Bakken and Oklahoma resource basins, also continued to show sustained improvement in their drilling efficiency.

Portfolio management remains front and center. And we continue to make progress advancing our plan of divesting at least $500 million of non-core assets. What we have identified for sale are non-core E&P and midstream assets, operated and non-operated, that simply do not compete for capital today, given the depth and breadth of our inventory in US resource play, and will likely have higher value in someone else's portfolio.

During the quarter we announced our strategic intent to scale back our conventional exploration business, as the success of our US resource plays has continued to raise the bar for capital allocation. Commensurate with this decision we signed an agreement to divest our exploration acreage in East Africa.

Last week we provided initial guidance on our 2016 capital investment and exploration program, as we continue to progress through the planning process with the overarching goal of living within our means next year, inclusive of dividend and non-core asset sales. Based on our current outlook and preliminary plan discussions, we would anticipate a total Company 2016 program of up to $2.2 billion, which would give us the flexibility to deliver 2016 annual average production in the US resource plays flat to 2015 exit rates. This represents a significant reduction from our $3.1 billion program in 2015, but at least three-quarters of our 2016 program is expected to be directed toward the US resource plays, which offer our highest risk-adjusted returns. We expect our 2016 budget to be approved by the board of directors later this year.

There is no doubt that the macro environment continues to challenge the industry, but one thing remains clear -- Marathon Oil is not opportunity limited. We have profitable inventory even in a lower-for-longer commodity price scenario, as lower cost, capital efficiency and enhanced productivity continue to reduce breakeven prices and improve our economics.

Our priority remains balance sheet strength and capital flexibility in 2016. And we have a workforce that is responding to the challenge and positioning our Company for success today and through the cycle. I want to pause and personally thank and recognize our dedicated employees and contractors who continue to execute and deliver results, while protecting our license to operate each and every day despite the distractions and uncertainty of the current environment.

With that, I'll hand it back to Chris to begin the Q& A.

Thanks, Lee. Before we open the call to questions we would like to request that you ask no more than two questions with associated clarifications, and you can re-prompt as time permits. With that, Sylvia, we will open the lines for questions.

(Operator Instructions)

Ilya Balabanovsky, Morgan Stanley.

Good morning, gentleman. This is actually Illya. Evan got stuck on a refining call so I'm going to fill in for him. Thanks for taking the questions. You put out the up to $2.2 billion CapEx guidance for 2016 out there last week. What is the primary governor on your activity next year? Are you trying to keep resource play production flat? Are you trying to limit spending to a certain level? Or is the primary goal to reach certain specific targets, specific goals in individual basins?

Thanks for the question. Of course, for us, as we stated, the objective for us in 2016, particularly in the current pricing environment, will be balance sheet protection. And, of course, balancing our cash flows and living within our means. That is our primary objective. We are still very much in the planning cycle. The numbers we presented are preliminary. The work is ongoing. But we felt it important, as we communicated the change or the adjustment in the dividend, to also pair that up with at least an early view of 2016 outlook.

And a follow up, what does your Oklahoma program look like in 2016, both in terms of rig count and in more qualitative terms? How you're thinking about operated versus non-operated activity? To what extent is it going to be driven by HBP? Will we expect to see more Woodford wells because you are trying to hold the entire depth? Can you give some color on that? Thank you.

Yes. Thus far, of course, because we are still very early in the planning process, we haven't provided quite that level of granularity down to the basin level. But that will be coming as we finalize the plan. However, what I will share is, as incremental cash flow comes available, and we think about our program in 2016, due to the returns and the growth potential in Oklahoma, we expect it to compete very favorably in the capital allocation progress. So, I would just say more to come on that point as we finalize our plan.

Doug Leggate, Bank of America Merrill Lynch.

Thank you. Good morning, everybody. Lee, I wonder if I could ask a little bit about how you are preparing the portfolio for, let's be optimistic for a second, some kind of rebound in the commodity over time. You've obviously right-sized the dividend and you've got clearly significant depth in the Oklahoma basin, in particular. As you look at incremental capital allocation going forward, where would you see the priorities? And if I may tack on an add-on there, how do you see reallocating capital from your non-core assets? Can you maybe quantify how much capital may be associated with the non-core stuff, as well? And I've got a follow up.

Okay, very good. Thanks and good morning, Doug. Of course our decision around the adjustment in the dividend, one of the aspects of that was, in fact, the capital flexibility that it provides as we think about driving more allocation into the resource plays as we see more constructive pricings.

But as we think about where that first incremental capital may be directed, Doug, the way I think about it is it's going to be driven by economics, which today says that capital would be targeted toward incremental activity in both the Eagle Ford as well as ultimately Oklahoma, expanding our operated program in Oklahoma.

In terms of the non-core asset question, maybe let me step back and just address that in general, first and foremost. We have high confidence in our $500 million target that we have put out on the non-core assets. We have, of course, shared that we had, in fact, closed the earlier announced deal in East Texas/North Louisiana. We have many of those opportunities in process today and continue to feel that there is a market out there for the right type of assets. So, our confidence in that remains very high.

There will no doubt be implications, as we are successful in those transactions, from a capital avoidance standpoint. But it's probably a bit premature to get into those numbers until we are actually able to execute deals.

I appreciate that. My follow-up is really in your earlier press release you talked about the $2.2 billion, holding the exit rate in the unconventionals flat. I know it's a little early for 2016 yet but one of your partners has talked about the fairly hefty maintenance you're going to have in Equatorial Guinea. So, I wonder if you could give us just some order of magnitude as to how you see the portfolio production outlook with that level of spending going into next year? And I will leave it there. Thanks.

I believe what you are referring to, Doug, as we look out at 2016 there will naturally be associated scheduled and planned downtime as we do the installation of the compression project. That, of course, is fully accounted for in the preliminary numbers that we have shared thus far. So, that work is integrated into that.

As we think about that 4Q exit that we talked about, which was really talking about the resource play 4Q exit to full-year 2016 average, that's really outside of the total Company. But when you think about it from a total Company perspective, given that we have provided direct guidance from the resource plays, I like to think about it in really a few large buckets. One is, of course, Equatorial Guinea, which will largely be flat ex the downtime that I just addressed. Two, oil sands mining, which will have largely, again, a flat profile ex planned maintenance and turnaround.

We do have some other North America onshore assets that will have relatively shallow declines. And then, of course, and our conventional GoM and mature UK businesses, which albeit relatively small volumes, we'd expect those to have typical mature declines. As you put that overlay on it, I just want to try and give a feel for what volumes might feel like in their totality in 2016.

Ed Westlake, Credit Suisse.

Congrats on a lot of tough decisions so far this year for the downturn. I've got two questions looking at perhaps further out. The first one is on the Eagle Ford. Folks are worried about your tier one Eagle Ford inventory relative to tier two. Maybe just a reminder of how much tier one years of drilling you think you have and then what sort of degradation you think there is in the portfolio as you get out towards the fringe.

Ed, good morning. This is Lance. I think as we look at it, perhaps what I'd start with is, earlier in this quarter we actually disclosed an unconventional resource portfolio in North America of 5,500 wells. And of that portfolio I think we described the first five years of it, 77% of that returns better than breakeven at $50 flat oil. And of that inventory, Eagle Ford is by far the largest component. And I think we have confidence we have many years of what you describe as tier one or high-quality development left in the asset, Ed.

And then switching to the SCOOP, probably on the same topic, really it's only the XLs on the current economics that really look like they can compete with some of the best shale that is in other basins. Where do you think you can get the D&C costs down to perhaps for the shorter laterals? How many XLs do you think you can drill as a percent of the total? And, then, where do we think we are in the completion cycle in terms of optimization to boost the EUR? I'm just trying to get a sense of how much momentum there can be in that play in terms of recycle ratios and returns.

I think maybe I would start at the last end of that question first. I think we have a lot of confidence that we are so early in the development cycle in both of the Oklahoma resource basins, both SCOOP and STACK, that we are nowhere near that highest efficiency, best completions yet. So, we expect well productivity to continue to increase over time, particularly as we get to scale and we have more opportunity to experiment in a structured way.

Similarly, maybe perhaps best illustrated by the Smith pilot that was in our earnings deck, we also expect that more mature development cycle as it unfolds for us to really be able to materially impact the capital cost. I think that example, we are down 33% from the front end to the back end of that pad, is emblematic of what we expect on a full-cycle basis. I have complete confidence that we're going to continue to deliver both better costs and better productivity in Oklahoma. And that's going to help both the XL wells and the SL wells compete favorably for capital across the cycle.

Brian Singer, Goldman Sachs.

Thank you. Good morning. For investors who have looked to Marathon historically in part for that dividend, now as you have made the tough decision to cut the dividend, is there an offsetting metric that you and the Board are looking to improve or bolster as a result of that cut? It could be production growth, maybe corporate returns. Or does the dividend cut just help you to maintain your balance sheet objectives, which would potentially argue for a dividend increase if oil prices were to rise?

Brian, I believe our board is looking at it quite holistically. They are looking at, in aggregate, for all shareholders, what is the model based on our portfolio that will deliver the best total shareholder return.

When you think about the logic I believe that the Board went through with the leadership team, it was really looking at the dividend in the context of appropriately addressing the lower-for-longer environment and the uncertainty that is associated with it. It was really making certain that we could protect our balance sheet through the cycle. And then, finally, and I think most importantly, it provides us that capital flexibility going forward as we see more constructive pricings to drive more investment at a higher return into the US resource plays. And, of course, it gave us an increase in our free cash flows by greater than $425 million.

I believe the Board looked at it holistically. It looked at it in the context of the preliminary plan data that we had to share with them at the time. And it was really that collective logic that went into it.

Great. Thanks. The follow-up is with regards to one of the earlier questions on Eagle Ford, on the tiering. The oil as a percent of the total in the mix, just come down a bit here. Can you talk to whether that is timing based on the timing of completions, and how the oiliness looks of the remaining inventory in the remaining locations there, how that translates to the 2016 program.

Brian, our Eagle Ford asset has a substantial oil component, a substantial condensate component, and some wet condensate, a little bit of that, as well. In this environment, the lower-for-longer, in a disciplined way we are choosing the highest return opportunities at current pricing. The condensates generally have been providing those returns, so we are seeing a small change in mix to a little bit less oil overall.

We still have large inventory in the oil and the condensate left to develop in the future. And depending on commodity prices we're going to consistently choose those highest return opportunities. As large as the base is overall we don't expect the mix to change very much on the long-haul basis.

Great. Thank you.

David Heikkinen, Heikkinen Energy Advisors.

Good morning, guys. Thanks for taking my questions. From your second-quarter update to your third-quarter update in the Eagle Ford, your net wells to sales increased. Can you talk about how the increase for this year and what the expectation is now for fourth quarter versus net wells drilled didn't change.

Sure. I think one of the things we have seen, David, over the balance of this year is we continue to get more and more efficient overall, both in the completion cycle and in the drilling cycle. I think we have illustrated that in the deck. We continue to avoid building an inventory of drilled but uncompleted wells.

So, what you're seeing is us manage, as we get more efficient with those rigs, and we do it at lower cost, we have more opportunity to invest, we are just managing that inventory in an efficient operational basis overall. No intent to build inventory or to deplete it. We want to keep it relatively constant and so we're managing that actively, David.

Okay. And then just one quick question on EG. How much downtime will you have for the compression project? How long will that take?

Hi, David, this is Mitch Little. We have the installation campaign for the new compression platform that Lee spoke to earlier. And we would look at on the order of a couple of weeks to facilitate the initial installation of the jacket and topside. We also have scheduled planned maintenance as part of delivering our higher reliability in those assets so, there will be some partial downtime associated with that that will also occur in the first quarter.

But going into the second half of the year, of course we will have the benefits from that compression project. It will bring rates back up to above even current rates.

Just one quick one on the Meramec wells. The EG one was just a fit in. (laughter) The well results? Thinking about rates and well design, can you talk about -- I would've thought that area would have been a little gassier, it looks a little oilier. Lance, can you go through your thoughts on what happened in that part of Kingfisher?

Sure, David. I think as we are working through this early part of the Meramec, it's important to realize that we're focusing primarily on leasehold drilling. So, we are covering a diverse area of several counties to convert these term leases to held by production. We expect to see some diversity in those early well results We're still working on the best designs and the completion and how we manage those wells in the early days. While our results aren't perhaps as much as we desire, we expected this diversity. It's early days.

We are excited about seeing the continued momentum in the Basin. The IPs continue to get better, the productivity is improving overall. Importantly, the cost improvements over the last year have been very material. And on top of that you're seeing us continue to be opportunistic in adding acres in this area at attractive pricing, as we continue to see this as a great place to invest in the future.

Thanks, guys.

John Herrlin, Societe Generale.

Most things have been asked but I was just curious with Shenandoah. Is that an asset strategically that would be better off with one of your partners in terms of taking that cash flow or future CapEx and then dedicating it more towards the resource plays?

Good question. On Shenandoah, of course, we are still very much early in the appraisal phase. We have seen some excellent results from the last appraisal well, and I think we shared those as well as the operator has shared those.

We haven't reached an investment decision, of course, around Shenandoah in the base case. Ultimately it will need to compete for capital allocation head to head with the rest of our opportunities. But until we see the final development plan and can make, I would say, a thoughtful decision around that I think that's an open question.

Okay. Thanks, Lee.

Roger Reed, Wells Fargo.

Good morning. I apologize if some of this has been asked. I did get on the call a little bit late. In the unconventionals, when you announced the dividend reduction, the initial CapEx for 2016, the expectation the US unconventionals could be flattish, I think is the right way to think about it, in 2016 with the 2015 exit rate -- and we have heard these questions asked other places -- is there a rationale to keep that flat because of the challenges of recovering once oil prices come up and you start drilling more in terms of fighting decline curves? Or should we think of it as in a $45 to $50 oil environment that really is a reasonable way to invest in terms of just the returns of those wells today?

The way we have thought about that very preliminary guidance that we provided, Roger, is really rooted in our overarching objective of balance sheet protection. In the current environment, a sub $50 environment, we are not solving for growth at that point. We are really looking at living within our means, inclusive of both the dividend as well as our non-core asset program.

The preliminary guidance we provided we believe provides us a pathway to that cash flow neutrality. But as we see more constructive pricing or a more constructive outlook certainly we'll take a thoughtful approach to how we allocate that. And the number one call on that allocation will be our US resource plays. But I'd just emphasize that we are still very early still in the planning cycle.

Okay. And as a follow-up to that, is there anything that you have changed -- you mentioned earlier the shift towards maybe a little more of the NGL condensate side because that's where the economics are -- is there anything you have changed in the initial production of your wells the first 30 days, 90 days, something like that, in terms of choking them back? Why, in other words, sell all your production upfront when the prices aren't particularly impressive? And whether or not you have considered anything on the hedging side.

Roger, I'd say operationally we continue to bring the wells back in each basin based on the flow back parameters that drive the best well productivity. We are not managing those lower, I think, in the way you were describing, just to manage the production profile. We're doing it to drive best well productivity.

In some small cases, basin to basin where you may have once in a while a limitation on gas capture, for example in North Dakota, or we may build a facility that's slightly undersized to minimize our spend and we'll peak shave, but those tend to be short term. And those are the exception not the rule. Overall we are continuing to manage the chokes and the flow back to drive best well productivity.

Thanks. And hedging, any thoughts on that?

Roger, this is JR. I think you should consider the fact that hedging will be an element of a broader commodity risk management strategy going forward. And as opportunities present themselves in the market, we will continue to look at ways to protect more of the downside commodity price risk in the portfolio.

Pavel Molchanov, Raymond James.

At the risk of sounding like a CNBC debate moderator, I've got to push you a little bit on the dividend. Three months ago you used very strong language in explaining why the dividend is the first call on cash flow. I'm just curious, what in the last 90 days, what was the specific trigger for shifting from it is the first call on cash flow to cutting it 76%?

Pavel, first of all, I would still say, even with our current dividend levels, that remains our first call on cash flow. But in terms of the why now question, which I believe is what you are asking, around the adjustment to the dividend, the way I would describe that is, first of all, it's really been a further and continued volatility and weakness in the commodity pricing environment.

I would say, secondly, it's been a growing confidence in the quality but, most importantly, the depth of our US resource play base, which we just added in the past quarter 600 million oil-equivalent barrels of 2P resource there. And then I would say the third factor that really was the trigger point is that we were able to share a preliminary view of our plan at the Board level. We had the ability to put that dividend adjustment in the context of our forward outlook and plan. Those were really the three, I would say, triggers, Pavel, in terms of the why now question.

Okay. Fair enough. Shifting to 2016, I know you said you haven't finalized the specific geographic components of the CapEx but do you envision there being any carveouts from the CapEx curtailments? And I'm thinking Oklahoma, perhaps. Any areas that will get special treatment or protection from the overall 30% cut?

Again, we're going to follow our rigorous capital allocation process, Pavel. It's going to be driven by economics. But there are cases -- and Lance alluded to one earlier -- where there are lost opportunity aspects to some of the plays, specifically in Oklahoma where we still have significant term lease that we need to hold. We are going to be looking to protect that as a top priority. So, I wouldn't necessarily call that special treatment. I would just call that being smart about our business.

Okay. I appreciate that. Thanks, guys.

We have no further questions at this time.

Thank you for your questions and interest in Marathon Oil. I would like to thank everyone again for their participation this morning. Please contact Zach Dailey or myself if you have any follow-up questions. Operator, thank you. This concludes today's conference call. You may now disconnect.

Thank you, ladies and gentlemen, this concludes today's conference. Thank you for participating. You may now disconnect.