Anadarko Petroleum Management Discusses Q2 2013 Results - Earnings Call Transcript

Jul.30.13 | About: Anadarko Petroleum (APC)

Anadarko Petroleum (NYSE:APC)

Q2 2013 Earnings Call

July 30, 2013 9:00 am ET

Executives

John M. Colglazier - Vice President of Investor Relations & Communications

R. A. Walker - Chairman, Chief Executive Officer, President and Member of Executive Committee

Charles A. Meloy - Executive Vice President of U.S. Onshore Exploration and Production

Robert K. Reeves - Chief Administrative Officer, Chief Compliance Officer, Executive Vice President and General Counsel

A. Scott Moore - Vice President of Marketing

Robert P. Daniels - Executive Vice President of International and Deepwater Exploration

Robert G. Gwin - Chief Financial Officer and Executive Vice President of Finance

James J. Kleckner - Executive Vice President of International and Deepwater Operations

Analysts

Subash Chandra - Jefferies LLC, Research Division

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Brian Singer - Goldman Sachs Group Inc., Research Division

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Scott Hanold - RBC Capital Markets, LLC, Research Division

David W. Kistler - Simmons & Company International, Research Division

John T. Malone - Mizuho Securities USA Inc., Research Division

Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

John P. Herrlin - Societe Generale Cross Asset Research

David Heikkinen

Brad Carpenter - Wells Fargo Securities, LLC, Research Division

Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division

Arun Jayaram - Crédit Suisse AG, Research Division

Operator

Good morning, everyone. My name is Sarah, and I'll be your conference operator today. At this time, I'd like to welcome you all to the Q2 Anadarko Petroleum Corporation Earnings Conference Call. [Operator Instructions] Thank you. I'd now like to turn the call over to our host, Mr. John Colglazier. You may begin your conference.

John M. Colglazier

Thank you, Sarah. Good morning, everyone. We're glad you could join us today for Anadarko's Second Quarter 2013 Conference Call. Today's presentation includes forward-looking statements and certain non-GAAP financial measures. A number of factors could cause results to differ materially from what we discuss today. We encourage you to read our full disclosure on forward-looking statements and the GAAP reconciliations located on our website and attached to yesterday's earnings release. Also on our website, we provided a comprehensive summary of our global activities in our quarterly operations report. In a moment, I'll turn the call over to Al Walker, who will discuss the company's activity and second quarter results. Al will be joined by our executive team, who will be available to answer questions later in the call.

With that, Al?

R. A. Walker

Thanks, John, and good morning. We're very pleased to discuss the results of yet another strong quarter and to update you on a number of recent developments. Every aspect of our portfolio continues to deliver. As you saw on the earnings release and can dig into further in the operations report, during the second quarter, we increased oil volumes from our U.S. onshore assets by 20,000 barrels per day over the second quarter of last year. We reached milestones at 4 high-impact, short- to medium-term oil projects, successfully drilled 5 more deepwater discoveries and, again, achieved excellent operating results while generating substantial adjusted free cash flow.

I want to begin by highlighting the continued outstanding performance in our U.S. onshore assets, including the Wattenberg Horizontal and Eagleford Shale programs. Collectively, these 2 programs generated more than 90,000 net barrels per day of liquid sales volume during the quarter compared to 63,000 barrels per day in the second quarter of 2012. That's an impressive increase of more than 45% year-over-year. It's important to note that as we continue to accelerate activity in these high-growth liquids programs, we're very focused on safely driving operating efficiencies into every segment of our business. These improvements are enhancing project returns and are discussed in detail in the quarterly operations report posted on our website.

As anticipated and previously communicated, during the quarter, we had steep growth in our Wattenberg Horizontal program that led to higher line pressures on the field as production outpaced processing capacity, which temporarily shut-in approximately 1,300 low-rate legacy gas wells while maximizing growth from our horizontal program. Volumes from these shut-in wells should be restored during the third quarter and we expect to add up to 25,000 barrels per day of additional production by year end as new compression and processing capacity comes online.

It's critically important to continue to expand our infrastructure and takeaway capacity for our growth areas, as we've been doing over the years very successfully. We made a lot of progress on this front during the quarter, including the recent startup of our 200 million cubic feet per day Brasada natural gas processing plant in the Eagleford. This facility and other Midstream projects, which we and our affiliate, Western Gas, have underway, are designed to ensure future takeaway capacity to keep pace with our production growth. This has been central to our drilling and economic success in the Eagleford as takeaway has been an industry challenge that our company has done a great job managing. Beyond the outstanding performance of our significant growth plays, we've had some very strong early results with the Wolfcamp test in the Delaware Basin of West Texas. We're accelerating drilling activity across our 600,000 gross acre position following encouraging results and the production rates from our 2 initial wells each demonstrating IPUs of more than 1,000 barrels per day with high cuts of oil and liquids. This could become a very exciting and new growth area for us in future years if this play develops as the early results support.

As detailed in our ops report, we've made significant progress in several of our large-scale international and deepwater oil projects during the quarter. These sanction projects at the El Merk, Lucius, Heidelberg and TEN provide line-of-sight visibility to significant, high-margin oil and cash flow growth in the near to intermediate term. In addition, the carried-interest agreements we've entered into at Lucius and Heidelberg have materially enhanced our projected rates of return for each of these developments while reducing our capital intensity.

On the exploration front, the 5 new discoveries drilled during the quarter were pretty impressive, by any means, and our success there and optionality it provides our portfolio is equally impressive. Anadarko continued to achieve industry-leading 70% success rate with our deepwater exploration and appraisal drilling so far in 2013. These 3 discoveries announced in yesterday's press release, Raptor, Yucatan, Espadarte, along with Phobos and Orca, previously announced are very meaningful and indicative of our ability to continue to add to our inventory through the drill bit. For the remainder of the year, we have planned a very active deepwater exploration and appraisal program and look forward to sharing those results in future earnings updates each quarter.

On the operating side, our results continue to show significant earnings growth, strong cash flow generation and an improving balance sheet, all of which were consistent with the results we have guided investors to for some time. Of note, our net-debt-to-adjusted-capitalization ratio has improved to approximately 29% from 34% at the end of last year. We're very proud of these results achieved during the second quarter, including the sales volume growth through the first 6 months of the year.

Looking ahead to the balance of the year, we've increased the midpoint of our annual sales volume guidance by 1 million barrels per BOE. This increase, in spite of a modest reduction in our full year U.S. sales volumes expectations which were a result of the completion delay at Caesar/Tonga in the Gulf of Mexico, are continuing to do the types of things we expect. We believe that the well will be online by year end, fully contributing to 2014 oil production volumes. As we've stated previously, we're focused on accelerating the conversion of our capital-efficient U.S. onshore resources, achieving peer-leading production growth per net debt-adjusted share and adding to that being an extremely attractive growth stock. We want to actively manage our portfolio to optimize the resource inventory we have and reduce our capital intensity. And we want to continue to deliver the exceptional exploration results which we have been achieving historically for higher future growth and optionality.

We believe by accomplishing all of these, we will meet or exceed the objectives we communicated to you in February this year and we continue to believe that 2013 will be an exceptional year for Anadarko.

At this time, our executive committee and I will be happy to answer your questions. Thank you.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from Subash Chandra of Jefferies.

Subash Chandra - Jefferies LLC, Research Division

Two questions. First, on Powder River Basin oil. If you can -- more color on what you're seeing there. Is it largely conventional? Do you see some shale-type repeatability? And my follow-up, sadly, is on Tronox if we can get to it.

Charles A. Meloy

This is Chuck Meloy. I was just going to respond to the Powder River Basin oil program. What we're seeing is some exciting exploration results as we move around and test 2 or 3 different prospect areas. The zones that we're playing are the Shannon and the Frontier and we're also looking, of course, at the Niobrara and Mowry in the Powder River Basin. And now this is a result of about, I don't know, 10 wells or so coming online. And they look really good. We're starting to see some good results. We're putting plans of development together for 2 of the areas up in the Table Mountain and Mojave areas and those should be conducted next year. And so the early returns look good. It's good oil and real good cuts. We're getting good prices for it and our program is just getting kicked into gear, so I think you'll see some really good improvement in our drilling performance and things look like they'll be -- have good economics, so...

Subash Chandra - Jefferies LLC, Research Division

Could you talk to maybe the well cost and the repeatability if you were to compare it? Obviously, it's going to be different than Wattenberg or Eagleford, but for contrast's sake.

Charles A. Meloy

Yes. The well costs we've seen have been in the, say, $7 million to $9 million range. And it's a little early yet to know the EURs. But the rates have been good. We don't have -- our interest position in these wells average, like, in the order of 50%. And as they come on, they've been coming on at fairly strong rates in the order of 500 to 600 barrels a day type of rates. And what I anticipate, those are exploration wells, so we have to build roads and power and all that kind of thing to the original wells. And as we get into manufacturing mode, we can substantially cut that down.

Subash Chandra - Jefferies LLC, Research Division

Okay. And then my follow-up is on, I guess, related to Tronox. I guess early this month, you guys have filed this idea, Arch versus Verizon. It seemed like it was favorably resolved for the defendants in this case and should reflect well on Tronox. I was curious how similar you thought that case is to Tronox or how different.

Robert K. Reeves

This is Bobby Reeves. We don't have anything new to report on Tronox. The 10-Q that was filed late yesterday continues to have a very extensive description of this matter. We're still confident in the merits of the case and we're anxious to get a ruling from Judge Gropper soon. As for other cases that are decided, that happens periodically and we'll certainly use those that are beneficial to us to the extent we can.

Operator

Your next question comes from Matt Portillo of Tudor Pickering.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Just 2 quick questions for me. In regards to the Permian, I was hoping that we could get maybe a little bit more color on the 30-day rates there and then potentially, the targeted zone in the Wolfcamp that you're drilling and any color on kind of initial liquids cuts on those wells.

Charles A. Meloy

Okay. This is Chuck again. The wells have been performing very well. We're just now getting them on production. We feel good about them because we have a lot of offset activity going on in the same interval, which is -- we refer to it as the beta and various industry partners have different names for the Wolfcamp ventures out there, but -- it's pretty exciting. They're a good piece apart, 15 miles along that line. And we have a number of offsets in and around our acreage position and also have good rates and have a little more production time on them, so they appear to be some pretty stout EURs based on the offsets. And we're looking at these and we're excited enough about it that we're moving in additional rigs and will be delineating the entire area over the next few months and are getting more production data and start sizing this thing up. But because we have offsets and there's quite a bit of well data in the area from other operators and then, actually, a little bit thinner with regard to the section, we're feeling really good about this.

R. A. Walker

And Chuck, our oil liquids cut is about 8%, largely oil.

Charles A. Meloy

Yes, it's mostly oil.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Great. And then just a quick follow-up there in terms of the CapEx plans. Could you give us a little color on maybe how many rigs you're running or how would you think about this play from an acceleration perspective?

Charles A. Meloy

Well, we hope to get about 5, 5 or 6 working in the Wolfcamp here in the next few months. And the cool thing, I think, that we have is the efficiency that we've seen in the rest of our program allows us to do this inside of our original capital guidance. And I think that's a great complement to our drilling and completions teams. They've just done an outstanding job this year of really using our capital very efficiently and very constructively and we're taking advantage of the softness in the market for drilling rigs and completion services right now. And so we're doing this inside our budget. When we get into manufacturing mode, we've said time and time again, these guys can really drive down the cost. And so it's a little early to size up what the actual economics of the play will look like, but I think our actions probably speak louder than our words, moving 5 rigs in the play, 5 or 6 rigs in the play over time and pretty quickly on the yields with some really good initial rates.

R. A. Walker

This is Al. I think I would think about this as a coming attraction for 2014 and beyond. The stuff that we will do this year is really more the exploration/appraisal type of work. And as we announced, early next year, our capital plans for '14, if we continue to see the types of things we are early on seeing in this play, it could represent a fairly meaningful part of our CapEx next year.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Great. And my last question, just in regards to guidance. So a slight downtick in gas price realizations for the back half of this year. I was just curious, is that being driven by any particular region or just any color on kind of the wider differentials?

A. Scott Moore

This is Scott Moore. I would say that we're primarily seeing a little pricing pressure in Marcellus, which is flowing back into realizations through our gas pricing. Pipeline utilizations are quite high on the Tennessean transco systems, but there are significant expansions coming into service in November which should help alleviate that situation.

Operator

Your next question comes from Brian Singer of Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

Sticking with the Marcellus, your Marcellus Shale production was up nicely sequentially. Can you just update us on how your backlog and rig count has changed and what you attribute to productivity improvements versus backlog reduction?

Charles A. Meloy

Brian, this is Chuck again. The production has been amazing. We're 2 Bcf a day gross in our AMI area and we've exceeded 0.5 B a day now, net. And what we have is around 230 wells in backlog. About 130 of those are waiting on completions and the remaining is waiting on mostly midstream-type activities or production hook-ups, that type of thing. And so we have a strong backlog. They're all in the right spots right down the fairway, so I think you'll see our production volumes continue to be strong. And what we've learned in the Marcellus is much like we've learned in many other places, is that these extended laterals and the right completion techniques for the type of reservoir the you're actually dealing with. On a site-specific basis, it's giving us just better and better EURs. It's just a learning process. We're starting to pay dividends. And so we're just getting more efficient at it and better at it and we've learned from our prior activities.

Brian Singer - Goldman Sachs Group Inc., Research Division

That's great. And then shifting to the Gulf of Mexico. Could you put into context Yucatan relative to your Shenandoah Basin thesis, what this means for both Coronado, Shenandoah and then other exploration prospects you have in the area. And then whether there's any change in prioritization of appraisal drilling, either because partners in these discoveries want to kind of push things forward or because you guys do?

Robert P. Daniels

Yes, Brian. This is Bob Daniels. We're excited about the whole Shenandoah mini-basin. We have the big discovery at Shenandoah. Of course, Coronado was announced earlier and the announcement here with Yucatan. Everything is working out there from a reservoir standpoint. We're looking for enhanced

lower tertiary reservoir quality. We're seeing pay in all of the things that we're drilling. We are seeing a little bit of variability as we saw in the original Shenandoah discovery, where we had a several hundred feet of pay in the original well and 1,000 feet of pay in the appraisal well. So things -- we're learning as we go. And what we're learning is that we really like this area and we anticipate that there will be more appraisal work going. And we're moving ahead with whatever kind of planning we can for potential developments in the area.

Brian Singer - Goldman Sachs Group Inc., Research Division

Great. And do you anticipate adding capital or shifting capital to that area for appraisal relative to your original plan?

Robert P. Daniels

For this year, probably not beyond -- and we always move capital around a little bit, but we feel like we've got the activities pretty well set this year. They're going to happen. And a lot of it's driven by rigs, when we can move rigs in and out. So what we've put forward is pretty much what we thought we would have to do this year.

Operator

Your next question comes from Doug Leggate of Bank of America.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

I wonder if I could ask you to give us an update on your disposal plans. I guess Mozambique has been -- I guess, obviously, we've been expecting something there for quite some time now. Maybe elaborate as to why your partners are ahead of you or not. And perhaps an update also on Brazil and any plans for MLP monetization in terms of selling down your, obviously, your public interest there at some point. And I've got a follow-up, please.

R. A. Walker

Okay. Thanks, Doug. I'll tell you what, I'll take the first question and we'll have Bob Gwin address the other 2 because I think he can speak to it better than I can. As it relates to where we are in Mozambique, I think we continue to make progress and look forward to a day soon where we can talk more specifically about what we're going to do there. I don't think, at this point, we feel like we're ahead or behind our partners. Our partners that have announced the deal found something that satisfied their needs. I think from our perspective, we continue to look for something we feel like is optimal for ours and when we do, we'll be looking quite aggressively to talk about it. But we're not quite there yet, Doug, is the short answer. I can't give you a lot of color around our partners' decision other than to say that it was not one that met our needs. And I think with that, I'll let Bob address the other 2.

Robert G. Gwin

Yes. And just to follow up on Al's color on Mozambique, I mean, keep in mind that the partner that was selling is actually in the country and we're remaining. And so certainly, our level of analysis and diligence relative to staying in is a little bit different there. On Brazil, as we've discussed before, we're trying to proceed with the sales process in advance of the formal unitization. That work is ongoing, both on the unitization front, as well as the divestiture. Our expectation is we should be able to put it in a place that would address the subsequent value redeterminations. We're conducting additional drilling on the blocks today. We're continuing to advance the value of the asset. And we don't have anything to report on the sales front other than to tell you we continue to work on it and have an active process in place right now.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

On the Midstream, Bob, you've got about, I guess, a $9 billion market cap right there with a 92% ownership. Can you give any color as to what your thoughts are on whether and when you might consider selling some of that down?

Robert G. Gwin

Sure. We did the IPO in December of last year. If we were to register additional shares during the 1-year period after the IPO, we'd be working under an S-1, which is a little more complex of a process than an S-3 shelf registration. The shelf registration, we can do after we've been public for a year in December. That doesn't preclude us from doing something in advance. But frankly, we're comfortable with the performance of WGP. We certainly expect to sell down some of it over time, both because of the effect it would have on being able to bring forward some of the value for Anadarko shareholders and as well as getting more liquidity out into the market for WGP to trade even better than it has with relatively limited liquidity. It is kicking off some very significant distributions to Anadarko today. It's a performing asset, something that we keep a close eye on. And at about $8 billion of value, that's worth about $16 a share, the Anadarko share price. So this is something that is pretty significant to Anadarko, even if it's unrealized or unrealized over time.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

My follow-up is maybe for Bob. It's related to the Raptor discovery. I guess we've been watching this one with some interest. It's a relatively new area. Can you help us understand whether Raptor would be commercial on a stand-alone basis given the absence of infrastructure? And maybe any plans you have toward acreage around that or just any color on the discovery generally and I'll leave it there.

Robert P. Daniels

Doug, I'll give you as much information as I can, but remember that it is kind of a new area. We've got new information. Our partners, BHP and ourselves, feel like we need to capitalize on that, so I can't really give you a whole lot more than what's in the release. We do like what we're seeing out there. It's high-quality oil, very good reservoirs. And we do think there is potential for additional accumulation similar to it in the area and we just need to work that all into our analysis and decide what we want to do. So beyond that, I prefer not to talk about it at this point.

Operator

Your next question comes from Scott Hanold of RBC Capital Markets.

Scott Hanold - RBC Capital Markets, LLC, Research Division

I know you're trying to say limited stuff on Raptor right now, just kind of a quick follow-up on that. I mean, what are your next steps out there with the Raptor discovery?

Robert P. Daniels

Well, Scott, we did work on an appraisal to that very quickly and then we're going to move the rig once we're done there. We'll move the rig over to our Deep Nansen prospect, take all that information that we have and then decide what we want to do, both at Raptor and in the areas surrounding it for additional opportunities.

Scott Hanold - RBC Capital Markets, LLC, Research Division

So did that sidetrack or appraisal test the same objective, or is there a different objective you're looking at also there?

Robert P. Daniels

It tested the same objective and some others that we saw that could have similar-type potential. And we got good information out of that.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay, understood. And moving back to the Permian real quick, you gave a lot of good color. Just a couple of quick questions on there. Your acreage position, you talked about 600,000 gross acres. Is that just grossed up for any kind of royalty interest you own there, or do you have a net position there, excluding other work and interest partners?

Robert P. Daniels

Yes, we -- our interest is generally around 40% or 40% to 50% working interest. It's around 350,000 net acres. And the royalties vary, on the 75% to 80% range, net royalty interest range. So that's -- I hope that answers your question.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Yes, that does it. And then also on the Permian, how much Bone Springs drilling have you done? Are you doing Bone Springs right now, or is it just kind of focused on the Wolfcamp as far as your operated work?

Charles A. Meloy

We're actually doing work in 3 different zones. The Bone Springs and the Avalon have been the bulk of the work to date, the Bone Springs in the south southern portion of our acreage and the Avalon on the northern portion. And the Wolfcamp just happens to be right in the middle of them. So the advantage that we have in the Wolfcamp that we haven't had historically when we started these things is the overprint of the infrastructure. And the Bone Springs and Avalon have built a major infrastructure out there, including the gas lines, the well handling facilities, the well lines, the gas plant's takeaway capacity, all that. So we've been able to drill these 2 wells and put them online very quickly. And so it's not going to be a long process to get to evaluation here. So that's a huge advantage for us and something that we don't ordinarily have when we start a new play.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. And is there any strategies, like, as you go forward, looking at the economics of Avalon, Bone Springs and the Wolfcamp in terms of how you attack that if the Wolfcamp continues to look pretty good?

Charles A. Meloy

Well, I think the thing would be, it's an additive play, which means strong economics in the Bone Springs and the Avalon and both those plays are maturing. We're more or less in manufacturing mode in the Avalon now. So we'll keep working those. They have attractive economics and they've done a great job with growing our oil production out there for the last few years. Now we still have quite a bit of running room in the Avalon and to a lesser extent, the Bone Springs. So I would say the Wolfcamp, at least at this time, is an addition to the others.

R. A. Walker

Scott, this is Al. I'll add to that. I wouldn't think of the Wolfcamp as pushing out either of the other 2 plays from a capital allocation perspective. They all have very attractive oil and liquids-rich type of opportunities. And they have the kind of wellhead margins that would fit on capital very well with allocation next year, in particular, for Wolfcamp, if it does develop the way we're seeing the early results suggest.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. And with the Wolfcamp being deeper, I guess what I was trying to get to is, is there any reason at all to drill the Wolfcamp first to hold the formations above it, or is that not an issue for you guys.

Charles A. Meloy

Well, the activity that we've done to date has been HBP-ing a great portion of the acreage. And I think what you'll see is that we'll actually start doing multi-zone pads because the Wolfcamp appears to be fairly widespread and so we'll just -- we'll take advantage of all the intervals available to us on that pad.

Operator

Your next question comes from Dave Kistler of Simmons & Company.

David W. Kistler - Simmons & Company International, Research Division

Real quickly looking at the Eagleford, Wattenberg, Marcellus and the impressive numbers you gave as far as time to drill in each one of those plays in your kind of operations release, can you guys quantify what that's doing in terms of rates of return or increase in number of wells you anticipate drilling this year or per well cost savings? Just trying to get a handle on how to think about that from an economic perspective. Obviously, it's improving, but...

Charles A. Meloy

Right. I can give you a couple of data points, so it may help you. We did a study not long ago just to our Southern and Appalachian region and most of the drilling has been in Maverick, Marcellus and East Texas. And so it's a compilation of those 3. We look back at how those wells were drilling in 2009 and '10 as compared to today. And if we ran the program we have today with the cost we had back then, it would have cost us an extra $2 billion. So we saved $2 billion in a matter of 4 years on those programs. And if you look at the program for the Southern region now, it's less than $2 billion total. So we added a year of capital to our program with the savings in our drilling completion program. So it's been a stunning program. And our drilling completion group, like I said earlier, has just done a fantastic job. The other way you can look at it is, if you go down into the Maverick Basin this year, our original program, we're probably going to drill in the order of 30 to 40 incremental wells for about the same amount of money in the Eagleford.

David W. Kistler - Simmons & Company International, Research Division

Okay. That's helpful. And then in the Wattenberg, last quarter, you guys had talked about kind of where you were on the learning curve with respect to spacing and interval identification, well cost, well design, completion design. Any kind of update you can give us, more than sort of indicative updates of what's happening, what you think the ultimate spacing is going to be, ultimate well cost, ultimate design, or are we still progressing through that learning curve?

Charles A. Meloy

Well, Dave, I think we're still progressing and we will be for several more years. And this is a big field. It has a large area and it's -- the GORs and the oil viscosity change throughout the field, so we'll have to work on each area and come to some conclusions. I can tell you, we're continuing to do spacing test. We're continuing to do lateral link test and completion designs. And what we're seeing is through the course of that, we've gone to principally slick-water frac-ing, which has saved us about $300,000 a well. So our well costs now are down in the low 4s. Now that's drilling completed and equipped. We still have some opportunity to reduce that further as we move forward. And the spacing is -- it's a difficult problem to solve because you're looking at not only the distance between wells but also how you complete them. So it's an optimization exercise. And so what we may do is have a little wider spacing with bigger fracs or tighter spacing with smaller fracs. And we're testing both of those extremes now to see which one actually delivers our best economics. And it may be different between where you have higher GORs and lower GORs. So all that's going to be going on for quite some time. It's not going to be sort of one day, we wake up and know it. And as product prices change, it will also vary. So we have a lot of learning to do. And the thing I'm excited about, when we sat here last year and talked about this thing, we were about 1/3 of the rate we are today. It's tripled. It's tripled in the course of the year. Our horizontal production has tripled. And this is good oil. It sells for good price. And we worked really hard to get a good takeaway. And the problem we're seeing right now is we've got too much hydrocarbon in the field. And the pressures are going up on the gathering lines and that type of thing, which is just high-class problem that we'll sort out here in the next couple of quarters and be able to move a bunch of hydrocarbons. And I think again, our actions speak louder than words here. We're up to 13 rigs and our plan really hasn't changed from the last quarter. We just keep plugging away.

Operator

Your next question comes from John Malone of Mizuho Securities.

John T. Malone - Mizuho Securities USA Inc., Research Division

Just going back to Yucatan for a moment. Based on the data you've seen so far, do you see potential for the kind of big bump in net pay from any subsequent appraisal that you saw in Shenandoah? It looks from your graph like there's down-dip potential.

Robert P. Daniels

Yes, John. Bob Daniels. Of course, we see additional potential out there. You never know what's going to happen as you move away from the salt reservoir interface. Whether you're going to have expansion down into the basin, of course, that's what the appraisals will be focused on. So that's what we're going to continue to move forward. We really liked what we learned from the Shenandoah area. And we think there's applications both at Coronado and Yucatan for those learnings. And so we're looking forward to getting out there and doing additional work.

John T. Malone - Mizuho Securities USA Inc., Research Division

Okay. And then just on the Wattenberg quickly, with the line pressures. If I heard correctly, you said that you thought there was 25,000 BOE a day potential increase through the balance of the year. If that's the case, how much of that is new and how much of that is just restoration of the wells that are shut-in due to pressure issues?

Robert P. Daniels

That's what's our expectation. Now what we're doing, John, is we have about 140 million cubic feet of additional processing capacity in compression coming online between now and year end. And then following that, we'll have our Lancaster 300 million a day cryogenic plant coming on. So the idea is to substantially lower the line pressures back to where they were several years ago, so we'll be restoring in the order of 10,000 barrels a day. And then the balance of the new production, some of which is behind chokes right now. And so if we get all this done and we're on a good pace to get it done, we should have a really nice bump either late in the third quarter or in the fourth quarter. And we're looking forward to that.

R. A. Walker

And John, this Al. I know you probably -- these have not gotten lost on you. We're not changing our annual view of what we think the Wattenberg is going to produce. In fact, it's producing at just exactly the rate year-over-year that we indicated earlier this year. I think in prior calls, Chuck's talked about when you're in these large fields with these line pressures and the way in which startups occur with processing plants and the like, that we just go through these typical plumbing issues. It doesn't change our annual guidance. And Chuck refers to them as growing pains. And simply, that's all it is. I'm sure you've seen -- and I'm not saying anything to you that you didn't already know, but I just think the fact is this field's actually doing exactly what we thought it would do. And the growing pains that we went through in this quarter, we've talked about in the past and they were expected.

Operator

Your next question comes from Charles Meade of Johnson Rice.

Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

Going back to the -- perhaps, going back to Marcellus. The -- I'm curious what's driving the outperformance on U.S. natural gas. It looks to me like it's the Marcellus. And if that's a fair read, could you give a -- could you talk a bit about the nature of what that outperformance is, whether it's higher IPs or whether it's a lower decline, so older vintage wells outperforming, or maybe if I work down on the completion backlog, you're just going to take a stab at decomposing that?

Charles A. Meloy

Charles, this is Chuck again. You hit it right on the head. It is the Marcellus. It's performing remarkably, actually. And it's undoubtedly the best gas well we have in the U.S. I think it's probably the -- that that's the case for the industry. I think the reasoning that you mentioned, is it higher IPs or lower decline rates and that type of thing, it's all of the above. The field is just performing remarkably well. And what we're seeing is the ability to regularly complete wells at 10 million a day and they last for quite some time at these higher rates. So we haven't seen the dramatic follow-up that we often see in some of these shales. There's just a lot more reservoir capacity in the Marcellus than what we're accustomed to in the remainder of the shales. And if you look forward, we still have a lot of ground to cover. And we got into this manufacturing mode, so we can cut our cost and we can bring these wells on in pretty big, lumpy -- in lumpy volumes. And I anticipate that'll continue. The offset to the Marcellus has been we're seeing declines in our CBM assets, in our IHUB assets. So those were -- that's where the declines are. In the IHUB is where the -- I'm sorry, the Marcellus is really great for us.

Charles A. Meade - Johnson Rice & Company, L.L.C., Research Division

Got it. That might be -- I wrote it down here. Chuck, when you said too much hydrocarbons in the field, there might be a lot of calls I'm on before we hear that again, but that might be your case with Marcellus, too. The other question I had was on Mozambique and the Espadarte well. The way I read that in your operations report, it looked to me like possibly, that was a big shift in making the -- in maybe revising up the size of the Golfinho/Atum complex. Is that the right read? And is there anything -- if that is the case, could that change your appetite or change your timeline for developing that Golfinho/Atum vis-à-vis the Prosperidade complex?

Robert P. Daniels

Yes, Charles, it's Bob. On the Espadarte and Golfinho/Atum resource range. I think, really, what these things are doing is pulling the low end up, giving us a lot more confidence. We are going to go back in and redo the entire Golfinho/Atum complex with the additional drilling. We have Espadarte now. We've got Atum 3. We're going to have a couple more appraisal wells in it to really delineate the field. But what it's primarily doing is moving up the low end and giving us a lot more confidence in the low end. And then the high end is going to stay about the same, probably, but we'll see given what we see in thickness variation and reservoir quality. But we're real pleased with the well. It was in an area that was not as clear on the seismic data and was very updip portion of it and it came in extremely well. So we're pleased with that. We're pleased with the Atum 3 results and things are moving ahead very well there. Regarding Golfinho/Atum timing, I'll let Jim Kleckner address that relative to Prosperidade.

James J. Kleckner

This is Jim. We're moving forward with a joint study with ENI to jointly develop Prosperidade. Golfinho/Atum, as Bob mentioned, is in the appraisal phase. And we anticipate working towards reserve certification towards the end of this year and into the first quarter. So we already have reserve certification for Prosperidade and are working towards the combined solution for jointly developing MA 1 and 4 with a LNG Park onshore.

Operator

Your next question comes from John Herrlin of Societe Generale.

John P. Herrlin - Societe Generale Cross Asset Research

Just some quick ones. With the Wolfcamp, do you have any lease expirations that are material?

Charles A. Meloy

John, we have a -- we're in primary terms in a lot of leases out there, but I wouldn't call any of them material. It's just standard operating procedures.

John P. Herrlin - Societe Generale Cross Asset Research

Okay. That's good. With Raptor, is this a situation where you'd be willing to reduce your exposure like you have with other plays in the Gulf?

Robert P. Daniels

John, I'd say that it's too early to call that right now. We really need to know what we have there. And so I think we're going to have to do some additional work and incorporate the most recent appraisal well into our thinking.

John P. Herrlin - Societe Generale Cross Asset Research

Okay. Last one for me is on conventional optimization. You're clearly getting more for the money, as you've indicated, in various plays. How much -- or how important is completion design now versus where it was before in terms of your planning process or your well design process? And what type of efficiencies are you getting? Are you using less sand, less fluid? Can you talk a little bit more about that?

Charles A. Meloy

John, it's a great question. What we've seen -- I don't think it's any more or less important than it was just a few years ago. What we're just doing is learning more and more about it. And the keys to it have been how do we stimulate more of this rock. And there's a lot of studies out there about the different types of fracs, different types of hardware that you use in these horizontals. And we've used some of all of it, I guess, as we've gone through these plays and learned about them. And what we're really trying to do is set up a completion. And we're trying to set up the well density as well as the completion process that maximizes the stimulated rock volume, so these molecules do not have to travel very far in these very tight shales. And so what we're doing is learning more and more about how to do that. And we've used the science of microseismic, production logging, tracers, you name it, to get a clearer and clearer picture about how these reservoirs respond to stimulation through these fracs. And they're not -- none of them are the same, by any stretch of the imagination, but there's a lot of lessons that we've learned from each that we've applied to the others. And it helped us design these experiments. So the efficiency that I see is, if you look at Wattenberg, our well costs have come down in the order of close to 30% since probably about this time last year. We were in the mid-5s and now we're in the low 4s. And that, you see across the spectrum of the program. So and frankly, I think, John, that'll continue for a while. The industry is really learning how to do this. And it's a bit more of a manufacturing process and incremental gains as you go. And as long as we're able to do these experiments and as new technology comes along, we're going to continue to improve it.

Operator

Your next question comes from David Heikkinen of Heikkinen Energy.

David Heikkinen

A quick question on the Gulf of Mexico. What production do you expect from Caesar/Tonga now? And what is the ramp of both the new well and any workovers?

James J. Kleckner

David, this is Jim. As Al mentioned, we had some mechanical problems downhole and that caused a several-month delay on our fourth well. So the target is to bring that well on towards the end of the year. And these are extremely good wells. We've got permeabilities in the range of 500 millidarcies and porosities of 26%, 27%. So they're high-volume wells that should come on at 15,000 barrels a day range. So I think you can read through the volumes on that, given we've got 1/3 working interest out there. But anticipate some really good production increases as soon as we get the wells back on.

David Heikkinen

Okay. And then just a detail on Lucius, with the production handling agreement. Will that flow in as a net against operating expense or marketing and gathering or other?

John M. Colglazier

Dave, this is Colglazier. That will come in as a contra-operating expense.

David Heikkinen

So it will go against OpEx.

John M. Colglazier

Correct.

Operator

Your.

Next question comes from Brad Carpenter of Wells Fargo.

Brad Carpenter - Wells Fargo Securities, LLC, Research Division

Just 2 quick ones for me. You previously touched on the 800,000 net acre position in Southeast Colorado. Just curious if you could offer us some additional color on that position. I know you've been letting others prove up that play. And also curious if you plan to take a more active role in proving up your position, or you're still just letting others given your perpetual mineral position there.

Charles A. Meloy

This is Chuck again. As you know, we have about 800,000 of our land grant acreage through there. It's a checkerboard position, so we're offsetting every other section in the play. So we let industry work through that and we're sitting by and making plans to be active in the event the play kicks off and is successful. And we're well positioned. We don't have a plan to get out and be aggressive right now because we don't need to. Our lease is lasting forever. And so we're in good spot.

Brad Carpenter - Wells Fargo Securities, LLC, Research Division

Okay, great. And then just another quick one for me. Given your large U.S. onshore exploration program, any other plays that you're excited about right now heading into the second half of the year? And potentially any other 2014 coming attraction that we should be looking towards?

Robert P. Daniels

Well, I think we've talked about most of them. Powder River Basin is really starting to show some promise. We're excited about the Shannon and the Frontier. And then we're playing in the Nio and Mowry in the south end. And the industry has had some good success in that area, particularly with the Niobrara. And Chesapeake's got a big program going, so we're adjacent to them and the initial wells look really good. So I think the Powder River Basin in general, it's an oil basin, we have a large land position there and it's well positioned. So I think you'll see us get more and more active up there. West Texas, the type of exploration we're doing out there has been to the -- just evaluating the different horizons. And Wolfcamp has come up and it shows a lot of promise. We're also seeing a lot of offset activity in other areas -- I mean, other intervals in West Texas. So we'll be evaluating that. There's different Wolfcamp ventures that are being drilled, as well as some of the shallower plays. So I think you'll see us -- our program expand in West Texas. And then we have a few other ideas we've been kicking around and working that we're not ready to share with you.

Operator

Your next question comes from Bob Brackett, Bernstein.

Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division

Returning to Raptor. Can you talk about reservoir quality, whether cuttings or log porosity? Is there a sense that those Norphlet reservoirs are as good as they are on the shelf or up onshore?

Robert P. Daniels

Yes, Bob, on Raptor, again, I can't give a whole lot of detail, but the reservoir quality was excellent. We're real pleased with what we saw there. And the fluid quality was also excellent, very high-quality oil.

Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division

And then a quick follow-on, which is at a higher level. How is the Permian competing for capital for those 5 or 6 incremental rigs, at least, the Wolfcamp. Relative to throwing an extra rig at Wattenberg or Eagleford, is that an infrastructure or pace of activity constraint, or is it just pure economics?

Charles A. Meloy

It's mostly economics, but there is an element that because we have considerable infrastructure in place with capacity available to us, we can get them online quicker and get our oil production up. So that's what we're planning on doing. Right now, with the tightness of the gathering system and that type of thing in Wattenberg, we're not going to add rigs to Wattenberg until we get all that sorted out.

Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division

And the economics, is that -- I mean, it seems interesting that Wolfcamp, where you're going in and you've got the additional CapEx and you're ramping, that's better economics than some of your established resource plays?

Charles A. Meloy

No, it's just we're at a point where in each of the -- in Wattenberg and Eagleford, we're at the rig counts that we want to be at, given the infrastructure positions that we have.

Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division

And the infrastructure base...

R. A. Walker

Bob, this is Al. I think what Chuck is also talking about is we see at Wolfcamp the potential of adding another leg to the stool, which could be real attractive as we think about '14 and beyond. The early results there really do suggest something that could be quite big. The 2 wells we've drilled are 15 miles apart and we see a lot of running room.

Bob Brackett - Sanford C. Bernstein & Co., LLC., Research Division

Okay. And so you'll get those other assets to some sort of level where you got a decade or something of inventory and then you just keep them flattish?

Charles A. Meloy

Well, I think as we are able to add processing capability and takeaway capacity, you could, in the future, see us increase our rigs. But I think one of the things we've always been pretty mindful of is that if we can't push it through the existing infrastructure, increasing the rig count doesn't really have real positive effect on the rate of return for the capital we're putting out. So that is more the constraint at the end of the day than exercising more rigs to increase capacity where we really don't really have throughput and takeaway.

Operator

Your next question comes from Arun Jayaram of Crédit Suisse.

Arun Jayaram - Crédit Suisse AG, Research Division

Just a couple of quick ones. Chuck, I just wanted to see if you could elaborate on kind of the infrastructure projects at Wattenberg. You talked about adding 140 million of compression plus Lancaster. Does that ease the near-term bottlenecks, or does that provide you running room in terms of, as we think about 2014, of easing the line pressures for next year's growth?

Charles A. Meloy

I think what you'll see is with the 140 million we have this year, we'll start seeing the land pressures drop. And we're not certain it'll get back to what they were used to be, but they'll certainly drop and add some capacity. And what I think you'll see when we do that is that these -- the old vertical wells that have logged off because of higher line pressure will start producing again and that will give us the boost. And then when Lancaster comes online, we've essentially unloaded the facility -- or the field for a while. We already are evaluating additional expansions as we go on down the road. So there's -- this is going to be a continual process of drilling with -- drilling, development and infrastructure expansion. We have 13 rigs working in the field and so we're going to continue to see a very significant ramp in the horizontal production. And we're going to have to stay ahead of that and keep the room for it to come into the system.

R. A. Walker

Arun, this is Al. I think one thing I'd like to add to that is just, today, we take our ethane, in particular, into the Mid-Continent. And with the expansions that Enterprise has underway, we believe by getting those NGLs into the Gulf Coast to Mont Belvieu, in addition to everything Chuck just mentioned, the price realizations in the future will go up as well. So it's volume as well as price discovery that should start working to our advantage later this year and into next year, depending upon what your own views are about NGL and, in particular, ethane price recovery.

Arun Jayaram - Crédit Suisse AG, Research Division

That's helpful, Al. And just to clarify, Al, you mentioned that you're -- despite the sequential decline at Wattenberg in Q2, you're sticking with the full year guidance, which is around 120 million. Is that correct?

R. A. Walker

We have not changed our full year view of Wattenberg. We still feel that for the year, it's going to do what we thought it would do for the year. So nothing changed on that front.

Arun Jayaram - Crédit Suisse AG, Research Division

Okay, that's helpful. And I just wanted to ask a little bit about -- in the ops release you talked a little bit about some downtime in the Gulf of Mexico in Q2, scheduled downtime. And I just wanted to see if you could quantify the impact to Q2 and maybe the timing of that, when that production comes back.

James J. Kleckner

Yes, this is Jim. The downtime that we had were some operations on some of the pipelines and pigging that was occurring in addition to some downtime on wells through normal work-over in operations. So I think we'll see that production start coming back up here in the third quarter and finish strong in the fourth quarter, with the Caesar/Tonga well coming back online.

Arun Jayaram - Crédit Suisse AG, Research Division

But you don't have a number of that impact?

James J. Kleckner

No.

Operator

And your last question is a follow-up from Subash Chandra of Jefferies.

Subash Chandra - Jefferies LLC, Research Division

I apologize if this question was asked already and I didn't understand the answer, but I'll ask it again. In the Permian, the Wolfcamp, do you see that sort of being enough to make the Permian a growth asset, restore previous volumes, make it a growth asset on a consistent, sustainable basis? Or are we talking about shifting the product mix and a fairly flat production profile?

Charles A. Meloy

Subash, it's pretty early to know how big it could get. But it really shows some nice promise with these early returns. And in the event it lives up to that promise, I think you'll see the Permian turn into one of our real strong growth assets.

Subash Chandra - Jefferies LLC, Research Division

Okay. So look to next year then. And then, I guess, a final question for me is with all the free cash flow, et cetera, and previously you've talked, I think, somewhat cryptically about dividend, stock buybacks or what you do with the free cash flow. I was just curious, when do we sort of talk to it? When do you feel comfortable in -- is it next calendar year to talk to what you do with free cash flows? And/or do we need sort of a resolution in Tronox before that happens or some sort of a development plan or FID for Mozambique?

Robert G. Gwin

Subash, it's Bob Gwin. I mean, you touched on some of the gain issues there. Obviously, cash flow is very strong. We're generating free cash flow. We've collected a lot of cash from the resolution of TPE. We've continued to reduce our net leverage. And you're right. We've been a little cryptic maybe in some of our comments. I don't mean to be -- to continue in that vein, but we're looking at it. We're considering it. We've got a lot of places to put capital to work within our portfolio, but with the cash position and the growth in our cash flow, both currently and prospectively, obviously, we're considering ways to return cash to shareholders as well as a central part of that cash allocation strategy.

R. A. Walker

Subash, this is Al. Let me just add to Bob's comments by saying that I think we've made great strides in reducing the capital intensity of our business model and still being able to show strong sequential growth year-over-year on almost any measure. I think as we look out, we, in the past, have had some hesitation about the timing of the dividend increase simply because of some uncertainties around other issues that are unrelated. I think as we look at those and as we gain increasing comfort with the capital intensity of our business model, previously, we might have waited until some of those uncertainties had passed. I think we're continuing to consider whether or not that's a gating issue or not. I do want to leave you with a strong impression, though, that we recognize that the current yield that our dividend payout creates, that's not something that will remain static. We believe, over time, we will increase the yield and the payout on our dividend.

Operator

There are no further questions at this time. I'll turn the call back over to the presenters for closing remarks.

R. A. Walker

Well, for those of you that are on the call still or have been on the call throughout, we are very pleased with this quarter, very pleased that our efficiencies have shown the types of success again this quarter that they have been able to create, resulting in extremely attractive earnings and cash flow quarter for us. Balance sheet keeps getting better. And Bob Daniels keeps finding ways to find more and more exploration success around the world. And we're very pleased that we are one of those companies that can grow through the drill bit. So thank you for being on the call this morning. And good luck to everybody for the rest of the day.

Operator

This concludes today's conference call. You may now disconnect.

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