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Anadarko Petroleum (NYSE:APC)

Q2 2011 Earnings Call

July 26, 2011 10:00 am ET

Executives

Robert Daniels - Senior Vice President of Worldwide Exploration

James Hackett - Executive Chairman, Chief Executive Officer and Chairman of Executive Committee

Robert Reeves - Chief Administrative Officer, Senior Vice President and General Counsel

R. Walker - President and Chief Operating Officer

Robert Gwin - Chief Financial Officer and Senior Vice President of Finance

John Colglazier - Vice President of Investor Relations & Communications

Charles Meloy - Senior Vice President of Worldwide Operations

Analysts

Scott Hanold - RBC Capital Markets, LLC

Brian Singer - Goldman Sachs Group Inc.

Joseph Magner - Macquarie Research

John Malone - Ticonderoga Securities LLC

David Kistler - Simmons & Company International

Robert Christensen - Buckingham Research Group, Inc.

Bob Brackett - Sanford C. Bernstein & Co., Inc.

David Tameron - Wells Fargo Securities, LLC

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

Douglas Leggate - BofA Merrill Lynch

Unknown Analyst -

Operator

Good day, ladies and gentlemen, and welcome to the Second Quarter 2011 Anadarko Petroleum Corporation Earnings Conference Call. My name is Jeff, and I'll be your operator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to your host for today, Mr. John Colglazier, Vice President of Investor Relations and Communications. Please proceed.

John Colglazier

Well, thanks, Jeff. Good morning, everyone. I'm glad you could join us today for Anadarko's second quarter conference call.

Today's presentation contains our best and most reasonable estimates and information. However, a number of items could cause results to differ materially from what we discuss today.

You should read our full disclosures on forward-looking statements available in our presentation slides, our latest 10-K, other filings and press releases for the risk factors associated with our business. In addition, we'll reference certain non-GAAP measures, so be sure to see the reconciliations in our earnings release and on our website.

We encourage you to read the cautionary note to U.S. investors contained in the presentation slides for this call and as we do each quarter, we've included additional information in our quarterly operations report as available on our website. And we'll be filing our 10-Q for the quarter later this week.

With that, I'll turn the call over to Jim Hackett, our Chairman and CEO, who will be joined by other members of our management team later in the call to answer your questions. Jim?

James Hackett

Good morning, everyone. We're pleased to report another solid quarter of operating results, and we'll now share the significant achievements and upcoming catalyst with you.

First, the highlights. We achieved record crude oil NGL sales volumes of almost 300,000 barrels of oil per day -- excuse me, 300,000 barrels per day, which resulted in significantly improved corporate margins and cash flow. We finalized the Lucius unitization agreement, which further enhances the economic efficiency of this future megaproject. We successfully tested 3 wells at the Caesar/Tonga development, with each filling in at rates of about 15,000 barrels of oil per day. And we closed the purchase of the Wattenberg plant in Colorado, which will improve recoveries and enable future expansion in the DJ Basin, including growth in the horizontal Niobrara play.

The depth of the portfolio allowed us to direct capital investments toward areas that offer higher liquid yields. As a result of this focus, total liquids sales volumes for the quarter were 13% higher than the second quarter 2010, amounting to an increase of 3.1 million barrels. The increase in liquids volumes contributed to a 29% increase in adjusted EBITDAX per BOE over the same period last year. This margin expansion was enhanced by the widening differential between WTI and Brent, as more than 70% of our crude production is based on Brent equivalent pricing rather than WTI.

Our record sales -- liquids volumes also contributed more than $1.8 billion in discretionary cash flow for the quarter. This cash flow covered our capital expenditures in the quarter, including a one-time investment of $518 million associated with the Wattenberg plant acquisition, while still generating more than $100 million of free cash flow. Liquids growth was particularly strong in the Rockies. The Wattenberg field in Colorado delivered a 41% increase in liquids volumes versus the second quarter of 2010 and continues to set production records for the field.

In the DJ Basin, we are encouraged by what we are seeing from our horizontal Niobrara program. We have significant running room with about 900,000 net perspective acres in the Denver-Julesburg area, the majority of which is economically advantaged by our fee mineral ownership via the land grant. We're running 3 rigs that are focused on horizontal Niobrara opportunities in the DJ Basin, and we expect to add another rig to test multiple locations further north in the Powder River Basin, where we hold an additional 360,000 net perspective acres.

In the Greater Natural Buttes area of Utah, we set another fuel production record during the quarter, with average sales volumes representing a 16% increase over the second quarter of 2010. We're currently operating 6 rigs in the area and recently, initiated construction on a major pipeline and plant expansion that will increase our liquids processing capacity by about 250 million cubic feet per day.

Additionally, last month, the U.S. Department of the Interior recognized and supported our collaborative efforts to address the Greater Natural Buttes expansion project. This is a significant step forward in the infield development of this area that offers tremendous resource potential with more than 6,000 identified drill sites that will provide sustained production and economic growth for the region.

Moving to our Southern and Appalachian region, liquids volumes increased by 24% with oil volumes up 47% relative to the second quarter of 2010. In the Eagleford Shale, we increased gross sales volumes to approximately 45,000 barrels of oil equivalent per day at the end of the second quarter compared to 36,000 barrels of oil equivalent per day at the end of the first quarter of 2011. We continue to be very active in the Eagleford with 11 rigs running. We achieved first production from 33 wells during the quarter and continued to improve drilling efficiencies and recently drilled a total of 20 wells, each in less than 10 days.

In our West Texas Permian oil projects, liquids sales volumes for the quarter more than doubled over the same quarter in 2010. We've also continued to improve drilling efficiency by reducing our average drilling cycle times by about 20% or 7 days versus 2010.

Turning to the Marcellus Shale in Pennsylvania, we're currently producing more than 500 million gross cubic feet per day from about 125 wells. Anadarko operates 7 rigs here, and we've safely reduced average drilling cycle times by about 20% relative to last year.

Now as an update on our megaprojects, we'll start Offshore, Ghana at Jubilee. The partnership continues to ramp production toward capacity, which contributed significantly to our increase in oil volumes during the second quarter. Current gross production is averaging about 80,000 barrels of oil per day.

In Algeria, the El Merk project is nearly 80% complete. Construction of the central processing facility as an associated infrastructure is progressing, and the project remains on track for full facility completion in late 2012.

At Caesar/Tonga in the Gulf of Mexico, we recently completed flow tests on 3 wells. Each demonstrated robust flow rates of approximately 15,000 barrels per day of high-quality 27-degree API gravity oil. We're progressing 2 parallel riser solutions and expect to achieve first production in 2012.

With unitization and expected sanctioning of Lucius in the deepwater Gulf of Mexico, we're eager to add it to our future list of megaprojects. As announced last week, we'll operate the unit with a 35% working interest. Subsequent to the unitization, we also signed a production handling agreement, whereby natural gas produced from Exxon's Hadrian South deal will be processed through the Lucius facility, in return for a throughput fee and reimbursement of all capital associated with the expanded gas capacity. This agreement will also result in higher natural gas price utilizations for the Lucius partnership to reduce transportation costs.

During the quarter, we also completed a successful well test at Lucius. As designed, the well flowed more than 15,000 barrels of oil per day of high-quality 29-degree API gravity oil. The test reinforced our previous resource estimates and indicated that Lucius can be developed with a minimal number of wells. The economics of Lucius were already very compelling, and the results of the flow test unitization agreement and the production handling agreement have elevated those economics to a higher level, making Lucius one of the most economically efficient projects in our portfolio.

We've already begun ordering long-lead-time items including the floating truss spar production facility that will be designed with a capacity of 80,000 barrels of oil per day and 450 million cubic feet of natural gas per day. We expect to sanction this project later this year and are targeting 2014 for first production.

Our Offshore exploration appraisal program is accelerating significantly. We're embarking on one of the most active drilling campaigns in the company's history. Let me highlight the activities off the coast of West Africa. The drillship has just arrived Offshore Liberia to drill the Montserrado prospect. Following completion of activities in Montserrado, we plan to move the drillship to Sierra Leone to test the Jupiter prospect and drill the first Mercury appraisal well. We also plan to remain very active in Ghana and Mozambique, with additional drilling activities in Cote d'Ivoire, Brazil and China. In addition, we expect to receive a permit to drill the Heidelberg appraisal wells soon and look forward to resuming an active program in the Gulf of Mexico.

Turning to the financial results for the quarter. We reported earnings of $1.08 per diluted share. As with previous quarters, we provided a breakout in the earnings release of certain items affecting comparability, without which second quarter net income would have been about $0.06 per share higher. Although we mentioned this earlier, it's worth repeating that adjusted EBITDAX per BOE increased by about 29% versus the prior year quarter and discretionary cash flow is very strong at $1.8 billion, generating more than $100 million

[Technical Difficulty]

Operator

The Anadarko conference call will begin here in just a second.

[Technical Difficulty]

James Hackett

Let me try this. Let's start with the financial results and just about -- it's just a little bit back.

Just to repeat, we reported earnings of $1.08 per diluted share. And as with previous quarters, we provided a breakout in the earnings release of certain items affecting comparability, without which second quarter net income would have been about $0.06 per share higher.

And although we mentioned this earlier, it's worth repeating that adjusted EBITDAX per BOE increased by about 29% versus the prior year quarter and discretionary cash flow was very strong at $1.8 billion, generating more than $100 million of free cash flow after a one-time $0.5 billion investment in the Wattenberg plant.

We ended the second quarter with approximately $3.4 billion of cash on hand in addition to the undrawn $5 billion credit facility, which has a term through 2015. We also entered in new hedges for a portion of our 2013 natural gas production through 3-way collars and this appears in the earnings release.

As an update to the BP oil spill, we remain confident in our publicly stated position that we have not recorded a contingent liability associated with this event. We'll provide updated information on this subject in our forthcoming 10-Q.

Looking ahead to the third quarter, we expect sales volumes to be in the range of 58 to 61 million barrels of oil equivalent. This reflects a risk operational profile that includes assumptions for downtime related to weather and facilities.

In summary, we're very pleased with the performance of the portfolio in our quarterly results, and we're excited about the numerous significant catalysts in the months ahead. We look forward to updating you to on our progress in the coming quarters. And with that, Jeff, I might ask you to open it up for questions.

Question-and-Answer Session

Operator

[Operator Instructions] It looks like our first question of the day will come from the line of David Heikkinen. [Technical Difficulty]

Let me go ahead and move on to Mr. Bob Brackett with Sanford Bernstein.

Bob Brackett - Sanford C. Bernstein & Co., Inc.

Question related to Mozambique, twofold. One, that's an awful lot of core that you cut on the Windjammer and Lagosta. What were you targeting? And second, on the Camarão, if I'm pronouncing that correctly. Is that targeting oil or gas?

Robert Daniels

Yes. Bob Daniels here. On the core, we just cored the reservoirs that we had found in the previous discovery wells. And the idea there is to get really good petrophysical analysis, rock properties, so that we can put together our overall reservoir model and have a much better understanding about the flow units and fluids. We're going to get DSTs later in the year to where we have a good idea about pressures communication, compartmentalization or not. And the whole idea is to get that data to a third party that can then do a resource certification for us through 2012. So that's the idea. The analysis, the lab work on the cores takes the longest. So we want to get that up front. And so because we got a very big project here, we want to make sure we got all the data that we need up front. As to the Camarão, it's not an oil project or prospect. That's in the same area, the LaBarge and Jammer area. And we're looking for an appraisal to the Windjammer prospect and also some additional sands that we did encounter in the original well. So it's an exploratory well from that standpoint, and that should be spud the second half of the year here.

Operator

And our next question comes from the line of David Heikkinen with Tudor, Pickering, Holt.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

As you look at your exploratory program, I wanted to hit the West African ongoing programs. First Ghana, can you talk about thoughts around extension of West Cape Three Points and any other prospects there first?

Robert Daniels

Well, again, David, this is Bob Daniels. On the West Cape Three Points, we've got an active exploration program going there. We're on a CASA right now, which we used to call the Updip Dahoma prospect. And of course, we've got the Mahogany East that we've already drilled and appraised. We have Teak as the discovery and several other smaller discoveries in there. And what we're trying to do in the West Cape Three Points block is to see do we have enough resources there that can be aggregated together to have another development. And of course, we have to have the exploration and appraisal work done. We plan on getting back to Teak later this year for an appraisal well there. We also have the Cedrela prospect that we'd like to get to. We had a rig lined up for it and then it had an issue with the previous operator, so we're looking at how we're going to get that well drilled. But there's still additional activity on the West Cape Three Points, all focused on do we have enough for another project there?

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

Where's Cedrela and the rig delay? Did you get an extension to the timing on the license?

Robert Daniels

The operator filed a force majeure, and we're going to have wait to see how that all plays out and then [indiscernible] there.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc.

And then going up West Africa and Liberia and Sierra Leone, the other 2 prospects, Kosrou and Paon, can you talk about those? I know the other 3...

Robert Daniels

Yes, those are the 2 in Cote d'Ivoire. And originally at the beginning of the year, we'd said we were going to drill 3 to 5 exploratory wells in West Africa this year. And then we dropped to 3, and that was because of the political situation in Cote d'Ivoire. That's been settled. We can now operate in Cote d'Ivoire, where service companies are moving back in. Our office is up and operating. We've come out of force majeure, we've contracted a rig actually to drill those 2 wells that will both start with CI-105, probably November-ish time frame. And then the CI-103, which is the Paon prospect, will be followed thereafter immediately. So we have the first 2 slots on the rig that's coming. And we do expect at least the first one to spud this year and probably the second one to at least spud this year. They're good prospects, they look very similar to the Jubilee style that we're pursuing, same targets with the Cretaceous-age fans coming off this shelf. And we wanted to drill these wells for a while, and now we can.

Operator

And our next question comes from the line of Dave Kistler with Simmons & Co.

David Kistler - Simmons & Company International

Real quickly looking at your exploration slide for the Offshore campaign. I noticed in Gulf of Mexico that Phobos is no longer on that list. Is there any particular reason for that? And then in the Gulf of Mexico, what would you kind of rank as your top prospects for this year?

Robert Daniels

Yes, Dave, Bob Daniels again. Phobos is just off the list because of the timing. We're looking at 2012 spud for that, nothing to do with quality of prospect or anything like that. It's just as we looked at which ones can we move through the system as the regulatory environment that we see, we need to get our appraisal work done, the wells that we are already working on, such as Heidelberg. And then Spartacus looks like it's going to be an easier process to move, very more straightforward. So we've been pushing that one as an offset to the Lucius discovery. The kind of syncline separated off to the northeast, and we do expect to spud that either very late this year or early next year. So we have a very good inventory of prospects ahead of us. Phobos is one of them that if you looked out into 2012, is on the list. Also we tried to put here is what's going to happen over the next 6 to 9 months.

David Kistler - Simmons & Company International

Great, I appreciate that clarification. And then looking at your efficiency gains in the Eagleford, Marcellus, Bone Springs specifically, can you talk a little bit about what that does as far as accelerating a drilling activity program there? And then how that impacts costs? Obviously it offset some of the costs inflation you're seeing. But aggregate costs, if you are going to be drilling more wells, could be going higher. Just trying to think about how that flows through to CapEx.

Charles Meloy

Well, we're very -- This is Chuck. We're very excited about how our drilling teams have performed in each one of those assets. They're doing a spectacular job, actually gaining more efficiency in every element of the well construction process. What we think we're going to do or how it's playing out right now, we're drilling more wells with the same rig count in the order of 40% more in several of these plays. And we're actually getting that many more wells drilled with the same effort, given risk planning, which gives us a much higher net present value for the production, because we get it on quicker. And it costs less to drill any individual well. The aggregate CapEx is going up on a program basis in a given year because we are putting more tangibles in the ground. But our intangible costs are actually coming down. And so that all makes the economics better.

David Kistler - Simmons & Company International

Okay, great, I appreciate that. And then just one last one, if I can. With respect to the Wattenberg plant acquisition that's allowed you guys to increase liquids yields there and have great visibility on your running room for liquids production, do you look at making investments, pretty substantial investment on the liquids side of things in some of these other fields, like the Eagleford or potentially even parts of the Bone Springs, to be able to, well, be able to continue with that kind of similar visibility and forward projections?

Charles Meloy

Dave, we're looking at each one of those carefully. When we have plans to maximize our revenues off each one of those fields. So additional wells and plants are under consideration in some level of progress right now.

James Hackett

I might mention too, Dave, on that is we don't see an immediate need to do a big step out with capital on those infrastructure elements in those plays like in Wattenberg. That was a fairly unique situation, where we had some very underwater contracts based on a very old plant arrangement. And there's plenty of competition in these other areas for new infrastructure. So I don't see the same kind of magnitude, if you will.

Operator

And our next question comes from the line of Doug Leggate with Bank of America Merrill Lynch.

Douglas Leggate - BofA Merrill Lynch

Going to try a couple, if I may. Caesar/Tonga, given the delays to first oil, and the success you've had with the test results, is there any change to the development plan there? I seem to recall you were looking about 40,000 barrels a day through Constitution. But it seems that the field could do a an awful lot better than that. Can you talk a little bit about? And I've got some follow-ups please.

Charles Meloy

Doug, this is Chuck. Actually, we've drilled and tested all 3 wells now and in excess of 15,000 barrels a day per well. And what we have between Caesar/Tonga and Constitution is a minimum capacity of 40,000 barrels a day. So if there's upside opportunity on Constitution, we can push the rates up with the wells that we have. And we also have planned an additional well down the road, once we get the facility in subsea system, et cetera, wind down. With regard to the riser, we're progressing 2 additional solutions, both of which have first production in 2012. And so we're on schedule to make that happen and you should see that coming forward soon.

Douglas Leggate - BofA Merrill Lynch

Okay, so no change to the original plan, Chuck.

Charles Meloy

Yes.

Douglas Leggate - BofA Merrill Lynch

Okay. My follow-up is first of all in Brazil, obviously, you've laid out the 3 appraisal wells here. But what's the plan beyond that? I mean, with these 3 wells, are you done -- will you be done in Brazil in terms of scoping out the scale? In which case, what do you see as the running room there? And finally if I could ask you this to talk a little bit about Mercury. I guess a commentary in the release suggested that you'd be looking at DST there at some point. Can you just maybe give us an idea of what you're looking for there? What do you think the ultimate scale of that asset could be, and perhaps what the plan going forward could be? Because I guess that seems the closest to moving towards development, or maybe I'm wrong there. But now with the -- give us some color there and I'll leave it at that.

Robert Daniels

Yes, Doug. Bob Daniels. On Brazil, we've got the 3 wells going. We're on Itaipu right now. That's the first appraisal well of that discovery. So whether or not that's going to move us to a sanction point is -- we'll probably will need additional drilling after that. Wahoo, towards the end of the year, we'll be drilling the second appraisal well, second location really for appraisal. That could help us define now the previous DST and appraisal work, what we have there are much better. And then Itauna, which will spud in September, remember that's a shelf discovery post-salt, potentially a simpler -- well, it's clearly a simpler development, potentially a simpler reservoir system. And we try to design the program there that with very good news at Itauna, we may have enough to actually have confidence we can move that one forward. So that's what the appraisal's focused on. We'll need something else into Itaipu. Wahoo can help us a lot, get to a decision point. And then Itauna, potentially, with good news could be enough. As to Mercury, when we put a DST in there, we've talked about it being Mercury as the most likely one. But we actually have the option to DST in West Africa, any of the wells that we want to. And so we're going to drill the wells and decide then what's the best place to run a DST based on the results.

Douglas Leggate - BofA Merrill Lynch

Are you prepared to give any kind of idea of what you see as a scale of the opportunity there at this point, or is it still too early?

Robert Daniels

We can talk about that in all of those. These are Jubilee style or Tweneboa/Enyenra style, which there are subtle differences between the 2, but they're overall the same Cretaceous fan systems coming off. It's where you are in that overall fan system. One, you're down in the basin floor where you have more low-bake type geometries. Another, you're up a little bit more in the channelized system. And so the combinations of the 3 we're testing, we'll look at both of those. But we're looking at things that are the Jubilee and Tweneboa style and size. The scales are very, very similar. When we look at these, at least the sand geometries and the sand scale, we're looking at very similar size and scale to what we see in Ghana. So we're looking for multi-hundred-million-barrel type objectives.

Douglas Leggate - BofA Merrill Lynch

Could I just squeeze one more in very quickly? The sequential drop in volume guidance Q2 to Q3, can you just quantify what you're assuming in terms of downtime, just in case we don't get kind of hurricane season that maybe you priced in? And I will leave it there.

Charles Meloy

Doug, we always have and will provide sort of a risk operational profile that's inclusive of what our historical weather patterns have been and the downtime associated with those, as well as what we anticipate downtime on our facilities around the world for plant maintenance and just normal outages. And you can see from historical performance that it's particularly like in the last 3 years if you look through the second and -- I'm sorry, the third and fourth quarter guidance, we hit it very well on a risk basis through time.

Operator

Our next question comes from the line of Robert Christensen with Buckingham Research Group.

Robert Christensen - Buckingham Research Group, Inc.

Can you spend a little more time on the Wattenberg processing plant purchase? How much more money are you going to put into it? And how accretive it could be, and when that accretion could start to show up?

Charles Meloy

This is Chuck. What we're seeing in Wattenberg, just a big picture, if you step back far enough, the early returns on our horizontal drilling campaign have been outstanding. And what we've decided to do is make strategic moves together, all the value chain we possibly can within Wattenberg inclusive of the plants, the gathering system and land. And through that, we are going to put a very comprehensive development plan together, which includes the full utilization of all the plant assets we have out there, which now include the Wattenberg plant we just acquired from BP, the Platte Valley plant we acquired from EnCana and the facilities that we had, legacy facilities that we had at Fort Lupton. So the combination of all of those, we think we can use to reduce our land pressures, increase our run time and increase our recoveries both on our base production, which has historically been in Niobrara and Codell and J Sand wells and take full advantage of our horizontal program in the Niobrara, both inside Wattenberg and the greater DJ.

Robert Christensen - Buckingham Research Group, Inc.

And is it fair, a financial question I guess, to say if I take that purchase out of the capital spending in the quarter that I would add that to your $117 million of free cash flow, so that the quarter really was -- adjusted free cash flow of $635 million. Is it fair to look at it at your company that way? That would appear to be a little early for Anadarko generating free cash flow. I remember sort of thinking next year would be a free cash flow year. I know it helped by $100 oil. But it appears to me free cash flow has arrived in quantity earlier than expected.

James Hackett

No, that's exactly the way to look at it. And obviously, that's driven by liquids volumes and our substantial price realizations related to Brent.

Robert Christensen - Buckingham Research Group, Inc.

If I might just take one more, and it's a Macondo-related question. So when does the trial in New Orleans begin? Is there a date for commencement of the trial?

Robert Reeves

This is Bob Reeves, Robert. The multi-district litigation, so far, Judge Barbier has indicated there will be a multiphase trial, with the initial liability phase starting at the end of February of next year.

Operator

Our next question comes from the line of Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc.

You touched a little bit on the Niobrara. But I was wondering if you could give some more color with 15 wells now producing. Your thoughts so far, which zone 2 drilled horizontally and are producing, any additional color on what you're seeing.

Charles Meloy

Well, as I mentioned earlier, the early results look really good. And I think the uplift in our Wattenberg liquids volumes quarter-over-quarter and year-over-year, are indicative of the type of results that we're getting. We still think it's a little early in the game to come out and say, here's a [indiscernible], because we're exploring a very large area. As you know, we have almost 900,000 acres in the DJ Basin to look at. And so we're being very methodical about our approach to evaluating that acreage. And then in addition, we're going to start a program up in the Powder River Basin, which is another 300,000 barrels so -- 300,000 acres. So we have a very large area to evaluate. But again our early returns look really well, really good and you're starting to see that result come through on our flow volumes that we report quarter-to-quarter.

Brian Singer - Goldman Sachs Group Inc.

And I guess what percent of the wells that you've drilled so far, the horizontal wells, are focused on the Niobrara zone versus the Frontier zone or other zones? And is there a way you could characterize of that 900,000-acre position, as what percent do you feel like you've drilled and have confidence in or have a view that it's repeatable in the absence of natural fractures?

Charles Meloy

Well, most all of the wells we've drilled so far have been Niobrara wells. We are yet to drill -- we've drilled Frontier wells several years ago, but are just about to start our campaign up in the Powder River Basin here in the next couple of months. So the vast majority have been Niobrara. We've actually tested a couple of other zones with one well. We're going to continue to evaluate the Codell and the Sussex and others, a potential as well in the DJ. As to what's prospective, if you look in the DJ Basin, about 200,000 or 300,000 barrels of -- I'm sorry, 200,000 or 300,000 acres of our position is in Greater Wattenberg, where we have 3,000 or 4,000 producing Niobrara wells. So we know it's very good in there. We've drilled infill wells with horizontals, and have then -- the early returns, they look very good. And we're out exploring, we've drilled about 7 or 8 wells thereabouts, along with Industry, who's drilled another several dozen wells in the Greater DJ Basin. And some of those show very good potential for very good economic returns.

Brian Singer - Goldman Sachs Group Inc.

Great. And then lastly, following up on the last -- the previous question, the previous questioner, if Brent prices stay flat or strengthen from here, you'd be in a very good position from a free cash flow perspective next year. How do you look at capital allocation? Does that make you want to hold on to Mozambique versus seeking a partner? Does it make you want to accelerate exploration offshore broadly, deploy more rigs onshore U.S.? How do you think about capital allocation?

James Hackett

Well, Brian, in the past, we've identified our capital structure, keeping our debt to cap in that 25% to 35% range. And if we start generating free cash flow that would cause us go below that range, and obviously we've got a ton of opportunities around the world. And we would continue to invest in those opportunities, because we think they provide excellent rates of return.

Brian Singer - Goldman Sachs Group Inc.

And do you see at all any constraints on the infrastructure side to ramping up in onshore U.S., and how that would compare versus, say, an exploration ramp-up offshore internationally?

Charles Meloy

Well, generally on the onshore assets, we're pushing really hard to expand our infrastructure position. Wattenberg is a great example with the new plants and the pipeline that we have taking crude into Cushing. We also have expanded substantially in our position into Marcellus. And so each one of those are available to us. And as we get incremental infrastructure built out, we can add rigs and that's what we've been doing.

James Hackett

And just on the offshore international side, as you might appreciate, I mean, I think we're in a good environment from a rig standpoint. Return marks are a little tighter on the spot market. But the spot is available, so we can do some things there as well.

Operator

Our next question comes from the line of David Tameron with Wells Fargo.

David Tameron - Wells Fargo Securities, LLC

Let me hit a couple, going back to Wattenberg. Would you have made that acquisition with or without the Niobrara, i.e., does the success of the Niobrara factor into the decision to make that acquisition?

Charles Meloy

It certainly had to. We had early results that looked really good. And we felt like it was important for us to control our destiny in the field, so we could maintain very constant land pressures on our gathering system, as well as reap the benefits of improved processing margins and increasing liquid volumes, plant liquid volumes, with the associated gas in the Niobrara. So the whole system worked for us to put that together, and it was a tremendous value proposition for us.

David Tameron - Wells Fargo Securities, LLC

Okay. I'm just going to state the obvious here. I mean, you drilled 40. You're going to drill 40 wells this year. You just made a big plant acquisition. You won't give us well results but it's -- you're obviously encouraged? I mean, -- okay, I'll move on. I'll circle back to that some point until I get some production data from you. Let me jump to Greater Natural Buttes. It looked like NGLs were down quarter-over-quarter, year-over-year. Is that the cryo plant, when does that hit? And is that -- you've run into some process issues up there and should that alleviate those?

Charles Meloy

David, what we have is Chipeta Train 2 is a cryo plant and during the quarter, we've had excellent results with it. It's been running great. During the quarter, we had electrical outage on one of our pumps, on our generators there so we were down for a few weeks. And so if you look at instantaneous rates, it's equal to the first quarter. We just had a period of downtime during the second quarter. That's back up and running now and at full rate and volume.

David Tameron - Wells Fargo Securities, LLC

Okay. And then what's the cryo plant? Are you going from 250 to 500?

Charles Meloy

Train 3 will be an additional 250 million cubic feet of cryo gas processing.

David Tameron - Wells Fargo Securities, LLC

Is that 6 months out? Or when do you expect that to come on?

Charles Meloy

What we're doing -- we hope it's in the order of about 12 months is our expectation, 12 to 15 months right in there. We're just now starting construction, and a lot of the infrastructure that we need is already there. We're building in on the same plant site that Train 2 is on. It's just a little early days to pin down on a completion date, but in the 12- to 15-month time frame.

David Tameron - Wells Fargo Securities, LLC

Okay. And then whoever wants to take this next one. There's talk coming out of D.C. about a potential tax holiday? Obviously, you have a significant amount of international assets. But if something like that were to go through, is there any impact financially, strategically to your operations?

James Hackett

Well, obviously it depends upon the nature of what might get passed. But a tax holiday would be a net positive for us, and we would appreciate it and look forward to it, obviously.

David Tameron - Wells Fargo Securities, LLC

But I mean, there's no potential, anything we'd see in the numbers overnight?

Robert Gwin

No, no. I don't think so. I mean, there's so many different things being discussed, it's such a broad question. But from a holiday standpoint, if you're talking about repatriation of funds or anything like that, I don't think you should expect that's anything would materially move our numbers.

James Hackett

I think they need to focus on restructuring the corporate tax rate as opposed to tax holidays. That's our position formally.

Operator

Our next question comes from the line of John Malone with Ticonderoga SEC.

John Malone - Ticonderoga Securities LLC

Just 2 quick questions. The first one is on Nigeria. Can you give a little color on some of the political situation there? Where things stand with Sonatrach?

R. Walker

This is Al Walker. A little bit on that. We certainly, like everybody else, have been watching the Middle East and North Africa with a lot of interest since the first of the year. We and Sonatrach entered into a formal arbitration process in Paris in June. That concluded. We continue to have discussions around TPE. We're certainly open to ideas that could be independent of what that arbitration tribunal might decide later this year with a ruling. We think our relations with Sonatrach, despite all of that, are excellent. At the field level, we continue to have really good results. El Merk is progressing pretty much on track with the expectations now of having things completed in 2012. And I'd say in general, the unrest in North Africa has certainly been a concern. We don't see any evidence of its impact on approximately 40% of the country's production that we operate, and hopeful the issues around TPE will get resolved by year end.

James Hackett

And only thing I'd add to that is as you recall, we had probably $7 a share taken out of our stock at the time the TPE was passed. It would amount to more than that currently. We don't think there's any equity value in there for a settlement or for a favorable decision. And so from our perspective, it's all upside from here.

John Malone - Ticonderoga Securities LLC

Okay. And just an unrelated question. Is there been any movement on -- this is just looking farther out, but the LNG developments in Mozambique, in East Africa, are you guys talking to buyers, are you talking to EPC contractors, is there anything new to look at there?

Robert Daniels

Yes, John, we're going through all the normal processes of kicking off this LNG project. We actually have issued pre-FEED contracts to start working through the scope and scale is of this development. I think what we're most excited about is the results from the drilling and appraisal program. Our exploration team, they found a tremendous resource. And we're going through the process, the balance of this year and early next year to really size that up. And once we have definition around that, just how big it is and it looks fairly substantial, once we see how big it is, we'll start closing in on what the design parameters are for the plant, and then get into the actual process of FEED and sanctioning that project in 2013 time frame.

Operator

Our next question comes from the line of Joe Magner [ph] with Nazarene [ph] Capital.

Unknown Analyst -

There's been a lot of discussion in the marketplace recently about the possibility for a settlement with BP. I'm not going to ask you to speculate on this for the possibility of that. But can you just remind us where things stand? What mechanics of the arbitration process are for the companies? The status of your lawsuit against BP, the cost upon the multiphase litigation, the status of your lawsuit with BP? And then time line with respect to any outstanding investigations or reports, or anything else that might affect the process there?

Robert Reeves

Yes. This is Bobby Reeves. Let me just mentioned first, there's a lot more detail that will be on our 10-Q and putting up to -- as we've done every quarter. We'll update that disclosure in the 10-Q to be filed later this week. I will refer you specifically to that for details. But briefly, there was a notice of dispute submitted by BP under the joint operating agreement. We're in a process of time line as provided under that agreement, to consider whether or not resolution is possible. After a particular time period, then either party can move forward with arbitration. We have not reached that time yet. And then that would invoke the time line for arbitration, which at the earliest would be sometime next year. With respect to settlement, we feel good still about our position that we've talked about for over a year now, but at the same time, remain open to discussions.

Unknown Analyst -

Okay. And then there's the discussion about how the next 6 to 9 months could be the most active in company's history of the deepwater in the Gulf of Mexico, deepwater exploration front. You touched on Heidelberg. You expect a permit there, and the thought that Spartacus could move through the process quickly. Can you just give us any additional detail on your anticipated recovery of permitting? Or any other regulatory developments that you can shed additional light on where things stand?

Robert Daniels

Okay, Joe, this is Bob Daniels. Just on the rest of the wells, I touched on Heidelberg and Spartacus because those are the ones we operate and we're moving those through the system. We have the most control over those. But our partners in other wells are moving and progressing very well through the regulatory environment. And that would include Coronado and Yucatan over in the Shenandoah mini basin. Both Chevron and Shell are both moving permits through the system. Vito, which is one of our discoveries that we have an interest in that Shell operates, they're moving permits through the system there. And then we're presently involved with the Kakuna well, which is drilling. We have a carried working interest in that well, so they have successfully obtained a permit on that. So while the process has been slow, people are getting greater clarity around what the requirements are and the EPs and APDs are moving through the system. It just needs to move through the system on a quicker pace. But we do anticipate quite an active second half of the year in both operated and non-operated wells and continue on into 2012.

Joseph Magner - Macquarie Research

Okay. So just to summarize, it's more the process, kind of getting the kinks worked out of the process more than any other things that need to fall into place, any other major...

Robert Daniels

That's exactly it. It's just understanding the new process and then what the requirements are under that, and making sure that it's a lot of give and take, or back and forth, I guess I would say, until there's some clarity around each step of the process. And once you've done it once, then it's much easier in the subsequent applications.

Operator

And our next question comes from the line of Scott Hanold with RBC Capital Markets.

Scott Hanold - RBC Capital Markets, LLC

Could you all touch on in China the Baiwang prospect? When are we going to spud that based on your best estimate? And remind us of sort of how long it could take to drill that well?

Robert Daniels

Scott, Bob Daniels. Right now, our best estimate is it will spud in the fourth quarter of this year, the rig is under contract. We are doing all of the detailed planning for the well. And they're doing essentially sea trials on the rig to make sure it's all ready to go. So end of the year, late fourth quarter is when we look to spud that well.

Scott Hanold - RBC Capital Markets, LLC

Okay. And how long do you think it would take to get down?

Robert Daniels

Well, it's probably about a 60- to 70-day well at this point.

Scott Hanold - RBC Capital Markets, LLC

Okay. And then with the, I guess, results you all see when you get down there. I mean, how is that news flow going to work? Are you going to sort of be waiting for a senior take the lead there? Or would you be able to put some out independently?

Robert Daniels

Scott, I'll say it's just like all of our wells, you have to get approvals from both the partners as well as the host government on these internationals, so it will be dependent upon as you get the approval stacked up on it.

Scott Hanold - RBC Capital Markets, LLC

Okay, then and one last question. On the Niobrara, I know you all had talked about looking for a JV partner potentially. Has that thought process changed based on what you've seen so far? And I guess coupled with the fact that as the prior questioners appropriately indicated, you've got a lot of free cash flow given strength in Brent and what not.

R. Walker

Well, this is Al Walker. I think as it relates to a joint venture opportunity in the Niobrara, like we have done with the other shale plays and other things that we've monetized, we will look at that when we think the opportunity is right. That opportunity could present itself in the near term or it may be a little longer. I just think you have to look at the fact over the last 5 years, we've monetized substantially amount -- a substantial amount rather, approaching $25 billion in assets. So we certainly have a track record of doing it the right time, and I just think I would lean on that track record more than looking at it, perspectively.

Operator

All right, ladies and gentlemen, this concludes the Q&A portion of the call. I'd now like to turn the presentation back over to Mr. Jim Hackett for closing remarks.

James Hackett

Thanks, Jeff. And I appreciate everybody participating today. We look forward to seeing many of you in the coming months or talking with you in our next earnings call. In the meantime, we'll continue to work hard to deliver positive results for all of you and hope you have a great day. Thank you.

Operator

Ladies and gentlemen, that concludes today's conference. Thank you for your participation. You may now disconnect. Have a wonderful day.

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