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Executives

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

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

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

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

Charles A. Meloy - Senior Vice President of Worldwide Operations

R. A. Walker - President and Chief Operating Officer

A. Scott Moore - Vice President of Marketing

Robert P. Daniels - Senior Vice President of Worldwide Exploration

Analysts

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Subash Chandra - Jefferies & Company, Inc., Research Division

Joseph D. Allman - JP Morgan Chase & Co, Research Division

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

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Joseph Patrick Magner - Macquarie Research

Scott Hanold - RBC Capital Markets, LLC, Research Division

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

Brian Singer - Goldman Sachs Group Inc., Research Division

John Malone - Global Hunter Securities, LLC, Research Division

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

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

Anadarko Petroleum (APC) Q4 2011 Earnings Call February 7, 2012 9:00 AM ET

Operator

Good day, ladies and gentlemen, and welcome to the Fourth Quarter 2011 Anadarko Petroleum Corporation Earnings Conference Call. My name is Larry, and I will be your operator for today. [Operator Instructions] I would now like to turn the conference over to your host for today, Mr. John Colglazier. Please proceed.

John M. Colglazier

Well, thank you, Larry. Good morning, everyone. We're glad you could join us today for Anadarko's Fourth Quarter and Year-end 2011 Conference Call. We also look forward to hosting to you at our investor conference here in The Woodlands on March 13, where we will provide a more in-depth look at the growth and value-creation opportunities our portfolio can deliver, as well as discuss our 2012 capital program and guidance.

I need to remind you that today's presentation will contain our best and most reasonable estimates and information. However, a number of factors could cause actual results to differ materially from what we discuss.

You should read our full disclosure on forward-looking statements 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 we've included additional information in our quarterly operations report on our website.

In just a moment, I'll turn the call over to Jim Hackett, our Chairman and CEO, who will discuss our 2011 results. Jim is joined by other members of our executive team, who'll be available to answer questions later in the call. With that, let me turn it over to Jim.

James T. Hackett

Thanks, John, and good morning, everyone. Anadarko had a strong finish to an excellent operational year, leading to record volumes, strong cash flows and industry-leading exploration success. In 2011, we delivered sales volumes at the high end, while holding capital expenditures at the low end of guidance. We continue to drive improvements in drilling efficiencies across our U.S. onshore operating areas, and this contributed to record sales volumes of 248 million barrels of oil equivalent, while spending less than anticipated in -- cash capital and achieving the best safety performance in the company's history.

In addition, we are well on our way toward meeting our objective of 3 billion barrels of oil equivalent of proved reserves by year-end 2014. We replaced 159% of our produced reserves at competitive cost this past year and ended the year with approximately 2.54 billion barrels of oil equivalent of proved reserves, which is a 5% increase over year-end 2010 and was accomplished almost entirely through the drill bed.

Our record sales were driven by a 10% year-over-year increase in liquids volumes, which averaged more than 290,000 barrels per day. During the fourth quarter, approximately 70% of our crude oil volumes received waterborne pricing, resulting in an overall oil price realization of $11 per barrel above WTI. We also benefited from NGL volumes, receiving 59% of WTI pricing through our ability to access Mont Belvieu in the premium Gulf Coast markets.

These results demonstrate that our liquids-focused capital allocations are working. At year-end 2011, liquids comprised 43% of our total sales volumes, delivering an incremental 70,000 barrels per day or a 31% increase since 2008, when we began targeting liquids-rich areas of our portfolio. We plan to continue this capital allocation approach that will drive us toward higher liquids production in the years ahead.

Our fourth quarter results provide an excellent illustration of significant liquids-growth achieved in several of our core operating areas. For instance, in the Wattenberg field, which we'll talk more about momentarily, we achieved a 24% overall sales volume increase over the fourth quarter 2010, with liquids from the field increasing at twice that rate, adding almost 13,000 barrels per day.

Comparing year-over-year gross exit rates in the Eagleford Shale, we achieved an increase of approximately 50,000 barrels per day from our TEN rig program, representing 185% growth. We remain one of the largest producers in this highly economic area with a gross production exit rate of approximately 77,000 barrels of oil equivalent per day and with liquids comprising approximately 65% of the production stream.

Collectively, shales have become a material contributor to our portfolio. In 2011, our shale plays delivered a year-over-year sales volume increase of almost 200%. Shale volumes now account for slightly more than 10% of our total company sales volumes, up from less than 1%, 2 years ago. Shales also represent about 5% of Anadarko's total proved reserves.

In addition to growth we've realized in the shale plays to date, we're very excited about our horizontal Wattenberg opportunity in Colorado. It's not easy to find a 1 billion barrel field, so to have this kind of opportunity in your own backyard is especially unique. In November, we announced a potential of 500 million to 1.5 billion barrels of oil equivalent of liquids-rich net resources which is accessed by applying horizontal drilling technology to the Niobrara and Codell formations that are underlying our 350,000 net acre position in the Wattenberg field. The Wattenberg horizontal program has all of the key components of a major resource play. Its exceptional economics are driven by estimated ultimate recoveries of between 300,000 and 600,000 barrels of oil equivalent per well.

High-quality, liquids-rich reservoirs, very competitive development and drilling costs currently estimated around $4.5 million per well, a premier land and mineral position, operation of an access to existing infrastructure and extensive knowledge of the subsurface as a result of years of activity in the area.

As the largest producer in Wattenberg and in anticipation of the significant growth offered by the new Wattenberg horizontal program, we took strategic steps to enhance the alignment of our upstream and midstream assets in the region by purchasing the Wattenberg plant early in 2011. This acquisition, combined with existing infrastructure and the Western Gas Partner affiliates' purchase of the Platte Valley plant provides us with substantial operating processing capacity in the Wattenberg field and Greater Denver-Julesburg basin.

In the fourth quarter, Wattenberg averaged approximately 76,000 barrels of oil a day, equivalent with a growing liquids composition. We look forward to updating you on Anadarko's Wattenberg horizontal activities and plans for 2012 and beyond at our investor conference next month.

Adding to our liquids growth profile in 2012 and beyond, we made significant progress in our mega projects, all of which are oil focused. In the Gulf of Mexico, we are currently installing the production risers at Caesar/Tonga, and we continue to expect first oil sales by mid-2012. We also unitized and sanctioned the deepwater Lucius project in 2011. Fabrication on the 80,000 barrels of oil per day spar is underway, and all major contracts have been awarded. We plan to bring this capital-efficient project to first production in 2014.

The 130,000 barrel per day El Merk project in Algeria is on target, and we expect meaningful oil volumes by the end of next year. The project is now about 88% complete, and our contractors continue to make excellent progress. In Ghana, our partnership is advancing the TEN complex, which status for Tweneboa, Enyenra and Ntomme toward a planned development that is expected to be completed later this year.

During the exploration, our worldwide deepwater exploration and appraisal drilling programs continue to create differentiating value, as we achieved an 80% success rate for wells completed in 2011. This success included de-risking the TEN complex offshore Ghana that I just mentioned, as well as adjacent discoveries at Teak and Akasa. We also made our first post-moratorium discovery in the Gulf of Mexico at the Cheyenne East prospect. The well is already being tied back to Independence Hub, with first production expected by the end of this quarter. We plan to return to pre-moratorium exploration levels in the Gulf this year, as we expect to participate in at least 6 deepwater wells.

The most significant highlight of our 2011 exploration program was tripling the recoverable resource estimate offshore Mozambique to a range of 15 to 30-plus Tcf. Our 2011 activities included 4 successful wells and further confirmation of the connectivity and scope of this massive natural gas accumulation, which is shaping up to be one of the most significant natural gas discoveries in the last decade.

We recently brought a second drillship to the block to conduct testing, while the other vessel continues appraising and exploration activities. In parallel, we're working with our partners in the government of Mozambique to advance the development of an initial 2-train onshore liquefaction facility. We continue to target third-party reserve certification and a final investment decision around year-end 2013, with first production anticipated in 2018.

As I mentioned earlier, we replaced 159% of our reserves in 2011 and ended the year with approximately 2.54 billion barrels of oil equivalent of proved reserves. We added 377 million barrels of oil equivalent or proved reserves from the drill bit and incurred costs of around $5.6 billion. Proved developed reserves now comprise about 71% of our year-end total proved reserves, which is even stronger than the 69% we reported for year-end 2010.

Turning to the fourth quarter financial results, we included a table in yesterday's earnings release regarding certain items affecting comparability, without which, net income would have been $0.85 per share approximately. The largest of these items, which are typically excluded by the investment activity in published estimates is a $1.5 billion or noncash impairment, primarily related to our CBM properties in the Powder River. Impairment was triggered by low natural gas prices, which reduces the post-2006 acquisition's assigned carrying value of the assets. It has no impact on proved reserves.

Another item is a noncash charge of $250 million related to the Tronox adversary proceeding. We are confident about our case and are preparing for trial. We're currently engaged in the mediation process, and this noncash charge reflects the current estimate for reaching resolution.

The value of our high liquids volumes generated exceptional discretionary cash flow for the year of approximately $7.2 billion, equating to $29 per barrel of oil equivalent, which is a 26% improvement over 2010. We generated approximately $625 million of free cash flow during 2011, even taking into consideration $880 million of investments associated with 2 strategic midstream infrastructure acquisitions in Colorado.

In addition, as you are aware, we resolved the dispute with BP over the 2010 Deepwater Horizon event, removing significant uncertainties for our stakeholders and returning everyone's focus to the growth and value-creation opportunities in Anadarko's portfolio. We financed the settlement using $1.5 billion of cash on hand and $2.5 billion from our revolving credit facility. We ended the year with approximately $2.7 billion of cash on hand, which included the receipt of insurance proceeds related to the Deepwater Horizon events and $419 million of contingent proceeds from the 2008 Peregrino sale in Brazil. We remain committed to reducing our net debt to cap level back to within our target range of 25% to 35% over the coming year, and we expect to accomplish this primarily through asset sales and performance.

As I stated at the beginning of the call, we had a strong finish to an excellent operational year. Recapping the fourth quarter, we delivered strong liquids growth, enhanced price realizations and midstream margins, low operating costs, improved DD&A from low-cost reserve additions, capital efficiency and continued exploration and appraisal success.

The results of 2011 built greater momentum around our predictable and repeatable performance, with unmatched exploration upside for our investors. We believe we are well positioned to continue that success into the next decade. We hope to see all of you in our March 13 investor conference, where we'll discuss our forward plan in more detail.

With that, operator, if you would now open up for questions, I'd appreciate it.

Question-and-Answer Session

Operator

[Operator Instructions] And our first question comes from the line of Doug Leggate of Bank of America.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

If I could kick off with an exploration question, and then I have a follow-up, Jim, on Algeria, please. Jupiter is still drilling. My recollection is that this was similar in structure to 1 or 2 of the other wells that you've drilled out there so far. But it seems to be going on for quite a long time, and I'm just wondering if there's a particular prognosis that one of the guys can give us there. And related, the implications of the Itauna result on the Brazilian sale process. And I have a follow-up on Algeria, please.

Robert G. Gwin

It's Bob. Regarding the Jupiter well, yes, it's taken a little bit longer than we’ve typically drilled out there, and that's just typical operations. We had some things we had to do on the rig at one point in time. We're getting close to the end, and we'll have information on that when we get the well down and completely evaluated. And then, of course, we're going to move from there over to our Mercury appraisal well. And so we've still got a lot of work to there in Sierra Leone. Meanwhile, we're drilling in Cote d'Ivoire on our coast drill wells, so similar play type and looking for more success out there. Regarding Itauna, the Itauna well was not the bulk of the value there in -- the Itauna discovery's not the bulk of the value on our Brazilian assets. The 2 pre-salt discoveries are where the bulk of the value is. The Itauna well, we P&A-ed it. We had some hydrocarbons in the lower zone. The main objective for the appraisal section was wet, and so we're going to roll that new data into our interpretations there on 29 and see what it tells us. But really, the bulk of the value's always been in the pre-salt.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Great. I understand the sensitivities around Algeria, Jim, but I'm guessing we'd all kind of expected some news from the arbitration panel by year end. I'm just wondering if you can give us an update if whether or not you still believe you have a good -- you're in a good position there? And if so, when we're likely to hear something? And I'll leave it there.

James T. Hackett

Absolutely, Doug, and I understand that. We would've loved to have had a resolution of that here for you today, but it's not a court of law where we have a specific time for the decision. It's an arbitration panel, and so we still feel it's imminent. We will update you, obviously, immediately once we have some results on that. And I think it's upside for our investors, if we're successful.

Operator

Our next question comes from the line of Subash Chandra of Jefferies.

Subash Chandra - Jefferies & Company, Inc., Research Division

Was curious, Jim, if you thought this was the year that you see Gulf of Mexico volumes either stabilizing? And if it's possible that even this year -- later this year, that you see Gulf beginning to reverse?

James T. Hackett

Yes. I do think that within the next 2 to 3 years for the industry as a whole end up being back to pre-moratorium levels with much longer -- with meaningfully longer lead times between actually trying to get a well ready to be drilled and getting it permitted. But I think those will all stack up to, where it will be back to previous activity levels. In our particular case, as I mentioned from an exploration perspective, we're definitely going to be back to pre-moratorium levels as a company this year from a development and develocat standpoint that maybe a little slower still for us as well. But I do think the signs are very positive, and we're taking advantage of that with the drilling activity we see for this year.

Subash Chandra - Jefferies & Company, Inc., Research Division

And Jim, you say pre-moratorium levels. Is that in terms of activity or in terms of net volumes?

James T. Hackett

No, it's in terms of drilling activity. As you know, Independence Hub is on a decline, so we're overcoming that.

Subash Chandra - Jefferies & Company, Inc., Research Division

Right, okay. And do you think the net volumes achieved a sort of a sort of flat line at some point this year?

James T. Hackett

Well, if you look out -- the industry suffered a very significant decline in production during this moratorium followed by the pre-moratorium. And I'm not sure that the industry as a whole could catch back up to the pre-moratorium levels, but just because of the significance of decline. I think in Anadarko's case, with the placing Caesar/Tonga on production, we should see a very nice bump toward midyear this year and that'll make up a fair share of the loss that we've had during this moratorium period.

Subash Chandra - Jefferies & Company, Inc., Research Division

Okay. And a final one. Jim, I think you mentioned the 25%, 35% debt ratio target, asset sales and execution. So on the asset sales, I suspect Brazil is the most significant part of that. Are there -- is there anything else proposed for sale?

Robert G. Gwin

Yes, this is Bob Gwin. We've just begun marketing our Indonesian assets. That's something that we'll be working on here in the coming months. In addition, although it's relatively small, little less than a couple of hundred million dollars, we've recently signed a couple of PSAs for the -- some sale of some gas properties in South Texas. There's always things that we're doing within the portfolio that don't rise to really what I call level of materiality, but in the aggregate, they add up over the course of the year that we continue to work on.

Operator

Our next question comes from the line of Joe Allman of JPMorgan.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Jim, in terms of the Tronox litigation, could you describe why you're confident about your position?

James T. Hackett

I might have Bobby Reeves do that, if you don't mind.

Robert K. Reeves

Joe, good morning. Look, this is a case that has some very unusual claims, and we believe it's pretty simple as to what the law provides. And we're confident that the testimony, when presented to the court, will go in our favor. We're involved in reviewing the expert testimony through depositions right now. We still have a lot to go before trial with some motion practice and what have you. But we're confident about our case. But as Jim said, anytime you have a complicated case like that, it makes sense for the parties to look at potential resolution, and that's what we're doing in mediation. And that's what this chart relates to.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay, that's helpful. And then just a separate topic. I was struck by looking at your operations report at the growth in natural gas in a couple of areas, in particular, East Texas, Haynesville and Pinedale. So could you describe what's really driving the growth in those 2 areas?

Robert G. Gwin

Joe, in East Texas, we're in a unique position in Panola, Anderson County areas, where our Cotton Valley and Haynesville production has some liquids associated with -- primarily in our Cotton Valley production. We're starting to drill horizontal wells, seeing very good results in our old properties like the Southeast Carthage and Central Carthage JV. So we've just taken on a horizontal program with 5 or 6 rigs to knock out those opportunities and have good economics. They're reasonably liquids rich, and we have good contracts in the areas, we got good net backs, and the combination of all that adds good economics to our system.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay. And are you targeting the -- what [indiscernible] there in the Cotton Valley?

Robert G. Gwin

It's just the Cotton Valley section that we're working through.

James T. Hackett

And again, Joe, it's liquids-oriented. We don't plan to add rigs per dry gas drilling. We might be going the other direction, in fact.

Operator

Our next question comes from the line of David Heikkinen from Tudor, Pickering, Holt.

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

Jim, that was actually a perfect segue for my questions. As you think about going the other direction with low natural gas prices, the only area that you were really drilling dry gas was the Marcellus. You've had a couple of -- your completing in the Utica. Can you talk about that region in general, as far as activity levels for 2012, and what that means from a capital spending as well?

Charles A. Meloy

David, this is Chuck. We really haven't finalized our 2012 activity yet. But our company op activity's been around 7 rigs in the Marcellus, so -- and Chesapeake's drilling 12 to 13 rigs in our JV area. They -- as you've seen in the press, they've mentioned they're moving down on their rig count. We're using our rigs -- we're going back and forth to the Utica to drill wells with those rigs. And if we have a better liquids-rich opportunity for those rigs, we'll take advantage of it. And the economics we still see in the Marcellus are good. We're in a very high-delivery, high-value area. And we'll need an opportunity to substitute amount. Within the event we can come across that opportunity, we will.

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

Okay. And then just generally speaking, as you think about 2012 production and CapEx, can you give it just a red box, higher or lower than 2011?

James T. Hackett

I think what we can say on the CapEx piece of it is just that we are still committed to staying within cash flow. As you look at the current strip prices, Dave, we should be underneath that. And we'll give you more details around that when we get to the March investor conference.

Operator

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

David R. Tameron - Wells Fargo Securities, LLC, Research Division

A couple of things. Let me go back to Mr. Heikkinen's question real quick. In the last couple of years, your production growth has been at single-digit 5% to 6% kind of guidance. Is that -- can you -- to take David's term, can you red box it any more than that? I mean, is that, generally, what we should be looking for?

R. A. Walker

David, this is Al. I think you can expect that's a reasonable assumption. I think, we project at 7% to 9% compound at over a 5-year period. But in any given year, we may be below that 7% to 9%. You've seen 6% in some recent years for us. As you think about CapEx for us next year, just to come back to Jim's comment, in addition to saying that we think in the current strip we're going to be cash flow positive, you can expect that capital number to be below 7%. So as we think about growth, as it relates to our spend next year, we've got a lot of things of which production growth would be a part of the equation. But I don't think we're married to having to deliver 7% to 9% growth in any given year, if we, in fact, don't see good wellhead economics. And in the current world, where we've got $3 or less gas, we're not going to pursue production growth where we don't think we have good wellhead economics.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

No. I appreciate that, that's helpful. And then whoever wants to take this. Asset sales, you mentioned potentially looking at other things to divest, what any -- can you give us any indications there what should we be looking at?

Robert G. Gwin

This is Bob, David. Really at this stage, we can't -- we will expect to get bids in -- here on Brazil. Now that the appraisal wells have been drilled, we'll expect bids here in the coming weeks. And if any of them are attractive, obviously, we expect to pursue a sale there. And if they're not, as you know, we managed the portfolio fairly aggressively, understand where we can make the most money and where assets fit into our multiyear growth plans for production and reserves. And we continually evaluate that, and we'll continue to do so. I think by the investor conference, we'll have some clarity around Brazil, certainly, and it will enable us to speak in a little more definitive terms about direction for the balance of the year.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay. One more. And I don't believe it was any of you -- but somebody made -- from Anadarko, made some comments about -- I think it came on the international side, but made comments about the CFTC and potential margin requirement and the impact that will have on producers, given that there's a decision, apparently, coming in the next couple of weeks. Can you – can anybody there address that? And kind of your stance on that? What impact do you think it'll have on the industry?

A. Scott Moore

This is Scott Moore. Our comments are more just hypothetical for any producer. If you have to collateralize your derivatives position, that cash flow's got to come out somewhere. And so that's a concern of the industry. That regulators are trying to protect consumers taking capital off producers' pockets, it isn't really going to help consumers.

James T. Hackett

We've been weighing in on that politically through several different associations, and we'll continue to try to do that. We'll see where it ends up. But we feel good about the relative cash flow CapEx dynamic for our company, as we mentioned, for this year. And I presume for future years that we don't have to live outside of cash flow, and therefore, some of this is a bit of a -- we've done hedging tactically, not long term. And if we didn't have as much of that accessible to us, it wouldn't be the worst thing in the world. But we still think it's important for the commodities side of the business to be active for the industry, and so we'll continue to fight for the right answers there.

Operator

Our next question comes from the line of Joe Magner of Macquarie Capital.

Joseph Patrick Magner - Macquarie Research

Just a few follow-up questions. In the Wattenberg field, the 11 horizontal wells are online. Can you give us a breakdown of how many of those are Codell versus Niobrara wells? And any comments on how the performance between those 2 Horizons varies?

James T. Hackett

Yes. In the original 11 wells, I think 9 of them were Niobrara wells and 2 of them are Codell wells. The performance we've seen between the 2 reservoirs are very similar, they're outstanding. That's part of the reason why your starting to see our growth in liquids anywhere up 10% year-over-year and fair share that's coming from Wattenberg. If you look quarter-to-quarter, we continue to see growth in Wattenberg. We're now approaching 80,000 barrels a day in production from the field, which roughly half of it's -- well, half of it's liquids. And the target lines that we're picking in both the Codell and Niobrara, we're starting to hone in on the various parts of the field. It has better production characteristics from each and then targeting that interval.

Joseph Patrick Magner - Macquarie Research

And then speaking about that area, outside of the Wattenberg, how does your sort of testing program -- how the results of that looking in southeastern Wyoming and just north of the Wattenberg in Colorado? Any recent results to speak to?

James T. Hackett

Well, we continue our program. We slowed it down. We're now running 2 rigs between the Powder River basin and the Greater DJ. And we've had mixed results originally. They're improving with time. We're now focused more on the Niobrara, Codell section in the Greater DJ and working a number of horizons in the Powder River Basin, including the Sussex, the Shannon, the Mowry and other intervals. We have the great advantage of having that large mineral position in the Greater DJ, which gives us access to more data and as well as having offset information from other industry players. So we're just soaking it all in and putting together our plans for execution in the future.

Joseph Patrick Magner - Macquarie Research

Okay. And then going back to a couple of the recent questions. Over time, if you are able to live within cash flow, you mentioned that you'd like to get to the 25% to 35% debt-to-cap range this year. What would your priorities be for free cash flow over time?

James T. Hackett

Well, I mean, obviously, we are currently rated BBB- from a credit perspective. If we were towards the lower end of that 25% range, we'd probably, I would expect to be a stronger credit quality. And we've got lots of places to go and invest capital. It's our strategic approach to live within cash flow, because we think it's appropriate to have that discipline. But with all the exploration success that we've had over time, there's lots of growth potential in this company to the extent we had additional free cash flow, I think you could expect us to push on that accelerator a little bit and drive toward marginally higher growth rates, still staying true to that capital structure.

Operator

Our next question comes from the line of Scott Hanold of RBC Capital Markets.

Scott Hanold - RBC Capital Markets, LLC, Research Division

In the Gulf of Mexico, so Independence Hub's running around 4.25 right now gross. Is that about where it's at right now? And with Cheyenne East, where does that get gross production back up to?

Robert K. Reeves

Well, it was running 4.25 in the fourth quarter. It's actually, currently running more on a 3.75 range, with 1 additional well we'd watered out during the course of the fourth quarter. And what we see with Cheyenne East is taking us back up to that 4.25 range. The well was drilled last year. It's now being completed and will be put online before the end of this quarter and you should see our volumes climb back up accordingly.

Scott Hanold - RBC Capital Markets, LLC, Research Division

And are you doing other drilling on Cheyenne East? Or does gas prices sort of impact your thoughts of trying to grow that back to sort of max capacity?

Charles A. Meloy

We don't -- at these gas prices, we certainly don't see further investment in Independence Hub. We have a lot of opportunity out there. There's a number of prospects that we can take advantage of, but it will take higher gas prices in these. Frankly, we'll want to use our rig resources and assets to expand our oil portfolio in the Gulf of Mexico, including Heidelberg, Shenandoah, Spartacus, those types of prospects. And those are all coming this year.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. And into the Niobrara, Wattenberg area, you seem to have provided, an inordinate amount of emphasis operational update as well as your prepared comments. I mean, are you guys kind of leading into potentially looking at finding a JV partner, some sort of monetization here? Just kind of the thoughts around the emphasis on that area.

Charles A. Meloy

I think, the emphasis is associated with great performance, feel there is just fantastic force -- we continue to grow like we talked about earlier. And the wells that we have in that area have performed very well, with EURs from 300,000 to 600,000 barrels for less than $5 million wells. And so the economics are fantastic. I don't see us doing a JV in Wattenberg proper for quite some time, as we accelerate our production profile out there. And it's better than 50% liquids in all areas and 70% in the areas we're focusing on. So I think you'll see us continue to invest in that and continue to drill our volumes as we indicated in our release several months ago.

James T. Hackett

It's got short-dated cash cycling, and we've de-risked it, so it's not an ideal candidate in any case, even for investors. I think the areas outside of that, where you would look harder.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay, okay. And is that something that, I mean, should be a 2012 type of event? It sounds like you scaled on the drilling outside of the Wattenberg proper, but we're do you go from here?

Charles A. Meloy

It's scaled around the proper from Wattenberg. We just moved our rigs into the field, where the economics have been fantastic.

Operator

Our next question comes from the line of David Kistler of Simmons & Company.

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

Real quickly, following up on the Niobrara a little bit and just generally your liquids growth. If you kind of keep that trajectory of 10% liquids growth year-over-year, can you talk a little bit about what your bigger picture is for the liquids pricing environment in the States? And then, obviously, you have the infrastructure in Wattenberg to deliver the growth. Can you talk a little bit about what the Eagleford and Permian look like for you guys on liquid's levered growth?

A. Scott Moore

We, as far as the liquids pricing environment, have been experiencing, obviously, very strong recent pricing relative to WTI. That's been, in part due to the fact that your downstream markets connect to global waterborne Brent pricing as well as extremely strong petrochemical demand. And we think on a go-forward, long-term basis, that U.S. petrochemical consumption will remain very strong and that global oil pricing will remain strong. So we like that aspect of the market for us.

Charles A. Meloy

And we continue to make infrastructure improvements in South Texas, et cetera. And the objective is, as Scott mentioned, is to get as much to places we like to market from, whether or not we control that infrastructure. And we've done a lot of work in that area, making sure that we are able to keep pace with our production growth. And I think it's worked pretty well.

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

Great. And then maybe digging in into Bone Springs a little bit, can you talk to us a little bit about the well cost and well designs that generated the IPs that you released in your ops update?

A. Scott Moore

Sure. The Bone Spring play courses out the Permian Basin -- Western Permian Basin. We currently have 4 operated rigs and 4 non-operated rigs on average running in that area. Our current production now is approaching 22,000 barrels on a gross basis of oil and about an equivalent amount of gas. Our well designs are into the Bone Spring's, the horizontal wells, 5,000-foot laterals. They've been running us between $6 million and $7 million apiece, and we've been looking at EURs in and around 400,000 barrels equivalent from the wells. Most of which, of course, is oil. And it's very rich gas so we have a good NGL stream coming off of gas. And the economics are strong, and we've been frac-ing with 12 to 15 stages on average, and we're just having great results. Our execution has been good. Our well cost have been coming down. Our drill times have been coming down. Our cycle times on our completions have been coming down. And so we're just now starting to get into what I would refer to as a manufacturing mode, and we're doing additional pad drilling and density drilling in various sections. So our economics are actually improving.

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

Great. And then maybe just one question on Mozambique. In the past, you guys talked about finding a partner to build and market the LNG there. What's the latest thoughts, given kind of your resource potential and the size of the play at this point?

A. Scott Moore

This is Al. I think you can continue to expect that's part of the algorithm for us. The timing of it could, in fact, as I've indicated in the past be post FID. On the other hand, I'm not opposed to and we're not opposed to seeing something pre-FID if we something real attractive. So I would say just so that one's on a coming attraction basis, the trailer looks pretty good, and I'd stick around for the movie.

Operator

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

Brian Singer - Goldman Sachs Group Inc., Research Division

A couple of questions. First, on Ghana. Can you talk to where you see the production trajectory heading first over the course of this year as some of the Phase 1 sidetracks you referenced come on and then where you see production relative to the 120,000 barrel, the capacity ones, when it comes on, which I guess, would be essentially at full by the end of this year?

Charles A. Meloy

Yes, Brian. This is Chuck. I think the information Tullow's put out is along our expectations. What they intend to do is sidetrack 3 additional wells that were drilled in Phase I. The first of which was the J7. Production permit looks good, it's strong. We're ramping it up. It's over 5,000 barrels a day, and they're going very slow with the ramp up, doing lots of reservoir testing, trying to figure out what we're -- what's actually happening in the reservoir, with regard to the plugging of the gravel pack screens. I think all of the testing, the date, both pressure and production testing and reservoir modeling and the fact that we're seeing no pressure depletion of any significance anywhere in the field in fact, we're seeing pressure build and a good share of the field is evidence that this is a mechanical problem associated with our screens. The sidetrack should take that into account and repair that problem by just essentially opening up the screens, so these small fines can flow through. I mean, we'll catch them on the FPSO. And then later in the year, we're starting Phase 1a drilling and that's 5 producers and 3 injectors. The combination of all that work should build back volume. And what we're going to have to do during the interim is within the field, is as we drill on a drill center, shut in some production around that drill center to accommodate our drilling plans. So what we weren't seeing is a steady climb -- but 70,000 to 90,000 barrels per day in 2012, and then pushing upwards from that in 2013 once the work is completed. And I think that's a reasonable expectation particularly given the success of our J7 sidetrack and sorting out this field problem.

James T. Hackett

I presume you got from that, that the reservoir still, looks really good.

Brian Singer - Goldman Sachs Group Inc., Research Division

Yes, that's helpful. And then in some of the earlier questions, you kind of talked around -- well, Independence Hub need gas prices to be higher. And Marcellus Shale will be great if gas prices were higher. Can -- when you think about capital allocation, can you talk to what gas price it would take, given all the opportunities you have in your portfolio for you to allocate more capital to some of the dryer gas drilling in the Marcellus and the Haynesville and Independence Hub or other parts of your on-shore portfolio?

A. Scott Moore

Higher. Brian, this is Al. I think as you can probably appreciate, it's vary basin-specific. It's play-specific, the types of things we need to see in gas price for drilling a deepwater well in the Gulf of Mexico to produce through Independence Hub would be very different for the same economic equation in the Marcellus. And also, gas price discoveries we're continuing to see that basis is changing in the Marcellus from where it used to be relative to Henry Hub. So I think we're monitoring those pretty darn closely. I think today, like many of our industry peers, and certainly, you've heard us talk in the past, we are moving more towards oily and liquids-rich opportunities in order to be able to survive a sub-$3 gas world. It's not attractive, and I'd challenge very many places to be able to explain how you get positive wellhead economics at sub-$3. So the answer is just simply higher, it's going to be better, but is very basin-, very play-specific. And I think in our case, given the portfolio that we've got and the ability to move capital around and not be dependent upon 1 or 2 types of plays or being overly dependent upon natural gas as a hydrocarbon product, you can see in our results that we've been trying where we can to move to more liquids and more oil opportunities. And I think you should just expect that will continue to occur. And hopefully, at some point, industry will start to see some balance between supply and demand and see a move back up to curve.

James T. Hackett

And Brian, this is Jim. There's a lot of flexibility there to go back to gas if we need to. But I might remind you, we started this process in '09. We haven't really changed since then. And prices have been far in excess of $4 a decatherm during that period. And so our view, as Al mentioned, is the relative oil economics are still so attractive that you still need to have gas come up a fair degree, before we'd start reallocating capital to gas. That's unlike some of our peers perhaps because of the flexibility that's inherent in the portfolio. But we have a lot of flexibility to go back to that when and if the -- if cash flow support it, we think the economics do.

Operator

Our next question comes from the line of John Malone of Global Hunters.

John Malone - Global Hunter Securities, LLC, Research Division

Just a couple of follow-ups on Africa. Can you give us some idea on timing on the 2 wells you've got on Cote d'Ivoire, which you're targeting there? And also, it looks pretty clear that the TEN complex in Ghana is probably going to get an FPSO dedicated to it. What's the timing on West Cape Three Points? And when do you think you'll make a decision on a standalone development there?

Robert P. Daniels

This is Bob. I'll start with the Cote d'Ivoire drilling, and then I'll ask Chuck to take over on the sanctioning. On the Cote d'Ivoire drilling, we're drilling a Kosrou right now. And the target there is the same as what we've been looking for in the West African margin. It's a Jubilee look-alike sands, Cretaceous-age fan systems. We think that we've got some good prospects there in Cote d'Ivoire with Kosrou and then followed on by Paon. So we'll see what we find in there. I’d say that timing on Kosrou is that -- it's got a couple of months to go. I mean, we're just getting underway. We've top set both of them, and now we're back on Kosrou getting ready to really start the drilling. And I'd expect maybe end of the quarter results on it, and then moving into Pond. We also announced last week -- or signed last week 2 additional blocks in Cote d'Ivoire adjacent to our CL 105 block (sic) [CI 105] that we're going to be the operator of. So we do think there's a lot of potential in Cote d'Ivoire, and we're setting ourselves up for success with the additional acreage acquisition. With the TEN complex, we've got a lot of activity going out there. And that's all driven towards getting enough information for the sanction. And as Chuck mentioned, that's supposed to happen this year. And I'll let them go on to what he sees in the West Cape Three Points. We have quite a bit of activity there from an exploratory appraisal standpoint. Both the Akasa and Teak areas need some additional appraisal work. But Chuck, let you on with the sanctioning.

Charles A. Meloy

I'll just go back for a second to the TEN complex. We're expecting fee [ph] to be completed in the third quarter as Tullow has indicated. I think we'll make a proposal to the government of Ghana and the actual sanction be dependent upon when they approve that plan of development. We're hopeful it will be this year. And if you skip over the West Cape Three Points, we're evaluating really 2 outcomes: one is a standalone development between Teak, Akasa, Mahogany East, putting all that together in one large facility, probably another FPSO, which we are evaluating in a fleet process today. And the other option would, of course, be tying each individual field back to Jubilee and staged fashion. And the economics of those are being evaluated, and all that's underway. We hope to conclude that work again by the end of this year, propose it to the government of Ghana, GNPC, and have a decision sometime either late this year or next year depending upon when their approval process concludes.

Joseph Patrick Magner - Macquarie Research

Okay. And just a quick detail too. Can you confirm, you said there's 3 sidetracks to Jubilee? Is that 3 in addition to J7? Or is it J7 and another pair?

Charles A. Meloy

It's J7 and 3 more.

Operator

Our next question comes from the line of Bob Brackett of Bernstein Research.

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

I had 2 quick questions. One's a follow-up. I didn't hear the answer on Pinedale/Jonah, why those volumes seem to up 60% year-on-year for the fourth quarter?

John M. Colglazier

Yes, Bob, this is Colglazier. Pinedale/Jonah’s a field we have a less than a 10% interest in, so we're really at the mercy of when we receive information from the operator. So it's just -- as we get the info in and this happened to be a good quarter.

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

Okay. And then the other would be on the Haynesville. I take it that, given you've got 5 rigs in East Texas Haynesville chasing liquids, you've got no rigs in the Haynesville. So you guys have a nice little laboratory of what Haynesville production looks like when you stop. Can you talk about decline rates out there that you've experienced?

Charles A. Meloy

Not really. We're early in a program out there. We've drilled very few Haynesville wells. We didn’t participate in the big rush a few years ago when -- if we look at the dry gas Haynesville, we see it as being breakeven and best right now. And we don't have a lot of information you might ask those that have large Haynesville position.

Operator

Our next question comes from the line of Michael Hall of Robert W. Baird.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

Just a quick follow up on the question around liquids earlier in terms of U.S. liquids. I'm just curious if there's any, let's say, basin-specific kind of commentary you might make around any potential kind of tightness this year? Any bottlenecks you're seeing on the processing side, at least on a relative basis? And if you see any potential for varying kind of differentials on a liquids basis this year and any of the pieces of the U.S. portfolio?

R. A. Walker

I think the key for us is making sure that our liquids reach Belvieu pricing. And about 70% of our liquids are sold directly in that price and other 10% are sold in local markets would have to be better. So congestion would only impact us for 20% out of Conway, which is why we partnered with Enterprise on the Texas Express project to help debottleneck that part of the grid. I think, in general, we're pretty careful to pay attention and make sure that our downstream takeaway matches our processing agreements and are comfortable with our position.

Operator

Our next question comes from the line of Subash Chandra of Jefferies.

Subash Chandra - Jefferies & Company, Inc., Research Division

Just a follow up on the reserves' big year for PDP adds. Curious if there were any standout projects that made it into the PDP column? Anything specific?

R. A. Walker

Yes, Subash. And we don't really share the field-by-field level detail on that. We may give a little bit more on a country level when we do our 10-K, but other than that, we'll just not talk about it.

Subash Chandra - Jefferies & Company, Inc., Research Division

Got it. And then final one, the Indonesian asset sale, any sort of number we can use as a framework for expected proceeds?

James T. Hackett

No, not at this stage. It's too preliminary. You guys have seen the results around the assets we've announced with the discovery and some of the other activity. And as we move into data room process, we'll start to get some greater clarity as to how the market sees the value of the asset.

Operator

[Operator Instructions] Our next question comes from the line of Ross Payne of Wells Fargo.

John M. Colglazier

I guess, Ross isn't there, operator. Are there any more questions?

Operator

No, sir. With no further questions, I would like to turn the call over to Mr. Jim Hackett for closing remarks.

James T. Hackett

Great, thank you. Appreciate everybody being on the call today. We look forward to seeing you at our investor conference in March and hope you have a good day. Bye.

Operator

Ladies and gentlemen, that concludes today's conference. Thank you for your participation. You may disconnect at this time. Have a great day.

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