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Executives

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

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

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

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

Charles A. Meloy - Senior Vice President of Worldwide Operations

R. A. Walker - President and Chief Operating Officer

Robert P. Daniels - Senior Vice President of Worldwide Exploration

Analysts

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

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Brian Singer - Goldman Sachs Group Inc., Research Division

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

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

Scott Hanold - RBC Capital Markets, LLC, Research Division

Evan Calio - Morgan Stanley, Research Division

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

John Malone - Global Hunter Securities, LLC, Research Division

Robert L. Christensen - The Buckingham Research Group Incorporated

S. Ross Payne - Wells Fargo Securities, LLC, Research Division

Eliot Javanmardi - Capital One Southcoast, Inc., Research Division

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

Anadarko Petroleum (APC) Q1 2012 Earnings Call May 1, 2012 10:00 AM ET

Operator

Good day, ladies and gentlemen, and welcome to the First Quarter 2012 Anadarko Petroleum Earnings Conference Call. My name is Jeff, and I'll be your coordinator 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. Please proceed, sir.

John M. Colglazier

Well, thank you, Jeff. Good morning, everyone. I'm glad you could join us today for Anadarko's first quarter conference call. I'll remind you that today's presentation contains our best and most reasonable estimates and information. However, a number of factors could cause actual results to differ materially from what we discuss today. 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. And as we do each quarter, we've included additional information in our quarterly operations report that is available on our website.

With that, I'll turn the call over to Jim Hackett, our Chairman and CEO, who will discuss our first quarter results here in a second. Jim is joined by other members of the executive management team who will be available to answer questions later in the call. Jim?

James T. Hackett

Thanks, John, and good morning, everyone. We'll keep our prepared remarks brief this morning since it was only a few weeks ago when we hosted our investor conference here in the Woodlands. During the conference, we shared an in-depth look at our portfolio and it's embedded value-creation opportunities. So this morning, we'll focus on some of the major achievements during the quarter, which include that we reported record daily sales volumes, delivered first oil at Caesar/Tonga, generated strong discretionary in free cash flow, experienced continued success in our exploration program, demonstrated outstanding flow rates with drillstem test in Ghana and Mozambique and finalized a mutually beneficial resolution of the Algerian tax dispute.

Focusing first upon Anadarko's operational performance, we achieved record daily sales volumes of 704,000 barrels of oil equivalent per day during the quarter. With liquids volumes surpassing 300,000 barrels per day for the first time, it's worth noting that approximately 75% of these record liquids volumes were comprised of oil. Underpinning the increase in liquids volumes were both our U.S. onshore growth plays and the start up of the Caesar/Tonga mega project in the Gulf of Mexico.

At our March investor conference, we highlighted 5 major U.S. onshore liquids-rich growth plays: Wattenberg, Eagleford, Permian, East Texas Horizontal and Greater Natural Buttes. During the quarter, we increased liquids production in these areas by approximately 27,000 barrels of oil per day, representing a 50% increase year-over-year. This liquids growth was primarily driven by the Wattenberg and Eagleford assets, each of which continues to demonstrate excellent returns on capital. The Wattenberg field sales volumes averaged more than 80,000 barrels of oil equivalent per day in the quarter, while delivering a 12,000-barrel per day increase in liquids volumes compared to the first quarter of 2011. We are continuing to accelerate our horizontal drilling activity in this play as we expect to add additional rigs over the coming months.

Moving to South Texas, we're currently running 10 rigs in the liquids-rich Eagleford Shale. During the first quarter, we achieved 55% year-over-year growth in our net liquid sales volumes in this play. Keep in mind this production growth and our returns on capital are even stronger considering the $1.6 billion joint venture we executed between last year and this year with KNOC.

In Ohio, we're encouraged by the early results of our 3 producing wells in Utica Shale, where the most recent well has delivered more than a 13,000 barrels of light gravity oil through the first 30 days. We're continuing an active 2012 program in Ohio as we work to further evaluate a larger area in the prospective liquids-rich window covering approximately 390,000 gross acres.

In responding to the current weak natural gas price environment, we are planning rig reductions in the Marcellus Shale and Greater Natural Buttes assets and are evaluating opportunities to direct some of those rigs to areas like the Wattenberg Field that offer exceptional liquids-related returns.

As production continues to increase in these major growth plays, we are simultaneously ensuring our ability to extract maximum value through expanded infrastructure and access to premium markets. This includes our announced participation of the front range in Texas Express pipelines that will carry NGLs from the Rockies and West Texas to Mont Belvieu. It also includes our operated Chipeta Train III cryogenic expansion in Greater Natural Buttes, which will increase our net NGL sales volumes by more than 7,000 barrels per day, as well as construction of the Brasada, Lancaster and Bone Spring natural gas processing plants and securing numerous processing and takeaway arrangements in other geographic areas.

Turning to the Deepwater Gulf of Mexico, we brought Caesar/Tonga on line during the quarter and safely and rapidly ramped up production from 3 wells to more than 45,000 thousand barrels of oil equivalent per day. The partnership plans to drill and complete a fourth well later this year there.

In sanctioning the Lucius project in the Gulf of Mexico late last year, we've made good progress fabricating the whole of the spar and constructing the topsides of the facility. Later this year, we're planning to initiate development drilling in the Lucius field and are on pace for first production during the second half of 2014. We recently spud Spartacus, a Gulf of Mexico exploration prospect that is targeting sub-salt Pliocene sands similar to those encountered at Lucius. In addition, the Vito prospect is currently drilling below salt to further appraise this middle-Miocene discovery.

During the quarter, we announced the successful appraisal well in the Heidelberg field, coupled with the successful down-dip sidetrack announced in April, has provided additional confidence in the 200 million-barrel-plus resource estimates here.

Moving to our international projects, offshore Mozambique, we announced successful appraisal wells at Lagosta-2 and Lagosta-3 during the quarter and a successful drillstem test at Barquentine-2, which flowed at equipment-constrained rates of 100 million cubic feet per day. Since that time, we've successfully conducted another DST at Barquentine-1 that tested a deeper Oligocene sand formation and also flowed at facility-constrained rates of approximately 100 million cubic feet per day.

These flow tests demonstrated strong connectivity and productivity within the reservoirs. These are characteristics which should lead to fewer subsea wells and, therefore, significant cost savings in project development.

The successful Barquentine-4 well completed our appraisal drilling program in the Prosperidade area, and we have restarted our exploration program which will include drilling in the Golfinho, Atum and Orca prospects in the North before moving to the southern portion of the block for up to 2 exploration wells there.

Offshore Ghana and Ntomme-2A and Enyenra-4A appraisal wells both encountered oil, which significantly enhanced the value of the TEN, the Tweneboa, Enyenra and Ntomme complex, and expanded its areal extent. We also conducted successful drillstem tests at multiple zones at the Owo discovery well, which floated combined equipment-constrained rates exceeding 20,000 barrels of oil per day. Partnership is continuing an active program at the Deepwater Tano Block and working to submit a plan of development for the TEN complex this year.

Further West, offshore Sierra Leone, as previously reported, Anadarko and its partners encountered hydrocarbon pay at the Jupiter-1 prospect. And in April, the company announced that the appraisal well at Mercury-2 encountered water-bearing reservoirs. As expected, we're incorporating the data from both wells into our models as we evaluate further drilling plans in offshore Sierra Leone. In Côte d'Ivoire, we are currently drilling the pond prospect and we'll report on the results for the second quarter conference call.

Turning to the financial results for the quarter, we reported earnings of $4.28 per diluted share and have provided a breakout in the earnings release of items affecting comparability, the most notable of which are the $1.8 billion related to resolution of the Algerian tax dispute and a noncash charge of $275 million associated with Tronox adversary proceeding.

Excluding the items affecting comparability, first quarter net income would have been about $0.92 per diluted share. While we remain confident in the merits of our position regarding Tronox, we also recognize there's value in removing uncertainty for our shareholders. Therefore, we continue attempts to resolve this issue. And as a result, we have recorded a loss contingency of $525 million associated with the adversarial proceedings. If a settlement is not reached, we are prepared to go to trial in mid-May and will vigorously defend our interest.

As I mentioned at the beginning of the call, we generated strong cash flow, discretionary cash flow, of more than $1.9 billion during the first quarter. Free cash flow totaled more than $130 million, which includes the impact of $98 million in consolidated capital expenditures by Western Gas Partners, our midstream MLP. As a result of these strong results, we ended the quarter with approximately $3 billion of cash on hand.

During the quarter, Moody's Investors Service returned our senior unsecured rating to investment grade to Baa3 with a stable outlook. Also, we retired $131 million of debt during the quarter and reduced our net debt-to-capital ratio to 38% compared to 41% at year end 2011.

We see a clear path to our targeted net debt-to-capital range of 25% to 35% by the end of the year, with anticipated strong operating cash flows and income generation, including significant value from the Algerian tax resolution.

In March, we announced an agreement with Sonatrach that resolved the issues surrounding the implementation of Algeria's 2006 exceptional profits tax. The resolution preserves our long-standing relationship with Sonatrach and also returned significant value to Anadarko.

There are 2 parts to this resolution. The first part provides for a benefit of approximately $1.8 billion to be received over a period of 12 months, and this was fully recognized in our earnings during the quarter. In terms of cash, we expect to receive about $1 billion of this amount during 2012 and the remainder in the first half of 2013. The second aspect of the resolution is an amendment to the production sharing agreement which will provide additional sales volumes estimated to be 1.6 million barrels in 2012 alone and an additional 5 million barrels during 2013. The impacts of the resolution have been included in the updated guidance attached to our earnings release, as well as in the Algerian guidance model on our website.

Also, we recently closed under the divestiture of our South Texas dry gas assets mentioned at the investor conference, and we soon expect to close a sale of our Pompano asset located in the Deepwater Gulf of Mexico. We also finalized the joint venture agreement where we assigned 23% of our working interest in our enhanced oil recovery development at the Salt Creek field in Wyoming in exchange for our JV partner funding to $400 million of future development cost. This transition was identified during the investor conference as well.

As we were evaluating bids for our Brazil assets, we received notice of a potential unitization of our Itaipu Field with already producing Petrobras-operated Whale Park pre-salt complex, formerly referred to as Jubarte. Accordingly, we do not expect to announce anything related to the potential divestiture of our Brazil subsidiary in the near future.

To reflect the increased sales associated with the amended PSA in Algeria as well as strong operational performance, we have increased our 2012 sales volumes guidance range by 2 million barrels to 258 million to 262 million barrels of oil equivalent, with no corresponding increase to the 2012 capital investment program. Additional updates to guidance are attached to last night's earnings release.

We believe the results of the first quarter reflect our commitment to delivering capital efficient growth and good returns on capital. Adapting quality to Anadarko's portfolio continues to provide this flexibility to successfully manage through the current market environment and deliver differentiating value to our shareholders.

With that, Jeff, we're happy to take everyone's questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from the line of David Tameron with Wells Fargo.

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

Jim, whoever wants to take this, but can you guys -- can you just step back and give us a snapshot at Tronox? You understand the case, I realize you're in legal proceedings. But whatever you can tell us as far as background, and then I'll just leave it open and see whatever you could share with us would be helpful.

James T. Hackett

Sure. I'd ask Bobby Reeves to do that.

Robert K. Reeves

Good morning, David. Look, there's been a lot of misleading media and other reports out there about the Tronox case. And I should prep this with what I'm about to say, by urging you to look at our 10-K and 10-Q disclosures. But let me see if I can give you a little color about this. The plaintiffs in the Tronox matter is a litigation trust that resulted from the Tronox bankruptcy. And they're alleging a fraudulent conveyance theory under the bankruptcy code. And to break that down a little bit, they're alleging the Kerr-McGee either through an internal corporate reorganization back in 2002 or the subsequent IPO of Tronox, what was originally their chemical business in 2005, somehow attempted to harm creditors, environmental creditors in this case. We really believe that Kerr-McGee's corporate reorganization, an internal corporate reorganization to separate the E&P and chemical businesses in 2002 was conducted for totally legitimate business purposes and was not in any way done with an attempt to harm creditors. I think everybody will also agree that Kerr-McGee made very detailed public disclosures prior to the Tronox and the IPO in 2005 as part of the securities filings, and that allowed the market to really value the company. That resulted in a spinoff of a very solvent, adequately capitalized chemical company to its contingent environmental and toxic tort liabilities were well known and well-disclosed to lenders, investors and the public. Taking all that, we really believe that Tronox's financial problems were not the result of any sort of fraudulent transfer, but rather simply the result of the economic and housing crisis. Yes, that in turn led to the reduced demand for the company's principal product, which at that time was paint pigments. If you don't have housing being built, you don't need paint pigments. Pretty simple in our opinion. Those events were totally unforeseeable at the time of the IPO in 2005 and the spinoff of Tronox from Kerr-McGee. Now if, for some reason, the plaintiffs are successful on their theories, damages could vary depending upon the theory of liability. For example, if the plaintiffs were successful in arguing that the -- somehow the internal corporate reorganization in 2002 was a fraudulent conveyance, then they're damages might be measured in some way by up to the value of the oil and gas assets that were transferred. If they were successful though in somehow claiming that the fraudulent conveyance occurred at the time of the IPO in 2005, then the damages might be measured by the value of what Kerr-McGee got as part of the IPO, which was roughly $800 million. Lots of discretion in our opinion by the judge as -- if he sees liability here, which we don't believe is appropriate, but if he does, how he could award damages and avoid some of the punitive-like numbers you're hearing in the press. It's worth also talking about, David, that the plaintiffs have repeatedly claimed that this is a case about the value of environmental liabilities and toxic tort liabilities. If that's true, then it would be something you need to look at what the plaintiffs' own experts have said are the estimates of those liability at the time of the Tronox IPO in 2005 at somewhere between $1.9 billion and $2 billion, not the $15 billion or more that's being claimed in the media. And as you would expect, our experts have a completely different of those values. A dramatically lower, in our opinion much more realistic. I think as Jim said, earlier, we remain optimistic about our chances of prevailing in the lawsuit. We're going to vigorously defend it, but all litigation has its risk, so we'll continue to look for any reasonable settlement opportunity to remove uncertainties for our shareholders. Trial starts in May, and we look very forward to telling Kerr-McGee's side of the story to counter all of the sensational media reports. It will be the first time that our side of the story is actually told.

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

So Bobby, just following up, so I mean, can you put some parameters on as what you think your liability is?

Robert K. Reeves

I'd love to, David. I think that probably be inappropriate. I think I've given you enough color there that is more than anything. Certainly, we've taken a charge at this time of $525 million, and that's our best estimate at this time.

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

Okay. I had to ask. It's my job to ask. Let me ask one other question outside of that and then I'll jump off. Going back to Algeria, Jim, the 2 million barrels this year, do you guys having a feel for -- or could you give us a feel for what that impact is going to be for 2013? Similar-type number, bigger-type number, as far as production volumes?

Robert G. Gwin

Production -- David, this is Bob Gwin. Production volumes around 5 million barrels is what we're anticipating the impact would be. Jim mentioned the 2 parts here, that's from the revision of the PSA.

Operator

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

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

I've got a couple of questions as well, fellows, if you don't mind. Just a quick follow up on Algeria. The guidance on the tax, leaving aside the settlement volumes, it looks like the tax rate is coming down. But because we've got a full year and only a couple of quarters, I'm not really sure what the run rate is. Can you tell us what your cash tax run rate will be on Algeria going forward for settlement?

John M. Colglazier

Yes, Doug, this is Colglazier. I think the simplest way to do it is to go to our website where we put a pretty robust disclosure on the impacts of the amendment to the production sharing agreement. It's on the IR tab under presentations, off to the right. It's the physical location of it. But to answer your question specifically, we'll get the additional 1.6 million barrels as profit oil this year, another 5 million barrels next year and then you can continue that and decline that with production going forward. On top of that, the implied TPE production tax rate, if you will, will decrease. And this will happen in the third quarter because we're still working through some inventory in the second. But in the third quarter, that will drop from 30%, which is what it's been previously, down to about 18% on a go-forward basis. And then sends it -- I don't want to get in to how tax is treated, but the effective tax rate for Algeria therefore will decline to somewhere between 45% and 50% from the approximate 60% that it is today.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Great. That was the number I was looking for, John. Just 2 further quick ones, hopefully. Caesar/Tonga now is on stream. Can you just remind us what the rationale was between the scale of the production and the size of the resource? Because I understand Constitution is the kind of receiving facility, so to speak. But what's the prognosis for the production platform and would you expect to be able to increase the capacity like Constitution over time? And I have one final follow-up, please.

Charles A. Meloy

Doug, this is Chuck. We currently have 45,000 barrels a day equivalent online, which was our peak expectation for the 3 wells. We intend to drill an additional well this year. And what we've done is we've put our production capacity on Constitution topside. And as Constitution declines, that gives us an opportunity to increase our throughput on Caesar with time. And so we'll play the balancing game there with future wells and ultimately displace Constitution Ticonderoga volumes with the Caesar/Tonga volumes over time. And the timing of that is uncertain right now, but that's coming down the road.

Douglas George Blyth Leggate - BofA Merrill Lynch, Research Division

Okay, great. My final one, and I hate to bring this one up. But strategically, Mozambique -- I mean, we have seen some very substantial value recognized now and confirmed with Cove Energy. And if you look at some -- the long-dated nature of some of the potential LNG volumes there, I'm just curious as to what your thoughts are on whether or not you believe you will also get full recognition by retaining that as an operated project with a very long-dated production profile, and I'll leave it at that.

James T. Hackett

Doug, this is Jim. As you might expect with the value that's being created there and you rightfully referred to in terms of the Cove process, is that we have been approached by a number of companies about their interest in helping us, if you will, in Mozambique. And while we don't talk about specific transactions, that's always available to us. The thing that's very exciting here is that we've got some really great exploration wells still to drill. So that in terms of capturing value, we're still away from the maximum value period. And it's not escaped us that as you get more long-dated in terms of the reserve life, that our investors, as with all of our NAV, would like some of that collapsed forward. So we will clearly keep that in mind. But for right now, we're just thrilled about a validation stamp being put on this in terms of what this is worth, and very excited about the 5 exploration wells we still have to drill this year.

Operator

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

Brian Singer - Goldman Sachs Group Inc., Research Division

On Jubilee in Ghana, you'd highlighted in your ops review the 5 wells that are part of 1A and the sidetracks with the more optimal completions on the phase 1 wells. Can you just give us an update on the timing of the ramp up that you believe when you would expect full facility capacity and then how many 1A wells plus sidetracks that that would entail?

Charles A. Meloy

Brian, this is Chuck. When the Jubilee started -- the outlook for Jubilee started to look up. We're now producing 70,000 barrels a day, and we're excited about the EBITDA that we're seeing out there that's over $100 a barrel. So it's really looking good again. And what we're seeing is -- with the success of the sidetrack that we've had in a couple of asset jobs, that we see our way towards the peak production that was expected previously. We intend to start drilling our phase 1 wells shortly. And they will have a different completion on the one that's taken into account, the learnings of the original completions plus the sidetrack. And we look forward to seeing the production ramp up through 2013. And we'll get a lot of good value out of it with the great returns that we're having on our project.

Brian Singer - Goldman Sachs Group Inc., Research Division

And we should expect that to be gradual beginning in the second quarter just based on the 70,000 versus the 67,000 that was your average for Q1?

Charles A. Meloy

It's going to ramp up a bit in time we drill a few and then complete a few, drill a few and complete. So it's going to be a bit lumpy as we move up. And then we're going to be doing asset jobs in addition to that to try to recover some of the rates that we've lost from the original completions.

Brian Singer - Goldman Sachs Group Inc., Research Division

Great. And then shifting to the Marcellus Shale, production was up nicely quarter-on-quarter. You previously taken up, I think at your Analyst Day, your EUR to 8 Bcf. Can you just characterize your backlog there? And then if we look at the increase in production, how much you would characterize to bringing on backlog versus what you might attribute to improving well performance?

Charles A. Meloy

Brian, this is Chuck again. I'm not sure I could actually give you a percentage of both. But we've had a number of wells, both operated and non-operated, that have been waiting on midstream tie-ins and completions. And that activity is still going on today, particularly our non-opposition in the Chesapeake AMI where we've had a considerable number of wells that have been waiting on just some key infrastructure tie-ins. And that's now occurring and has really built the volumes. Out of the Marcellus, we still have a pretty good backlog in the order of 100-plus wells that could be tied in. And we're -- the thing that we're doing there is really slowing down the rig activity, both non-op and operated, given the wellhead economics that we're seeing and the prices that we're realizing out there. But the machine has been built and it's working and it's delivering some outstanding wells. And we're just looking forward to better realizations at the wellhead.

Operator

Our next question comes from the line of Brian Lively with Tudor, Pickering, Holt.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

A follow up question to the prior question on the Marcellus. So if you -- as you guys take rig count down in the Marcellus, should it be our expectation then that production will continue to grow given the backlog behind pipe production?

Charles A. Meloy

Our expectation, Brian, is for it to continue to grow, not substantially. It's more of an offset to our hub declines as we see the midstream as well as the completions of temporarily abandoned wells come on. So it's a growth pattern just because the wells are so strong, they have such shallow declines, high IPs [ph] and just long plateaus. So the underlying asset will continue to ease up.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And then in the Marcellus, what is the minimum rig that you guys need or want to run at this point given the leasing commitment?

Charles A. Meloy

It's probably in the order of 10. We have leasehold commitments particularly in our non-operated side at Chesapeake we'll continue to operate on. And then we'll be going steadily down to around 4, 5 rigs toward the end of the year, and that should cover us.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay. And then Algeria, maybe this just wasn't clear to me, but the -- what is the sensitivity of the projected cash flows from the additional profit barrels with changing commodity prices? So would your -- my question is would your cash flows change if crude prices were higher or lower than your expectation?

R. A. Walker

Brian, it's Al Walker. I think the short answer to that question is yes. But it doesn't make that particular production unique. They're -- the Sahara Blend is a premium to the Brent, so you're getting further premium to WTI. And so as you look at Algeria going forward, I think you just need to appreciate that we have a very attractive commodity that's being produced at a premium price to Brent, and that therefore it does have some volatility if we see Brent in this particular benchmark here back up or move back towards WTI. But I don't think it's unique in the sense that Algeria is something that -- a place that produces in a way that anything else in our portfolio might not produce the same way. As an example, in China, in the first quarter, you saw us have realizations at the wellhead there approaching $130 a barrel.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Let me ask you differently. I was talking more just on the additional profit barrels. So I guess, say if crude prices drop, would you get more a barrel?

R. A. Walker

Brian, let me ask you this. Are you referring to the settlement barrels for which we are recovering $1.8 billion? Are you talking about the amendment to the production sharing agreement where we have a lower TPE going forward?

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

I'm talking about mainly the additional recoverable barrel, the first part of that.

R. A. Walker

Okay. That $1.8 billion, John described that well, that's a value barrel. So when we recover $1.8 billion, whatever the price environment, we'll deliver barrels related to recovery of that amount. So the barrels really don't matter as much as recovering that the dollar amount of $1.8 billion.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

That's what I was looking for. Because it was my understanding that you're going to still recover it sort of in a barrel fashion, but thanks for the clarification.

R. A. Walker

That's correct. And it will come through future listings over the next 12 months. And John has given you good guidance, I think, on what we anticipate that to be this year or next. And as we -- whatever the price environment is, once we get to that $1.8 billion, then those liftings for the settlement barrels will go away, and we're only dealing with the TPE barrels to be produced going forward.

Operator

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

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

Another shale question. In the East Texas -- well, actually not shales maybe. But East Texas, the horizontal program, what is the gas oil or liquids gas mix in the wells?

Charles A. Meloy

Subash, this is Chuck. The -- there's 2 different plays. One is the Cotton Valley, the other is the Haynesville. They have very similar characteristics. The -- they make some condensate in the order of 10 to 20 barrels of 1 million. And then the big uplift that we have is NGL volumes from both, and they range from 50 to 100 barrels per million.

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

Great, okay. So I guess should we see the dry gas component, the associated gas component of East Texas rise as you drill this program out? Or will that -- or will it be offset by natural declines in the dry gas component?

Charles A. Meloy

Well, I think you're talking about the residual gas after processing. And you should see it rise slightly with time.

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

Okay. In terms of the Gulf of Mexico and completions, you talked about Caesar/Tonga. I guess that's to sort of key production flat. Are there any other completions expected in the Gulf this year?

Charles A. Meloy

We had an additional completion on our Nansen project, number 14. That came on at about 1,500 barrels a day and around 40 million cubic feet a day, which is really heavy liquids once we've separate those out. And then we have a rig program in Marco Polo that is dominated by oil rig completions. And we're also doing work at the Caesar -- at the, I'm sorry, Constitution and Ticonderoga from re-completes and stimulations of those wells.

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

Okay, Constitution and Ticonderoga, got you. And just 2 more if I could. The -- in Mozambique, there's -- the oil area I guess -- will you participate in that license round? Or is your primary focus at this point just going to be the gas that you've identified so far?

Robert P. Daniels

Subash, this is Bob Daniels. We're paying attention to all the licensing rounds up and down the East African coast, Tanzania, Kenya and Mozambique. And if something looks interesting to us, we'll weigh it against what's in our portfolio. Regarding the oil, we think that we still have good potential on the southern portion of our block. And we'll be testing that later in the year with our Barracuda and Black Pearl prospects, which will be on the either side of the Ironclad well that we drilled earlier in the exploration campaign. So we still think we have potential for liquids down in the south, and just excited to get those tested later this year.

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

Do you know the timing of the license round where you have your test on beforehand?

Robert P. Daniels

I don't know the exact timing of when Mozambique is having a license round, but I would anticipate we're going to be ahead of it because we haven't heard a lot about it.

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

Okay, got it. And one final one if I could, on Tronox again. The -- so if I heard correctly, I think there was a -- in characterizing liability, there was a $1.5 billion to $2 billion number you might have quoted as the actual environmental liability that was cited by the plaintiffs. And my question was, if I heard that correctly, how much of that has previously been paid out by Tronox?

Robert K. Reeves

This is Bobby again. Let me clarify, what you heard was plaintiffs' expert reports on value of the environmental contingencies at the time of the Tronox IPO. There -- that's not necessarily the damages that are claimed, but I think it's a good measure for what's really being fought over here as compared to the punitive amounts that are being carried about in the media. I don't have readily available what's been paid in environmental liabilities. There -- the Tronox litigation trust did receive several hundred million as part of the bankruptcy reorganization. And that included some cash and real estate as well. So there were some dollars that they received as part of the Tronox bankruptcy.

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

Okay. And that second settlement, the settlement you've done in the second case, I think, with the debt holders, security holders of Tronox, it looks like it's absolutely a different path than this settlement. But I was curious if there was any sort of relationship here that could be drawn from the other settlement in a different court.

Robert K. Reeves

No, I don't believe so. I think those are totally different claims. Certainly, in relation to the bankruptcy of Tronox, as you would imagine, this sort of class action that would come after such event, the amounts were not material and were totally offset by insurance. So not a big deal there.

Operator

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

Scott Hanold - RBC Capital Markets, LLC, Research Division

In the Gulf of Mexico, you all tied in Cheyene East here recently. So when you look at the Independence Hub, I mean, what should we expect in terms of like production progression here over the next couple of years? And correct me if I'm wrong, but you aren't really drilling anymore gas wells at this point?

Charles A. Meloy

This is Chuck again. We're not currently drilling anymore gas wells around IHUB. The project has done great. It's made over Tcf. It paid out very quickly, and we continue to use that asset base for cash flow as you would expect. We had a very quick tie-in opportunity that we started several years ago in Cheyenne East. And the ball was rolling and the commitments were made, so we went ahead and finished it off. What I see happening out there that the hub is currently making around 400 million a day. And we're going to see the natural declines of those wells. Many of the wells are big wells, 15-plus million a day wells. And as they water out, you see these large declines in a very quick time. And the hub has a life of 2 or 3 years left on the original production and some of the wells like Cheyenne East that we just drilled probably has a 4, 5 year life that you'll see, just the steady natural declines take place. And we have a lot of additional opportunities out there should gas prices recover, but until then, we won't be drilling any additional wells.

James T. Hackett

And all that is reflected in our guidance, which Chuck just spoke to.

Scott Hanold - RBC Capital Markets, LLC, Research Division

So when you look at like a new drill out there, I mean, what gas price makes that economic? Obviously, the hub itself is there. And remind me of the well cost, is it like $50 million to $60 million per well?

Charles A. Meloy

Yes, it's in that order of magnitude. If you add completions, it's a little bit more than that. And so you need some really good gas prices for 30 to 40 Bcf type completions. And today, they're just not there.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay, fair enough. And one other question, just in general on guidance. Obviously, you get about 1.6 million barrels from Algeria. And then you beat the quarter by the midpoint about 2 Bs [ph]. And so it's about 3.6 Bs [ph] -- or I'm sorry, 3.6 MMBOE of your potential upside to your prior guidance, but you raised it by 2. Is some of that related to kind of conservatism given what may happen on the natural gas side?

Charles A. Meloy

Well, Scott, there's 2 things really. The first thing you need to consider is the fact that we're selling properties like South Texas. We did the EUR JV. So that will cut into our production that we've seen. At the same time, our shales and other assets are growing, so you have that benefit. Caesar/Tonga will be online for a full quarter. What we haven't done is really put in a lot -- put the gas volumes through to the future guidance because we continue to believe that these kind of a wellhead prices, you'll see some curtailments through time. You'll see people go back in and resurrect production if it was to have an issue. So we've been fairly conservative with our gas guidance just with the anticipation of a poor wellhead realizations will result in lower production.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Just to clarify one point you mentioned there. So the recent asset sales you had, that was not already in the prior guidance? Is that correct?

Robert G. Gwin

Scott, it's Bob Gwin. It was -- we provided that at the investor conference, the total those 3. The EUR, the Pompano and the South Texas, as Jim mentioned, was about 3 million barrels of 2011 production. And so those assets are either closed or in the process of closing. So some production from those assets was included in the first quarter, but it's fully baked and has been baked into the annual guidance.

Operator

Our next question comes from the line of Evan Calio with Morgan Stanley.

Evan Calio - Morgan Stanley, Research Division

On Algeria, Mozambique, lot's of my primary questions are answered. But I guess first, just kind of question on true up [ph] cost really appear to be easing. Now you're op reports updates showed significantly lower completion costs on some of your onshore U.S. plays. I'm surprised, one in the Haynesville. But are you seeing kind of a cost comments in kind of other oily plays in Eagleford, Wattenberg?

Charles A. Meloy

Well, in the areas where you have rig growth like Wattenberg and Maverick and probably up in the Bakken, you're still seeing price pressures. And the assets where we have, like the Bone Springs, Avalon, Haynesville and our other GNB, that type of asset, the -- we have some opportunity to reduce those costs. We're taking advantage of those opportunities, and we reflected those in the operating reports. I think you'll see continued pressure, downward pressure in those type of assets. I think there'll be regional differences in the really high plays where resources, both completion and other assets like trucks, et cetera, are very scarce right now and the demand is high so the prices are up there with them. But we're going to continue to work our areas. And I think we've established ourselves sort of the 800-pound gorilla in many cases in these plays, and our pace is what dictates the pace of the basin, and therefore, we have some pricing range.

James T. Hackett

And the completion and drilling efficiencies more than make up for these cost pressures that we see even in the hot areas, which is handy. So we're beating down the cost in other areas.

Evan Calio - Morgan Stanley, Research Division

That's good. I appreciate that. Just a brief follow up on Tronox, not to kind of beat a dead horse in here. Your statements are very helpful, but the loss contingency up in the last quarter, I just presumed that reflects current renegotiations of the plaintiffs. And kind of like exploration, this is some risk aversion of potential outcome based upon state-of-the-art discussions?

James T. Hackett

Let me see if I can cast it. First of all, I think we've done the right thing in the accounting guidelines and said exactly how we have to do that. It is the result of continued attempts to resolve the matter. But the matter is not resolved.

Evan Calio - Morgan Stanley, Research Division

And the trial date, mid-May, do you expect a 2-month-ish trial if you go down that route?

James T. Hackett

I think it could be longer. With a busy bankruptcy judge in New York, we may be limited to 2 or 3 days a week. So this could stretch on into August.

Evan Calio - Morgan Stanley, Research Division

Great. And maybe just one last question. Wattenberg, also operationally great here. But I mean, could you discuss any material constraints to growth or any bottlenecks related to either takeaway or processing capacity here, at least in 2012?

Charles A. Meloy

Well, it's a great asset, a growing asset and we've -- we really pushed up the volumes. Jim mentioned, I believe, it's over 80,000 barrels a day of volumes now. There's several things that we've undertaken to make sure we eliminate any constraints that we see or that are foreseeable, which include additional plant, processing plant called our Lancaster plant that Jim mentioned. We've also subscribed to some NGL takeaway capacity down to get product all the way down to Mont Belvieu, which would be beneficial for us. And aside from that, we're essentially just stepping up the rigs in concert with any constraints that we see with regard to land clearances or right-of-way clearances or permitting. And as those are overtaken, we continue to ramp up rigs. We originally anticipated ramping up to 7 rigs about year end, and we're already there. And so the process is working good, the machines start to spin well and you're seeing our volumes ramp up accordingly.

Operator

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

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

Real quickly over in the Utica. When you look at sort of the production composition or mix, does that create any anxieties with respect to ability to get production online and delivered over time due to high BTU content or liquids content? Or is that all been planned for ahead of time?

Charles A. Meloy

Dave, this is Chuck again. Actually, the things we're seeing is predominantly oil related. It's a liquid-rich environment, but most of this is actually oil. We do have liquids in our gas, and our midstream team is working through solutions to handle it. The volumes are not so great that we can't readily handle this and deliver to markets. And there is a -- there's an opportunity to use a current infrastructure to handle the volumes that we have. And so we're feeling very comfortable about the gas side of this and, of course, we can handle the oil easily and get it trucked to market. So we don't really foresee a big problem.

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

Okay, that's a helpful clarification. And then with respect to your comments earlier about being a little conservative with gas guidance and the performance you guys have seen today, can you talk a little bit about, is that potential gas that could be curtailed? Is that more driven with production growth from associated gas or production that's tied to traditional natural gas wells?

Charles A. Meloy

It's natural gas wells, dry gas wells. We're anticipating additional curtailments in some of the Northern Rockies production, CBM and those type of areas as well as the Marcellus, in our guidance.

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

Okay. And then just one clarification. I mean, with your guidance, it shows that kind of gas production is certainly tapered. Is there a point as you redirect activity towards more liquids-rich areas but that have decent associated gas content that we'll actually see an increase in gas production on a corporate level just to do associated gas production?

R. A. Walker

This is Al. Let me try to answer that. Probably one of the biggest variables we face as we provide guidance is what the outside operating properties are going to do. And I think, as you think about looking at us, we're pretty conservative on what we assume others will actually do. And consequently, as we move quarter-to-quarter, we ourselves are sometimes surprised by what our outside operator properties will do. And so consequently, our ability to true that up as we go through the year, to some extent is where that variable is coming from. And that's not as easy as you might imagine for us to predict this for own-operated properties.

Operator

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

John Malone - Global Hunter Securities, LLC, Research Division

Just a couple of quick international questions. On Golfinho, when do you expect to spud at Mozambique? What's the timing of it? And then this being, I believe, distinct from Prosperidade, so what's your idea of resources in that part, the northern part of area 1 resource potential?

Robert P. Daniels

Yes, John, this is Bob Daniels. Golfinho is actually spud. And so we figured it will be about a 60-day well, something like that. With the last couple of wells out here though, we've been really drilling them fast. I think our drilling group has just done a phenomenal job of understanding what they have to do to get these wells down. It is -- the objective of Golfinho is the same sand system that we see over at the Prosperidade complex up to the north and west of it. We see a potential that it could be an extension of that. But we also see a potential that it could be its own accumulation. And so that's what we need to get out there and test and see if we get -- if we have hydrocarbon there and then also what the pressures are and whether there may be a relationship between the 2. That will be followed up with Atum, which is very similar, testing in other sand system up in the north and west of the Prosperidade complex and then followed by Orca, which will be testing a lower sand package that we've seen some hydrocarbons in the Prosperidade complex beneath the thrust sheets. So we've got a very good exploratory program going to the north, and it should be back to back, Golfinho, Atum, Orca.

John Malone - Global Hunter Securities, LLC, Research Division

So just to clarify that. You're not seeing anything on the size that they would indicate? Do you think it's possible that this could be 50 miles away but still an extension of the bigger complex that you found so far in Golfinho?

Robert P. Daniels

That is a possibility. I don't think it's the most likely outcome, but it is a possibility. When you look at the -- all the data that we have in there and you look at the continuity of the sand packages, these are very, very significant sand packages, and seem to be very laterally continuous, which we've proved from our DSTs out there. So there is a possibility of that, but we think that the higher likelihood is that it's an independent accumulation.

John Malone - Global Hunter Securities, LLC, Research Division

Okay. And then just on Brazil, can you elaborate a little bit as to what the government is doing with the unitization, what is it going to take to get that sales process moving again?

Robert P. Daniels

Yes, this is Bob again. On Brazil, we got a couple of wells that we've drilled and that we're going to drill this year. We've got another Wahoo well to drill and a couple up in the Espirito Santo basin. And the Itaipu is the area that they're talking about unitization. We've got a couple of wells in it. We're looking at drilling 1/3 and potentially a DST on that. And that is potentially in communication with their Whale Park area to the north and west of it, which is on production in the pre-salt. And so I'll let Bob Gwin talk about the implications of that.

Robert G. Gwin

The unitization discussions, obviously, are being handled by the operators, so we defer to them on questions around the unitization. From our perspective, unitization could change expectations around the asset with regard to capital or cash flow production. Obviously, the timing of each of those things, those have effects, potentially, we don't know. But potentially material effects on the valuation of the asset. And accordingly, we need to do the analysis and let the process run its course before we're able to assess how it might affect our views on valuation or the timing of our process. Obviously, not only do we need to do such analysis but potential purchasers would need to do that as well, work it into their cases as they, we would expect, would then rebid.

Operator

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

Robert L. Christensen - The Buckingham Research Group Incorporated

I'd like to ask a little bit more about the Utica. And I know it's early days on wells, 30 days on your best well out there. But how is the pressure holding up there? Is -- or it seems to me we're seeing declines start to slow in that well, good thing.

Robert P. Daniels

Bob, this is Bob Daniels. We like what we're seeing to date, but it's very, very early. We've got a couple -- 3 wells on production now, the best one was the third of that group. We think that we're going to have to evaluate longer-term to see -- to answer the question that you're asking as to how we're going to hold up. And then we also think that at some point, because of the liquids, high liquids content that we have out here, that we may have to put artificial lift on these and really see what they can deliver. Because, of course, the first 2 had fairly low gas content relative to some of the others in the area, very high oil content. And so to really get a good sense of what they will deliver ultimately, we may have to have artificial lift and just watch them for a while. Of course we've got a rig out there. We're continuing to drill. We've got our fourth well that we're completing, the fifth is being drilled. And we will continue with that program typical of what we do in these shales is pilot programs around our acreage position and put them online and evaluate the results before we decide where to kick off the development program if it's called for.

Robert L. Christensen - The Buckingham Research Group Incorporated

So you kind of answered my question because I didn't see enough gas for gas lift. I mean, are you -- is the gas-oil ratio the right ratio for potential gas oil lift? Is it sufficient enough at this point?

Robert P. Daniels

Well, the first 2 wells had about 1,000 GOR. It's what we're seeing to date. And that would not be enough at this point as we move farther to the south and east, you get higher gas content and more energy from the gas. What we're really looking at is what are the economics of the oil versus liquids-rich gas versus the dry gas. And that's what we're paying attention to is to how these wells are going to perform and then what it means in the way of returns to us.

Robert L. Christensen - The Buckingham Research Group Incorporated

Has there been any change after 3 wells, now a fourth, in your completion design? Are you doing them all the same at the moment? When would you vary up that?

Robert P. Daniels

Yes, we try to learn from everyone of them. The first well was our shortest lateral. We've increased the length of our laterals. And then we've been tweaking the numbers and types of frac stages we've been putting on in each one of those, seeing how they respond. The most recent well will be our longest lateral. The fifth well that we've drilled. So we're just testing all the different ideas out there as we move geographically to see where the best areas are and then what the best way to get the hydrocarbons out of the rock is.

Robert L. Christensen - The Buckingham Research Group Incorporated

One final, when you say geographically, I can't really follow the dots on the map. But how much area has been defined by the 5 dots on the map of the 394,000 acres you have?

Robert P. Daniels

That's a very smaller -- actually, the first 2 are on the same pad. The third well was a step up down to the south and east a little bit, about 3 or 4 miles. And then the fourth well is a little bit farther to the southwest. We haven't even stepped up to the north some significant distance. So that will come very shortly as we get past the winter time where we're kind of restricted on where we could build locations and move equipment.

Operator

Our next question comes from the line of Ross Payne with Wells Fargo.

S. Ross Payne - Wells Fargo Securities, LLC, Research Division

Yes, I was just curious if we could get an update on the Macondo environmental issues still outstanding.

Robert K. Reeves

Ross, this is Bobby Reeves. You remember that as part of our settlement with BP, there are certain indemnities that are covered by our agreement there. The only thing that's outstanding is any fines and penalties. Certainly, any natural resource damages, that's BP's responsibility. But with respect to Clean Water Act fines, there's really been no activity there. We still believe we have the right case there that we're not culpable. And since it's a fault-based type of statutory regime, any fines or penalties that could be assessed against us should not be material. There's no trial date set on this. This could be around for a while. It may not be resolved for some time.

Operator

Our next question comes from the line of Eliot Javanmardi with Capital One Southcoast.

Eliot Javanmardi - Capital One Southcoast, Inc., Research Division

Just a quick question regarding the East Texas production, I know at the Analyst Day you had mentioned or actually listed in your literature that you're at about 35,000 barrels equivalent a day net. If you could provide an update as to where you stand on that production figure now, that would be great. And a follow-up to that is realizing that the area in the East Texas horizontal was localized and you're drilling structural highs, do you see a potential to -- are you still seeing any potential to nudge off the number of drill sites there? Or are you in a situation now that the development teams feel like you kind of tapped out in that regard?

R. A. Walker

This is Al Walker. Let me try to address the question on what we're doing in East Texas. I think that's an area where a lot of our acreage today is HBP. But as we understand the play better, we're actually going out and picking up some additional leases. So I'm afraid, for this call, we really don't want to give you a lot of additional data beyond what we gave you in March.

Operator

Our next question comes from the line of Charles Meade with Johnson Rice.

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

I actually had 2 questions first. Touching on the Wattenberg, I think an earlier person asked about how the logistics are going there. I was wondering if you could talk about the other side of that, which would be the results you're getting out of there. And I know that you guys gave us a lot of detail in March, but also that there's kind of new things being turned over there all the time. So I was wondering if you could give us an update on what you're seeing kind of from the reservoir and the different horizons there.

Charles A. Meloy

Charles, we're continuing to see just outstanding results from Wattenberg. Our productions climbed up, that's how the 80,000 barrels happened. It's over 10,000 barrels a day up from -- when we came out with the Wattenberg discussion 6 months or so ago. So it's increasing very quickly. We're drilling both Niobrara and Codell wells, and they're both performing extraordinarily well. And I think the coolest thing to me is we're seeing great results across the field area, the field area proper, from east to west to north to south, and our neighbors are having great results. So you're -- this thing is working. It's working in a big way, and we're pushing up the volumes. And they have good economics, they have great wellhead realizations. And we can do it at very low cost, so it would -- the equation is about as good as it gets.

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

Got it. And then shifting to the Gulf of Mexico. The -- I think you said the Spartacus is spud. And I saw the lease on the cartoon, that's just going to the Pliocene. So I was wondering when -- what's your expectation on how many days it's going to take to drill and when should we kind of expect to see something there, in the way of results?

Robert P. Daniels

Yes, Charles, Bob Daniels again. They -- it has spud and making good progress on it. These are not overly complicated wells. And so I would think within 60 days, we should have results on that well and can -- and talk about it.

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

And will Phobos be an immediate follow-up with the same rig or is that later?

Robert P. Daniels

No, it won't be. In Phobos, it would be a much more complicated well and that we have dual objectives there with the Plio-Pleistocene like Lucius, and then we have a lower tertiary objective. So it's going to be a much more complicated well and a longer time period. It'll be later in the year before we spud that.

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

And it might be a 2013 result then to get to the Wilcox?

Robert P. Daniels

Very possible.

John M. Colglazier

I want to thank everyone on the call, and we look forward to visiting with you at the latest at the second quarter earnings call, and have a great day.

Operator

And 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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